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Gas and Electric Infrastructure Interdependency Analysis

Prepared for:

The Midwest Independent Transmission System Operator

Gregory L. Peters President, EnVision Energy Solutions (804) 378-0770 February 22, 2012

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Disclaimer: This report was prepared by Gregory L. Peters, Principal Consultant, dba EnVision Energy Solutions for the benefit of the Midwest Independent Transmission System Operator (“MISO”). This work involves detailed analyses of interstate pipeline daily flow and capacity data and data obtained and compiled by an independent third party. 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. `

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Summary of Assignment…………………………………………………………………………………………………7 Executive Summary………….……………………………………….…………………………………………..8

Supply and Infrastructure Outlook to 2030………………………………………………………13

Factors Supporting Gas Supply Growth...……………………………………………………......19 Enhancements in Horizontal Drilling and Hydraulic Fracturing …..……………………19 Shale Gas Size and Growth……………………………………………………………………………….21 Shale Gas Geology……………………………………………………………………………………………26 Natural Gas Demand……………………………………………………………………………….……….30 Impacts on Natural Gas Infrastructures………………………….………………………………..34

Pipeline Infrastructure in the Midwest…………………………………………………………....41

Natural Gas Pipelines in the MISO Region…………………………………………………….….41 Transportation of Natural Gas Supplies...…………………………………………………………42 Canadian Natural Gas Imports to the Midwest Region…………………………………….44 Intrastate and LDC “Hub” Companies inside the MISO Region…………………………45 Major Interstate Pipelines into the MISO Region..……………………………………………47

Pipeline Capacity Analysis………………………………………………………………………………..…..50 Understanding How Capacity is Measured…………………………………………………..….50 Overall Pipeline System Configuration……………………………………………..………….....50

Overview of Pipeline Utilization……………………………………………………………50 Utilization Rates……………………………………………………………………………………51 Integration of Storage Capacity….............................................................51 Varying Rates of Utilization………………………………………………………....………52 Measures of Pipeline Utilization…………………………………………………………..52

Understanding How Capacity is Measured in this Analysis..…………………………....53 Load Factor Analysis………………………………………………………………………………...….….53 Daily Insufficiency Analysis (“DIA”)…………………………………………………………….…….58

Pipeline Infrastructure and Investment Costs………………………………….……..….…….72 MISO-Identified Pipelines Investment Costs…………………………………………….……….72 Natural Gas Industry Infrastructure Investment Costs.....……………………….…..…...76

Natural Gas Storage Serving the MISO Region………………………………………..………..80 New Storage in MISO Region since 2000………………………………………………..……..….82

Future Gas Storage Development…………………………………………………………..……..….84

Future MISO Region Infrastructure Expansion……………………………………….……..….85

Table of Contents

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Major Issues Facing Infrastructure Development……………………………………..90

Development Cost Uncertainty………………………………………………………………………...90 Timing Issues………………………………………………………………………………..……………….….91 Capital Cost Recovery Uncertainty…………………………………………………………………….91 Less Spare Flexibility and Shorter-Term Contracts…………………………………………....91 Other Uncertainties…………………………………………………………………………………………..92

Contract Issues Impacting Capacity….………………………………………………………………….93

Conclusion….………………………………………………………………………….………………………………….95

Lists of Figures Figure 1: U.S. Production per Well & Total Gas Wells Figure 2: U.S. Natural Gas Prices 1990 – 2012 Figure 3: Impacts of 2008 Pipeline Capacity Expansion on Regional Prices and Average Basis Figure 4: INGAA Projected Gas Supply Growth Figure 5: Henry Hub Price History Figure 6: U.S. Gas Production History Figure 7: U.S. Gas Rig Count by Type Figure 8: North American Major Shale Production Figure 9: EIA Lower-48 Shale Play Map Figure 10: North American Shale Production Figure 11: Decline Curves for Selected Shales Figure 12: Comparative Spot Price Movements in Natural Gas and NGLs Figure 13: Trend: Oil & Liquids are Driving the Gas Market Figure 14: U.S. Natural Gas Consumption: Industrial vs. Electric Power Sectors Figure 15: Natural Gas Growth in Power Generation Figure 16: U.S. and Canadian Gas Consumption Figure 17: Historic “Longitudinal” Flow Patterns Figure 18: Today’s Developing “Grid” Flow Patterns Figure 19: Market Responsive Infrastructure Additions Figure 20: Impact of Emerging Shales and Conventional Declines to Pipelines Figure 21: World LNG Estimated January 2012 Landed Prices Figure 22: Generalize Natural Gas Pipeline Capacity Design Schematic Figure 23: Potential Marcellus Pipeline Expansions Figure 24: Regional Gas Infrastructure Capital Requirements for 2011 to 2035 Figure 25: Regional Gas Infrastructure Capital Requirements for 2011 to 2020 Figure 26: Expenditures for New Gas Storage Capacity Figure 27: U.S. Natural Gas Storage Facilities Figure 28: Underground Storage Comparison

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Figure 29: Certified Storage Projects Since 2000 Figure 30: Bison Extension Figure 31: New Supply Sources from Rockies (WBIP) and Bakken Region Figure 32: Spectra Energy (TETCO) Perspective on MISO Region Opportunities Figure 33: Wabash Gas Storage Project Figure 34: NNG Northern Lights Project Figure 35: Vector Expansion Capabilities

List of Tables TABLE 1: MISO Region LDC and Intrastate Pipelines TABLE 2: MISO Region Major Interstate Pipelines TABLE 3: Pipeline Flow Capacities and Relative Sizes TABLE 4: Pipeline Load Factors TABLE 5: Daily Insufficiency Analysis - Unavailable Capacity for CTs and CCs TABLE 6: Estimate for Initial Cost on Site of Compression TABLE 7: Estimated Construction Costs for Most MISO Units TABLE 8: Comparison of INGAA Midwest Region 2020 and 2035 Infrastructure Costs

TABLE 9: MISO Region Underground Storage Companies

Definitions: “MISO-identified facilities or units” or “facilities or units” are hypothetically-possible natural gas-fired generation facilities. “MISO-identified pipelines” are pipelines that have the facilities or units on them.

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Overview of MISO Region Major Pipelines

Schematic of the U.S. Natural Gas Infrastructure

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This purpose of this report is to review and analyze current and future natural gas pipelines, storage facilities and related infrastructure, current and potential, for natural-gas fired electric power generation over a 20 year horizon in the MISO region. The specific tasks are as follows: Task 1: Provide Baseline level information for the MISO over 20 year (2011 – 2030) time

horizon:

Describe sources for natural gas supply, both US and Canada;

Description of current natural gas pipelines in Midwest;

Description of future expansion of natural gas pipelines in Midwest;

Maximum total capacity of existing pipeline infrastructure by Firm or Interruptible for pipelines;

Usage of natural gas by combined cycle and combustion turbines. Task 2: Identify available capacity on the existing pipeline infrastructure. Task 3: Provide an overview of how much additional electric generation capacity can be built

using existing infrastructure. Task 4: Provide and overview of how much additional electric generation capacity can be built

assuming future pipeline additions as planned by the major pipeline companies. Task 5: Assess the additional pipeline infrastructure and investment costs needed to provide

adequate natural gas for an electric power plant expansion plan for the next 20 years. Task 6: Perform an analysis of gas-fired capacity additions that can be supported based on

defined locations provided by MISO. The defined areas are associated with coal capacity reductions or retirements that may be driven by the new EPA regulations.

Task 7: Identify major gas storage locations and capacity; and, how those locations tie into the

interstate gas pipeline infrastructure in the Midwest. Task 8: Survey MISO-identified pipelines, that may have hypothetically-possible natural gas-

fired generation, issues related to capacity, operating conditions, generation support capabilities, storage, expansion plans and construction costs to site power generation facilities.

Task 9: Provide a written report outlining results and findings.

Summary of Assignment

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SUPPLY FACTORS IMPACTING NEW U.S. PIPELINE CAPACITY The Midwest and the MISO region has become a crossroads in the North American natural gas market. There is an extensive network of over 25 pipelines that transport natural gas from nearly all major supply basins in North America to and around the MISO region. However, natural gas flows in the MISO region have seen significant changes lately. Combined with shale gas developments nationwide, pipeline infrastructure projects have created a major paradigm shift and domino-effect of altering traditional North American natural gas market flow patterns. For example, the traditional south to north pipeline capacity (Gulf and southwest gas) and north to south pipeline follows (Canadian gas) have been altered by the Rockies Express Pipeline (“REX”) and shale gas developments. The pipeline corridors with the most significant volume increases include the REX corridor from Wyoming through the mid-continent to the U.S. northeast; the Appalachian Basin to the Northeast; the east Texas to northern Louisiana corridor to the Midwest central and northeast regions; western Canada to the Midwest and Chicago corridor, and along the Gulf Coast into Florida. All these volume shifts are “supply push” increases (with the exception of Florida which is driven by “demand pull”). The “supply push” is a direct result of the abundance of U.S. and Canadian natural gas in North America. In fact, gas supply is in surplus to demand. Prices that were expected to be high and volatile are now expected to be moderate and relatively stable. Shale gas development has turned the economics of drilling for gas on its head. Shale gas production is making a significant contribution to the U.S. supply portfolio and will continue to grow for an extended period of time; potentially doubling over the next 20 years.

New pipeline infrastructure projects are concentrated in the expanding shale-rich oil, natural gas liquids (NGLs) and natural gas production areas throughout the United States and Canada. This layer of infrastructure is primarily providing access to local markets and interconnections through the interstate natural gas pipeline network. This trend will continue as new production opportunities develop in areas that have been overlooked for re-work, undiscovered or become economical. In many of the most popular shale basins, prices and production are being pressured by a lack of pipeline capacity. “Take-away” capacity from the Permian basin shale region in west Texas is constrained as is the Eagle Ford shale region in south central Texas. The Marcellus shale region in the Northeast is highly constrained when it comes to moving natural gas liquids (“NGLs”) to market. The clear majority of all new gas pipeline projects are being driven by shale gas projects, as producers tap into oil and NGL-rich shales and work to remain financially viable in light of lower natural gas prices.

Executive Summary

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DEMAND FACTORS IMPACTING U.S. PIPELINE CAPACITY Natural gas pipeline companies are also striving to achieve financial stability and thus, interstate pipeline project sponsors need shippers’ willingness to sign long‐term contracts for natural gas transportation. New pipelines are not built on the assumption that there will be a future market for natural gas transportation but on shippers’ commitments. The shippers’ commitments are needed to raise capital for a project to demonstrate a long-term revenue stream. Since regulated recovery of capital is usually for longer terms, pipeline and storage infrastructure developers are uncertain of recovering new capital investments in today’s environment. There are a plethora of rate issues, fixed-cost recovery, contract term and right of first refusal (ROFR) issues and others that beg the question, “Who is going to pay for it?” For this reason, there is a growing sentiment in the pipeline industry that pipeline expansions will be driven by regional projects and not by the multi-billion dollar, long-distance “bullet” projects. In lieu of constructing costly, large-scale “greenfield” pipelines, pipelines are now looking, wherever optimal, at less capital intensive means such as looping existing long-lines or using additional compression (or combination of the two) as the means to offer incremental capacity. Local (gas) Distribution Companies (“LDCs”) that have retreated to “short-term” contracting (3, 5, 7 years versus the 15 to 20 year contracts of old which provided cost-recovery certainties to pipelines) may be particularly fearful of entering into long-term contracts out of concern that regulators may find longer term contracts “imprudent” at a time when their transportation infrastructure and supply options are changing rapidly. This same concern is a major problem for regulated electric utilities as well. This type of regulatory uncertainty is a major impediment to pipeline and storage infrastructure financing and is a common gas and electric interdependency issue. An approach to incentivize pipelines and power generators, in particular, is needed to move forward with greater certainty about regulated cost recovery. Otherwise, there may be increased contracting tension for capacity between traditional LDCs and electric power generators unless pipelines can be flexible in their operations and services in “creating” capacity to support the needs of power generators. Consumer natural gas consumption growth has an important, although relatively smaller, influence on natural gas infrastructure development in the Midwest compared to electric power generation. Incremental pipeline infrastructure and innovative rates and services will be needed to primarily serve growth in power generation, because spare seasonal pipeline capacity may not be available. Pipelines also need to “re-think” the flexibility of their operations to accommodate power generation demand if customers are reluctant to commit to long-term contracts to support the financial burdens of infrastructure expansion.

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OTHER SOURCES OF PIPELINE CAPACITY FOR POWER GENERATORS

Marketers can also play a key role in providing gas delivery capacity to MISO region electric power producers. While LDCs, gas marketers/producers and some electric utilities hold a majority of capacity on the pipelines, they are able to assign or release long-term capacity to companies that require capacity for future electric power generation projects. Storage is another form of pipeline capacity. However, storage deliverability in the MISO region could face an infrastructure constraint because of the geology for storage in the region. Natural gas-fired power generation relies on high-deliverability storage. In the MISO region, storage is limited to aquifer and depleted oil/gas reservoirs that have seasonal injection and withdrawal cycles versus salt cavern storage which has high-deliverability cycling. Pipelines can have some level of flexibility on injection and withdrawals within a season, but generally, the seasonal schedules must abide by fairly strict physical injection and withdrawal requirements and by tariff conditions. Another alternative may be additional above-ground LNG facilities. Pipelines and storage operators need to “rethink” their operations to provide flexibility to power generators. On the other hand, power generators need to be creative in their use of pipeline capacity release opportunities, other pipeline offerings such as parking and lending services, as well as improve operations communication and coordination with the pipelines’ control operators to meet summer and winter requirements.

AVAILABLE PIPELINE CAPACITY IN THE MISO REGION All of the above factors impact the availability of capacity in the MISO region through possible new pipeline infrastructure development, or by obtaining existing pipeline capacity through new pipeline service offerings or through other third party holders of capacity. As discussed in detail in this Analysis, current pipeline capacity to and in the MISO region is a “mixed” bag. Three (3) large interstate pipelines have already seen a change in available capacity because of the REX pipeline. Of the twenty-five (25) pipeline segments that were analyzed, the available capacity results varied considerably; from no available capacity to plentiful capacity availability. It was confirmed with the MISO-identified pipelines, that if the lateral construction modifications were made, the facilities would receive their required natural gas to operate on a “year-round” basis for CCs as well as CTs if firm transportation is contracted, with three exceptions. For example, Pipeline A does not have any available firm transportation or storage even with the construction options offered. Pipeline A’s solution is dependent upon Pipeline B having enough capacity. Pipeline B does not have any available firm transportation or storage. Pipeline B would require extensive looping and/or addition of compression to serve both the Pipeline A facilities as well as the facilities its system.

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In Pipeline C‘s case, it confirmed that it has sufficient firm capacity for a CC on a year-round basis. However, to ensure 100% firm delivery to two CTs year-round, Pipeline C has also confirmed that there would be additional construction costs above the lateral costs indicated in their Survey response. Where the CTs are located, Pipeline C is restricted during the Winter Period and a firm commitment from Pipeline C would require line upgrades to guarantee firm deliveries, according to Pipeline C. Construction costs for the types of upgrades needed for Pipelines A, B, and C would require additional compression and looping and other asset upgrades or additions. The exact costs for these projects are unknown at this juncture. However, similar projects’ construction costs have been in the hundreds of millions dollars. As for new pipeline infrastructure, the construction costs for the MISO-identified pipelines’ laterals to the MISO-identified facilities are estimated to be in a range from $921 million to $1,098 million for an average cost of $1,009 million. These estimates exclude any mainline construction costs. This number should actually be considered to be on the “low” side as the costs of additional mainline looping and compression would be in addition to the lateral upgrades on the pipelines that are included in the estimate above. This actual costs associated with these types of mainline projects could easily be in the hundreds of millions of dollars. These pipelines have indicated that these upgrades would be considered major projects that would require extensive analyses before precise cost estimates could be determined. At the Pipeline Z’s Customer Meeting in 2011, Pipeline Z revealed that it is studying the potential to extend its pipeline and it would cost approximately $450 to $600 million depending on volume. One can only imagine that costs to accommodate firm deliveries on the other pipelines that need mainline upgrades could easily top $2.0 Billion above the lateral costs. Some pipelines basically do not have available capacity where it is needed. Six (6) out of 32 MISO-identified facilities, to operate year-round, would require extensive mainline compression and looping that can possibly be as much as another $2 billion dollars. Two (2) pipelines are “on the edge” of having sufficient capacity, Pipeline D and E. Pipeline D is completely filled and firm capacity to the CT for service on a year-round basis is available, but, according to their executives, would require not only the construction cost upgrades, but a basic re-structuring of operations, if not additional, “unstated” costs. Three (3) additional pipelines (without MISO-identified facilities) do not have sufficient capacity to deliver the required gas with the required reliability for one CT or CC year-round. Producers and pipelines are exploring ways to move Marcellus shale gas “westward” into the MISO region, as was recently announced with the AEP-Texas Eastern-Chesapeake Energy “OPEN” project. Moving natural gas “westward” would require additional infrastructure and rate and regulatory action to accommodate the “backhaul” impacts on the MISO-region pipelines and the need for additional gas storage to support bi-directional and other “mixing-bowl” flow patterns that comes with the MISO region being a crossroads in the North American natural gas market.

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Each pipeline is unique in its operating characteristics for various engineering, physical configuration and operational flexibility reasons. Some pipelines stand-out as problematic for capacity availability as noted above. Others must “re-think” the flexibility of their operations to accommodate power generation demand. However, aside from the issues above, 26 or perhaps 24 (with consideration to the Pipeline D and Pipeline E facilities) of the 32 MISO-identified facilities should have sufficient capacity for normal operations. CONCLUSION Generally, almost all the pipelines will have to be increasingly operationally flexible to provide delivery service to the MISO power generators. Out of 25 pipelines, 3 do not have sufficient capacity and 2 additional pipelines are questionable for MISO-identified units. Three (3) others in the MISO region that do not have “MISO-identified units” do not have enough capacity to support a year-round CT or CC. It is conceivable, based on recent pipeline expansion projects, that the cost to accommodate the needed lateral and mainline expansion projects in the MISO region and the need for additional gas storage and LNG could easily exceed $3.0 Billion. Current growth in the shale gas basins, from the Bakken to the Marcellus, requires infrastructure outlets sooner than later because of the protracted supply “bubble” that is expected over the next three years, if not longer. Another key question is how long will it take, from project conception through the Open Season and regulatory approval process before construction begins? The issues discussed herein address the types of infrastructure projects MISO needs through 2030 as the supply “bubble” comes into equilibrium with forecasted power generation demand growth. In addition to physical capacity construction, the increasing gas and electric infrastructure interdependency requires an improved collaborative process between pipelines, power generators and regulators to coordinate natural gas infrastructure projects. Regulators will need to be flexible in fast-tracking pipeline construction projects to ensure that coal- to gas- fired generation, gas supply growth and infrastructure investment move in phase together. Meeting infrastructure needs requires improved regulatory certainty from state and federal regulators and agencies, particularly the EPA. Improved regulatory coordination and certainty, commitment and the will to incentivize pipelines and power generators are needed to move forward in coordinating the strengthening of the gas and electric power infrastructure.

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Overall supply growth in the U.S. has been remarkable in the past few years. Due to the vast size of the shale gas resource and the high reliability of shale gas production, the overall supply-demand balance has the potential to be synchronized for the foreseeable future, even as demand grows. The bulk of this change is attributable to prolific supplies of unconventional natural gas which can now be produced economically. Unconventional natural gas includes shale gas, tight sands, coalbed methane, deep gas, and gas produced in association with shale oil. Before the advent of significant unconventional gas production, natural gas development was susceptible to booms and busts. Investment in both production and usage seesawed on the market’s perception of future prices. This perception has been driven by uncertainty around the availability of supply to meet demand, in both the short and long terms. The investment cycle for supply was frequently out of phase with demand, due to the uncertainty of the large investment required for exploration or for LNG regasification (on the supply side) and for power plants and other large users impacted by economic cycles (on the demand side). In between supply and demand are pipelines, large-scale investment in many individual cases has suffered from underutilization or become a bottleneck as a result of uncoordinated cycles of supply and demand investment. In the MISO service area there are a number of examples of this situation that exist today that this analysis will identify. These factors create a dynamic of price volatility related to the value of capacity. The volatility itself affects investment decisions, creating a feedback loop of uncertainty. The obvious fact is that infrastructure development is driven by gas supply and gas demand issues and an array of restrictive factors ranging from environmental and governmental action considerations to long-term returns on capital investments. Until the mid 2000s, demand was the dominate macroeconomic driver as the U.S. economy enjoyed growth rates that enticed suppliers to seek new supplies in the face of diminishing conventional gas supplies. The dramatic gas production drop from 1970 to 1984 and the continuous, steady decline in production per well per day convinced many that natural gas production had “seen better days”. As shown below in Figure 1: U.S. Production per Well & Total Gas Wells, this trend, coupled with the ever-increasing number of wells drilled to squeeze out more production reinforced electric power executives to retrench in their beliefs that were grounded in the “natural gas shortage” of the late 1970’s, that natural gas was “unreliable”. Natural gas demand suffered through the 1980s and 1990s as the industry struggled with the persistent supply issue. The one major trend that was unforeseen at that time was the development of the notorious “gas bubble” in the late 1980s and early 1990s as a

Supply and Infrastructure Outlook to 2030

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U.S. Production per Well & Total Gas Wells

Past Concerns about Supply

Figure 1: U.S. Production per Well & Total Gas Wells

result of the regulatory lag from the “gas shortages” of the late 1970s (winter of 1976/77 was colder than normal and wellhead price controls and regulation kept much needed supplies out of the interstate market) which lead to the phase-in of well-head price deregulation through the 1980s and the drive by state regulatory agencies to essentially “force” LDCs into long-term gas supply contracts. With long-term supply contracts in hand, producers were encouraged and gas production increased, slowing the dramatic drop and rate of decline in production by 1986. Fresh off the success found in well-head price deregulation, the concept of “deregulation” in the interstate pipeline markets was building and eventually lead to today’s “open access” environment. One major consequence, however was years of litigation regarding the abrogation of the long-term contracts and the fate of hundreds of millions of dollars in gas supply-take-or-pay contracts and production growth. The ensuing “gas bubble” period developed in the late 1980s through the 1990s when national interstate natural gas prices were in the $1.50/Dth to $2.50/Dth range. The one major problem with lower prices for LDCs was their long-term contracts. Regulatory authorities began to penalize LDCs for being “imprudent” by holding long-term, higher-priced supply when short-term wholesale prices had plummeted. So there was also a move by LDCs to only enter into short-term (one year or less, but hardly ever more than three years) gas supply contracts and typically three (3), five (5) and 7 year firm (FT) transportation agreements. During a period of high alternative energy prices, the temptingly low prices of natural gas again began to drive demand. By the end of the 1990s, natural gas supplied about one-half of the nation's energy needs. Industry watchers noted several trends indicating increased reliance on natural gas. For example, in 1990, natural gas was used in 59 percent of new

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single-family home construction, up from 43 percent in 1985. By 1999, it was up to 70 percent. According to the American Gas Association (“AGA”), there were more than 1.3 million miles of natural gas transmission and distribution pipelines traversing the nation, delivering supplies to 60 million commercial and residential customers. The latter 1990s saw many nuclear power plants and coal-burning power facilities shut down or convert to natural gas facilities. This trend was particularly true in the eastern half of the United States, in highly-industrialized areas. From 1990 until 2011 natural gas futures prices averaged $4.09/Dth reaching an historical high of $15.38/Dth in December of 2005 and a record low of $1.05/Dth in January of 1992.1

U.S. Natural Gas Prices 1990 - 2012

Figure 2: U.S. Natural Gas Prices 1990 - 2012 During the 2000s, natural gas experienced consumption growth, but also the growing pains of “price spurts”. Price uncertainty then became the new resistance point for many traditional electric power generators. By the mid-2000s supply and price uncertainty prevailed as the natural gas industry went through a period of dramatic upheavals that resulted from trading improprieties and scandal, asset liquidations, a “back-to basics” movement by the interstate pipelines and a general rush to the non-trading exit doors. This tumultuous period is partly reflected in the price volatility as shown in Figure 2: U.S. Natural Gas Prices 1990 – 2012. The supply paradigm shift due to the quiet successes of tapping into unconventional shale gas and oil, tight and deep reservoirs with new drilling technologies, came to light with a reversal of declining production in mid-2008. Also, this shift from offshore to onshore production sources has reduced the dependency for Gulf Coast gas supplies. At the time of Hurricane

1 TradingEconomics.com

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Rita, the Gulf Coast supplied about 20% of total U.S. gas supply. Today is a little more than half that and continues to decrease. While the unfortunate state of the U.S. economy has temporarily dampened demand, the dependability of shale gas production has the potential to improve the phase alignment between supply and demand, which has lowered price volatility. As long as commodity prices can be sustained at levels that incent drilling and development, yet remain competitive with the price of alternate fuels, the vast size of the shale gas resources will support a much larger demand level than has ever been seen in North America. The continual expansion of the pipeline grid to deliver new shale supplies continues to impact the value of capacity, otherwise known as the locational basis differential. The locational basis differential is a measure of the difference in the price of natural gas between two geographic locations. A high basis price between the two locations indicates that the transportation capacity is highly utilized and the path is becoming constrained, such as in the case of the New England markets during extreme cold temperature conditions. If the basis differential is high enough and occurs over a long enough period, it provides justification for the shipper to purchase additional pipeline capacity and to signal to the Federal Regulatory Commission (“FERC”) that there is a need for additional capacity. As seen in Figure 3, Impacts of 2008 Pipeline Capacity Expansion on Regional Prices and Average Basis, since the Rocky Mountains Express pipeline (“REX”) pipeline got up to full capacity operations in January 2009, basis differentials from the Henry Hub have dropped to Chicago and to the Appalachian-based pipelines like Columbia Gas Transmission. While the basis price has weakened somewhat in the main MISO operating areas to this point, the largest basis price percentage decreases have occurred east of the MISO region.

Impacts of 2008 Pipeline Capacity Expansion on Regional

Prices and Average Basis

Figure 3: Impacts of 2008 Pipeline Capacity Expansion on Regional Prices and Average Basis

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It is expected that gas production will continue to grow steadily throughout the forecast period. The Interstate Natural Gas Association of America’s (“INGAA’s”) forecast for production, based on their Spring 2011 Reference Case, is shown in Figure 4: INGAA Projected Gas Supply Growth. U.S. and Canadian natural gas supplies are projected to grow by 38 Bcf/d from about 75 Bcf/d in 2010 to about 113 Bcf/d in 2035, adequate to meet expanded demand projections in 2035 of 109 Bcf/d. Unconventional natural gas supplies account for all of the incremental supply as production from conventional areas decline. Unconventional supplies (shale, coal bed methane and tight gas plays) will account for approximately two‐thirds of the total gas supply mix in 2035. 2 This is consistent with Navigant’s Spring 2011 Reference Case which projects that North American-produced supply will be 105 Bcf/d by the year 2040.3

INGAA Projected Gas Supply Growth

Figure 4: INGAA Projected Gas Supply Growth

The U.S. once again has reclaimed its position as “Number 1” in gas production, outpacing Russia as the world’s largest gas producer thanks to a dramatic increase in shale gas production. With this moderated and controlled supply growth, demand and pipeline investment are expected to grow in a measured fashion, with price volatility relatively limited. This should tend towards creating a healthy, stable, long-term market for natural gas. The vast majority of production growth will be driven by unconventional gas development, as opposed to conventional gas, which is in decline. Current U.S. and Canadian gas production originates from over 300 trillion cubic feet (Tcf) of proven gas reserves. The North American natural gas resource base is estimated to total almost 4,000 Tcf4 when adding unproved

2 North American Natural Gas Midstream Infrastructure Through 2035: A Secure Energy Future - Updated Supply‐Demand Outlook, June 28, 2011, prepared by ICF International for the INGAA foundation. 3 U.S. Natural Gas and the Role of Shale Gas, Questar Pipeline Company 2011 Customer Meeting Park City, Utah presented by Navigant Consulting, February 28, 2011. 4 Ibid.

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resources to discovered‐but undeveloped gas resources. That amount can supply U.S. and Canadian gas markets for about 150 years at current consumption levels. The Navigant study assumes gas supply development will continue at recently observed activity levels, and that there will be no new significant or special production restrictions. By comparison, The Energy Information Administration (EIA), in their 2011 Annual Energy Outlook estimates that the U.S. possesses 2,543 Tcf (U.S. only – no Canadian resources included) of potential natural gas resources.5 Shale gas is the largest contributor to production growth, while production from tight sands, coalbed methane deposits, and offshore waters remains stable. Production from coalbeds and tight sands does not contribute to total production growth in the EIA’s AEO2011 Reference Case but does remain an important source of natural gas, accounting for 29 to 40 percent of total production from 2009 to 2035. Shale gas makes up 47 percent of total U.S. production in 2035, nearly triple its 16 percent share in 2009. Natural gas from shale resources, considered uneconomical before 2006, accounts for 827 Tcf of this resource estimate, more than double the estimate published last year. At the 2010 rate of U.S. consumption (about 24.1 Tcf/yr), 2,543 Tcf of natural gas is enough to supply the U.S. for more than 100 years. The EIA 2011 Annual Energy Outlook reports that shale gas resource and production estimates increased significantly between the 2010 and 2011 and are likely to increase in the future.6 The increase in natural gas production from 2009 to 2035 in the AEO2011 EIA Reference case results primarily from continued exploration and development of shale gas resources. For the purposes of comparison, in 2008, Navigant wrote the “North American Natural Gas Supply Assessment” for the American Clean Skies Foundation. This study concentrated on shale gas as evaluated according to producer reports collected by Navigant. The resulting total supply estimate was 2,247 Tcf, including 842 Tcf of shale gas. This would have been 118 years of production at 2007 levels.7 Plans to develop Alaskan frontier gas, for which the Denali Pipeline and the Alaska Pipeline Project are designed, are hampered by the high cost of those projects relative to shale gas opportunities closer to markets. After years of negotiations and debate, the two pipeline projects proposing to deliver natural gas from Alaska's North Slope to the lower-48 States have run into many obstacles. The Alaska Pipeline Project, footed by TransCanada and Exxon Mobil continues to advance through economic, regulatory and political hurdles while the Denali Pipeline, a joint venture backed by ConocoPhillips and BP, announced the discontinuation of their pipeline project due to insufficient customer support in May 2011.

5 EIA, Annual Energy Outlook 2011 With Projections to 2035 www.eia.gov/forecasts/aeo/ 6 EIA, Annual Energy Outlook 2011 With Projections to 2035 www.eia.gov/forecasts/aeo/ 7 North American Natural Gas Supply Assessment, prepared for the American Clean Skies Foundation, Navigant Consulting, July 4, 2008.

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TransCanada officials reportedly maintain that their project is still active and on pace to seek a pipeline certificate from FERC in 2012.

Factors Supporting Gas Supply Growth Enhancements in Horizontal Drilling and Hydraulic Fracturing Natural gas prices experienced volatility and increases since 2000, and culminated in significantly higher prices in 2007-2008, as shown in Figure 5: Henry Hub Price History. The price spike in 2005 was hurricane related. These prices increases contributed to the boom in LNG import facilities projects in the early 2000s, as projected natural gas supplies then were forecasted to continually decline based on assumptions of future gas using traditional vertical drilling in conventional basins knows at that time. That conventional thought, up until 2008, held that North American gas production would have to be increasingly supplemented by imported LNG.

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Henry Hub Price History

Source: Navigant Figure 5: Henry Hub Price History

With higher prices came innovation in costlier technologies that supported the development of horizontal drilling and hydraulic fracturing. These technologies were refined in ways that dramatically increased drilling and production efficiencies, lowered costs, and enhanced the exploration and production economics of shale gas development. By mid-2008, domestic gas production results from shale gas leapt into the national spotlight as production numbers demonstrated surprising and astonishing results. Key to unlocking shale gas production potential was the evolution of the pioneering use of enhanced cost-effective technologies.

Shale gas development has turned the economics of drilling for gas on its head. The cost of developing shale gas has declined and well productivity has increased as drillers gained experience with the new technology. The time needed to drill a shale gas well has plunged from weeks to just days. This has driven down breakeven costs for most gas shales to less than $4/MMBtu, and even lower where natural gas liquids such as propane, ethane and butane are present.

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Shale gas production efficiency has continuously improved and expanded the number of wells that can be drilled on the same site. Instead of drilling numerous wells over an extensive area, numerous wells can now be drilled from the same site and traverse in laterals in various directions underground. The lengths of horizontal laterals average 2,000 to 5,000 feet, but can now extend well over 10,000 feet. Enhancements and innovation continue almost daily in other aspects of hydraulic fracturing technology. After a hydraulic fracture treatment, when the pumping pressure has been relieved from the well, the water‐based fracturing fluid begins to flow back through the well casing to the wellhead. This is called “flow-back” water. Companies like Range Resources pioneered the use of recycled flow-back water, and has been successfully in recycling. Range estimates that 60 percent of Marcellus shale operators are recycling some portion of flow-back water, noting that such efforts can save significant amounts of money by reducing the need for treatment, trucking, sourcing, and disposal costs.8 This is not an endorsement of any company identified herein, but merely an indication of some of the types of companies that are involved. Companies like Anadarko, Atlas Energy, Chesapeake Energy, Devon and others are moving toward total recycling. The industry is positively responding to the attention that is being focused on water usage and disposal. Other companies, like Ecosphere Technologies Inc., Fountain Quail Water Management, GeoPure

Water Technologies, Oasis Filter International Ltd., Pure Filtered Water Ltd. and 212 Resources, are continually developing innovative water recycling technologies. 212 Resources, for example, offers a transportable plant, or pod, that uses thermal distillation and evaporation combined with polishing technologies such as sonic and advanced ultra-violet light. According to 212 Resources, the pod can process flow-back or produced water at well sites to create drinking-quality water. Major improvements continue in this area as public pressure mounts and the industry responds to water treatment and recycling issues. These efforts to improve water management will tend to enhance the ability of shale operations to expand. Several states have passed legislation that requires the contents of chemicals used in the hydraulic fracturing process to be disclosed. Most companies are disclosing this information, switching to “green chemicals” and recycling water without governmental mandates. The EPA is investigating the potential impacts of hydraulic fracturing on water resources and intends to

report initial study results in 2012 with a follow-up report in 2014.9 The industry is aggressively addressing environmental concerns through innovation and water treatment breakthroughs before the EPA releases its initial study on hydraulic fracturing this year. The move by drilling companies to develop and offer new “green” fluids that have been reformulated and adapted from the stringent European North Sea countries should hopefully address the concerns of the EPA and reinforce the continuing progress and support of natural gas development well into the future.

8 Range Answers Questions on Hydraulic Fracturing Process, Range Resources, http://www.rangeresources.com/Media-Center/Featured-Stories/Range-Answers-Questions-on-Hydraulic-Fracturing-Pr.aspx 9 http://www.epa.gov/hydraulicfracturing/

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Shale Gas Size and Growth The rapid development and increasing efficiency of shale gas production has bolstered U.S. natural gas production from about 50 Bcf/d in May 2005 to about 61 Bcf/d in May 2011, even as overall rig counts fell from 1,170 to 890. The 20 percent growth in six years and the increase in overall gas production have been driven by shale gas, as shown below by the increase in horizontal drill rig counts and the decrease in vertical (conventional) rig counts in Figure 6: Monthly U.S. Dry Gas Production and Figure 7: U.S. Gas Rig Count by Type.

Monthly U.S. Dry Gas Production – Lower 48 States

Source: FERC Office of Market Oversight Figure 6: Monthly U.S Dry Gas Production

U.S. Gas Rig Count by Type

Source: FERC Market Oversight

Directional

Vertical

Horizontal

Figure 7: U.S. Gas Rig Count by Type

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The phenomenal growth in shale gas production is shown in Figure 8: North American Major Shale Production 2007-2011. Shale production output from eight major basins under development in North America grew from 3.0 Bcf/d in the first quarter of 2007 to 16.5 Bcf/d in the first quarter of 2011. This is an increase of almost 525 percent in a little more than four years. Over the last decade, U.S. shale gas production has increased 12-fold and now comprises about 25 percent of total U.S. production.

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N.A. Major Shale Production

Figure 8: Shale Production 2007- 2011

As shown in Figure 9: EIA Lower-48 Shale Play Map, the U.S. shale gas resource covers an incredibly large swath of the U.S. with additional large shale plays in Canada. The shale plays on Figure 9 include new plays in the 2011 version of the EIA map that did not appear on the 2010 version. These newly identified plays include the Niobrara, Heath, Tuscaloosa, Excello-Mulky, and Monterey. The oil, NGL and natural gas-rich Eagle Ford has been expanded in size from the 2010 EIA map. Shale plays are layered according to geological zones and depths. As we learn more about the deeper geological characteristics of shale plays, one should expect additional new sources of gas resources. The significant change in the EIA map is a clear indication that we are still in the early phases of discovery for this resource. The Bakken Shale, Marcellus shale, the Atrium shale and the New Albany shale formations are notable as these shales are either in or near the MISO the market area.

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Figure 9: EIA Lower-48 Shale Play Map

The Bakken Shale

The Bakken Formation can be encountered throughout the Williston Basin. The Bakken differs from other shale plays in that it is an oil reservoir, a dolomite layered between two shales, with depths ranging from around 8,000 to 10,000 feet. The Bakken extends across the Canadian border in Manitoba and through Montana and North Dakota. Each succeeding layer of the Bakken formation – lower shale, middle sandstone and upper shale layer – is geographically larger than the one below. The most important factor in the growth of Bakken oil production has been the application of drilling and well completion techniques learned from drilling the gas shales – horizontal wells with longer lateral sections and a greater number of hydraulic fracturing treatments. Even though the cost to drill and complete these newer wells is greater than the older wells, the economics of increased production, especially at today's $100 per barrel oil price, are extremely attractive. A number of geological assessments of the undiscovered, technically recoverable reserves for this shale play estimate that there are as much as 24 billion (bbls) of oil, 1.85 to 4 Tcf of associated natural gas, and 148 to 250 million bbls of NGLs in the play. By the end of 2011, the rate of oil production from the shale formation had increased to 550,000 barrels per day, which put a serious load on the local infrastructure’s ability to ship the oil out of the region. Natural gas is extremely plentiful however the lack of infrastructure forces many producers to “flare” this valuable resource. This is changing. ONEOK plans to spend over $1.6 billion on gas infrastructure to bring these supplies to markets in the Midwest. This year ONEOK began operation of a new gas processing plant. The new plant is expected to be responsible for eliminating flares at 250 wells, and producing 100 MMcf/d.

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Marcellus Shale Industry professionals are projecting that the Marcellus shale will become the largest natural gas producer from shale formations in the North America. The Marcellus formation is not a new discovery but it is currently the hottest play in the 54,000 square mile Appalachian Basin. Before 2006, this low-density, vertically fractured shale formation has had over a 100 year history with thousands of successful, low-volume, vertical gas wells, many of which have produced for decades. However, it was not until the year 2006 with the introduction of hydraulic fracturing and horizontal drilling techniques that had success in the Barnett shale did Marcellus wells begin to yield noticeably and significantly improved production rates. The Marcellus shale ranges in depth from 4,000 to 8,500 feet, with gas currently produced from hydraulically fractured horizontal wellbores. Horizontal lateral lengths exceed 3,000 feet, and, typically, completions involve multistage fracturing with more than three or four stages per well. Each stage is about 1,000 feet in length. The first horizontal wells drilled into the Marcellus shale tested at flow rates that exceeded 6.0 MMcf/d, and drilling operators are still delineating the boundaries of this shale formation. The Marcellus shale was virtually unheard of in 2007, outside of a small circle of geologists. One recognized expert on the Marcellus shale, Dr. Terry Engelder, a professor of geology at Penn State University, has estimated that the Marcellus has a 50 percent chance of containing 489 Tcf of recoverable gas.10 In 2010, the entire United States used about 24 Tcf/yr, or less than five percent of the Marcellus’ potential production.11 In a recent study by Penn State, it is estimated that Marcellus production grew from 327 million cubic feet per day during 2009 to 13.5 Bcf/d by 2020.12 Antrim Shale The Antrim Shale is located in the lower peninsula of Michigan within the Michigan Basin at a depth of 600 to 2,200 feet and covers an estimated 12,000 square miles. The Antrim is the primary unconventional gas target in Michigan and in 2007; the Antrim gas field produced 136 Bcf, ranking it number thirteen in terms of gas volume in the United States. This shallow late Devonian shale formation produces from a depth ranging from 300 to 1,800 feet where the Antrim is naturally fractured.13 This shale has been supplying natural gas in small quantities since the 1940s. However, the 1980s and 1990s technological innovations rejuvenated the Antrim shale from a marginal to a major supplier of natural gas. Production

10 Basin Oil & Gas magazine, August 2009, pg 22, available at http://www.geosc.psu.edu/~engelder/references/link155.pdf 11 EIA, Natural Gas Consumption by End Use, annual table, release date 5/31/2011, available at http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm 12 The Economic Impacts of the Pennsylvania Marcellus Shale Natural Gas Play: An Update, Penn State University, May 24, 2010, page 19. 13 The Origin of Natural Fractures in the Antrim Shale, Michigan by Murray M. Matson presentation at AAPG Eastern Section Meeting, Kalamazoo, Michigan, September 25-29, 2010.

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from this shale peaked in 1998, reaching 547 MMcf/d. By the second quarter of 2008, the Antrim shale averaged 351 MMcf/d, less than its 2007 average of 370 MMcf/d. For the typical well, peak production is reached after two years, and then the wells start to decline at about 8% a year and deliver a 20-year lifespan. Resources estimates range from 35 Tcf to 76 Tcf, with technically recoverable gas reserves estimated at 11 Tcf to 18.9 Tcf according to various studies by the American Association of Petroleum Geologists (“AAPG”). New Albany Shale Similar to the Antrim Shale and at a vertical depth of 500 to 2,000 feet, the New Albany shale, located in the Illinois basin, stretches across portions of Indiana, Illinois, and Kentucky. This shale formation has produced small quantities of natural gas since 1858. It is shallower, water-filled shale with a more coalbed methane-like character (lower Btu) than the other gas shales. The net vertical thickness of the New Albany varies between 50 and 100 feet. Development is ongoing, and production data, as it becomes available, will determine the potential and limits of this formation. Gas resource estimates for the New Albany Shale range from 86 Tcf to 160 Tcf with estimates of technically recoverable reserves ranging from 1.9 Tcf to 19.2 Tcf, according to the National Energy Technology Laboratory (“NETL”).14

As shown on Figure 10: North American Shale Production, U.S. shale gas is projected to grow to 50% of total production by the 2030s. Canadian production (not shown) grows to about 1/3 of total output by 2040.15

11

North American Shale Production Forecast

Shale Gas and Global Gas Developments presentation by, Kenneth B. Medlock III Ph.D.,

James A. Baker Insitute for Public Policy Rice University, May 26, 2011. Figure 10: North American Shale Production

14 New Albany Shale Gas Project, Gas Technology Institute; Report issued September 2009, GTI- 09/0016. 15 Shale Gas and Global Gas Developments presentation by, Kenneth B. Medlock III Ph.D., James A. Baker Institute for Public Policy Rice University, May 26, 2011.

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In the final version of its recently published study The Future of Natural Gas, the Massachusetts Institute of Technology stated that, “The current mean projection of the recoverable shale gas resource [in the U.S., excluding Canada] is approximately 650 Tcf. Approximately 400 Tcf [of which] could be economically developed with a gas price at or below $6/MMBtu at the well-head.”16 In 2009, the Potential Gas Committee of the Colorado School of Mines estimated that the recoverable natural gas resource in North America is 2,170 Tcf, an increase of 89 Tcf over their previous evaluation. This is enough to supply domestic needs at 2010 usage rates (66.1 Bcf/d) for 90 years. Of this total, 687 Tcf is shale gas.17 The British Columbia Ministry of Energy and Mines and the National Energy Board recently estimated the marketable gas in place in the Horn River Basin alone to be between 61 and 96 Tcf. 18 As indicated by the above, there is little doubt that the shale gas resource in North America is extremely large. The size of the shale gas resource in North America is more than adequate to serve all forecast domestic demand through the study period to 2030.

Shale Gas Geology Shale gas geology helps to reinforce its growth potential. Geologic risk has always been a significant issue in finding economically producible amounts of conventional gas. Conventional gas is generally found in porous rock formations, typically sandstone, beneath an impermeable layer called “cap rock”. Conventional gas is produced by drilling through the cap rock into the porous formation to release the gas. Finding and producing conventional gas still involves a significant degree of risk despite technological advances. The risk that wells will deplete quickly or come up “dry” with no deliverability or production following drilling, and thus no return on investment is ever-present in the conventional gas world. In unconventional shale gas, geologic risk is significantly reduced because shale gas plays have a higher level of certainty that gas will be produced in commercial quantities. The reliability of discovery and production of shale gas has significantly improved the economics and risks of drilling. Also shale gas production can be better controlled by managing the drilling and production process than conventional gas. This allows shale gas supplies to be produced in accordance with market demand requirements and economic circumstances.

16 Massachusetts Institute of Technology, The Future of Natural Gas, Ernest J. Moniz, et al, Chapter 1 http://web.mit.edu/mitei/research/studies/documents/natural-gas-2011/NaturalGas_Full_Report.pdf. 17 Potential Gas Committee press release, April 27, 2011, http://potentialgas.org/. 18 Ultimate Potential for Unconventional Natural Gas in Northeastern British Columbia’s Horn River Basin, May 2011, British Columbia Ministry of Energy and Mines and the National Energy Board.

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Since shale gas is trapped in the rock itself, it does not accumulate in pockets under cap rock. It tends to be relatively distributed in consistent quantities over great volumes of the shale. In horizontal drilling, a single well-pad is used to drill multiple well bores up to 10,000 feet in horizontal length into a formation, and each bore produces gas. Shale formations extend for miles and miles and vary in thickness from as little as 50 feet or lower to several hundred feet thick. In many cases, shale formations are in existing gas fields wherein the shale was penetrated regularly but not exploited. This reduces the risk of not finding a producible formation compared to some types of conventional gas structures. The horizontal well can produce volumes large enough to be economic through the use of hydraulic fracturing. Water, sand (or some other proppant to keep the fractures open), and a small amount of chemicals (less than 1%) are injected at high pressure to fracture the shale so that it releases the gas. As is the case with most shale wells, initial production (IP) rates are high, but drop off steeply in a year or two. Once a well has declined to 10-20 percent of initial production, experience has shown that production will then continue at a lower rate with a very slow decline for many years. Figure 11: Decline Curves for Selected Shales below typifies shale well decline curves. 19

Decline Curves for Selected ShalesExpected Ultimate Recovery (EUI)

“Developing Unconventional Gas- Shale Play Comparison,” Range Resources, 19 October 2009.

Figure 11: Decline Curves for Selected Shales

The certainty that shale gas supplies can be produced and managed in accordance with market demand requirements and economic circumstances is highly desirable. If demand is growing, additional zones and/or shale wells can be drilled to mitigate the IP decline rates

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The Economic Impacts of the Pennsylvania Marcellus Shale Natural Gas Play: An Update, Considine, Watson, and Blumsack, Penn State University, May 24, 2010,available at http://www.energyindepth.org/wp-content/uploads/2009/03/PSU-Marcellus-Updated-Economic-Impact.pdf

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from earlier wells. If demand subsides, drilling rates can be reduced or discontinued completely with production managed to meet market demand. Shale gas development is further reinforced by the fact that many shale formations also contain NGLs and oil, which strengthens the economic prospects of shale. For example, several energy companies including Enbridge, Enterprise Products Partners, Buckeye Partners, Kinder Morgan, and Dominion have recently announced plans to build or enhance NGL gathering and transmission systems in the Marcellus shale formation. The Eagle Ford formation in Texas is being developed as an NGL and oil play as much as a natural gas play. The general shift over the past year has been to exploit oil and NGLs with natural gas “along for the ride”. With gas prices at almost historic lows, it is the higher priced oil and NGLs that keep natural gas flowing even at uneconomic costs to the producers. Associated gas is gas that is produced in conjunction with oil production. It is also produced when NGLs are produced. Gas production is robust not only by the economics of natural gas itself, but by NGL prices, which tend to follow oil prices. Oil prices can offer a significant premium to natural gas on a per-MMBtu basis, particularly in today’s market with oil at $100 per barrel which equates to about $17.25 per MMBtu. Much has been made of the per-play economics of shale gas development. While the cost of producing commercial quantities of gas does vary from play to play, and even within a play, the overall trend is that drilling costs are declining as producers gain experience, develop efficiencies such as the ability to develop multiple fracture zones per well, and leverage investments in drilling equipment across greater volumes of gas. In some pure gas shale plays, costs have dropped below $4.00 per MMBtu (Dth) to produce, and continue to drop. Most shale gas plays are expected to be economic in the $2.50/Dth to $6.00/Dth range. In NGL and crude oil plays such as the Eagle Ford and Bakken, the cost to produce gas can be thought of as essentially zero, as long as the price of the NGLs and oil supports drilling. In the Bakken, large amounts of natural gas are being “flared” due to lack of gathering and pipeline infrastructure. As noted above, the price of liquids is several multiples higher than the price of natural gas on a per-MMBtu basis. It is expected that NGL and crude oil prices will continue to correlate and be strong relative to natural gas, based on continued strong demand as shown below in Figure 12: Comparative Spot Price Movements in Natural Gas, Crude Oil and NGLs.

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Comparative Spot Price Movements in

Natural Gas and NGLs

HH NG

Propane

Ethane

Butane

Iso-butane

Nat. Gasoline

Source: FERC Market Oversight

Figure 12: Comparative Spot Price Movements in Natural Gas and NGLs.

In its International Energy Outlook 2010, the EIA projected worldwide demand for liquid fuels would continue to be driven by strong economic growth and increasing demand for liquids in the transportation and industrial sectors in Asia, Europe, and Central and South America. The EIA projects demand to grow by more than 24 million barrels a day. The EIA also forecasts oil prices to increase to $130 per barrel by 2035, which will incentivize natural gas production.20.

Trend: Oil & Liquids are Driving the Gas Market

Donald Santa, President & CEO, INGAA, ONEOK Partners Interstate Pipeline Customer

Meeting Lake Forest, IL May 10, 2011

Figure 13: Trend: Oil & Liquids are Driving the Gas Market

20

International Energy Outlook 2010, EIA, at http://www.eia.gov/oiaf/ieo/liquid_fuels.html

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As shown above in Figure 13: Trend: Oil and Liquids are Driving the Gas Market, associated natural gas production remains strong and benefits from today’s trend by producers who seek higher profits in oil and NGLs in the same shales. Natural Gas Demand Natural gas consumption increases for power generation are likely to continue as domestic production continues to grow and natural gas remains a relatively inexpensive option for generators, but most projected growth is based mainly on the expectation of coal-fired power plant retirements. According to the EIA, since December 2008, the rolling 12-month total consumption of natural gas by the electric power sector has consistently exceeded the same measure of natural gas consumption by the industrial sector. Both the decreased industrial natural gas consumption due to the economic downturn and the increased utilization of natural gas-fired electric power generators contributed to this change. Figure 14: U.S. Natural Gas Consumption: Industrial vs. Electric Power Sectors highlights the trend that natural gas for power generation will exceed industrial demand for the foreseeable future and presumably beyond 2030, as industrial energy conservation and demand-side management increases.

US Natural Gas Consumption:

Industrial vs. Electric Power Sectors

Source: U.S. Energy Information Administration, Nov. 2011 Natural Gas Monthly, “Today in Energy” Aug.19, 2011

Figure 14: U.S. Natural Gas Consumption: Industrial vs. Electric Power Sectors

Taking advantage of the surplus of natural gas supply, LNG export facilities such as the nine U.S. export projects in operation or underway, offer the potential for a new baseload export market for natural gas and to support ongoing development of natural gas through market balancing. Canadian developers also have proposed several new export projects.

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The development of LNG exports is another recent positive development to the sustainability of the long term gas market. In May 2011, Cheniere Energy received U.S. Department of Energy (DOE) approval for the export of up to 2.0 Bcf/d of LNG from their Sabine Pass terminal. Cheniere has plans to construct several new liquefaction terminals on the same sites as their existing import facilities. The Kenai Peninsula facility in Alaska has been exporting LNG since the late 1960’s. But, three other LNG projects, Freeport LNG, Cameron LNG and the Coos Bay Oregon project have recently been granted export approval by the DOE. Four additional facilities are in various stages of the export application process: Dominion’s Cove Point, MD, Cheniere’s Corpus Christi project, the Golden Pass LNG project and the Gulf Coast LNG project near Brownsville, Texas. Coal-fired electric generation is likely to continue to be under pressure from increasingly stringent environmental regulations. The FERC recently issued an informal report stating that up to 81 gigawatts of coal- and oil-fired electric generation is "likely" or "very likely" to be retired due to new environmental restrictions, including the EPA’s recently issued maximum including the EPA’s recently issued maximum achievable control technology (“MACT”)21 requirement within the proposed Cross-State Air Pollution Rule (“CSAPR”).22 The EIA projects natural gas power generation to almost double by 2015 and shown in Figure 15: Natural Gas Growth in Power Generation.

Natural Gas Growth in Power Generation

Natural gas, wind and other renewables account for the vast majority of capacity additions from 2009 to 2035

Figure 15: Natural Gas Growth in Power Generation.

CSAPR will institute a stringent national standard on emissions of mercury, arsenic, and other pollutants found in coal and oil, but not in natural gas. While the very large 81 gigawatt

21 MACT rule was issued on December 21, 2011. 22 FERC’s August 1, 2011 Letter to Senator Murkowski.

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estimate is highly fluid and based on assumptions subject to review, it indicates the direction for gas. Actions by the EPA as directed by the Presidential memo of December 23, 2011 confirm further regulatory action against coal-fired power generation. The strict MACT rule represents an “upgrade or die” obligation for operators of older coal-fired plants, requiring them to limit their emissions of various air pollutants, including mercury, by January 2015, with some flexibility for one- to two-year extensions.23 Several major utilities have announced or are actively executing programs to retire coal-fired facilities. For example, Tennessee Valley Authority signed a settlement with the EPA to idle or retire 2,700 megawatts of its 17,000 MW of coal fired capacity (from 18 units) by 2017. Southern Company announced that under the CSAPR and MACT EPA rules it would expect to retire 4,000 MW of its 12,000 MW coal-fired fleet, and about 3,200 megawatts' worth of coal- and oil-fired plants would be converted to run on gas and another 1,500 megawatts would be replaced with new gas plants. It is estimated that about 40 percent of Southern's coal fleet would be retired or replaced with gas. It could need to spend $13 billion to $18 billion through 2020 upgrading its coal-fired plants in response to the new EPA rules.24 American Electric Power states that it will retire almost 6,000 MW of coal-fired generation and has listed 25 of 55 coal-fired generators as candidates for being shuttered, many of which have been running at full capacity in 2011. On that list is a 42-year-old behemoth in Louisa, Ky., called Big Sandy 2. Upgrading it would cost $700 million.25 The New York Times stated that up to 80,000 MW of coal-fired capacity could be supplanted by other fuels or conservation in the U.S. as a result of the new EPA rules.26 This number is consistent with the FERC Staff number of 81 gigawatts.27 It represents about seven percent of the U.S.’s electric generating capacity. The EPA’s estimate is much lower at 10,000 MW. However, the trend toward large-scale coal reductions is clear, and that natural gas is the leading replacement fuel choice for power generation. Power sector natural gas consumption growth is the dominant driver of future natural gas market growth in all regions and depicted in Figure 16: U.S. and Canadian Gas Consumption. If the U.S. and Canadian natural gas market increases, about three-fourths of the market growth will occur in the power sector.28 Electric load growth, penetration of renewable generation technologies, demand-side management, penetration of clean coal with carbon capture, and expansion of nuclear generation are areas of uncertainty. The growth rate of natural gas consumption in the electric generation sector is the predominant determinant of the growth rate of the entire natural gas market.

23 Gas Daily, “EPA rule seen creating substantial gas demand,” December 23, 2011. 24 New York Times, August 5, 2011, “Southern Co. Sees Price Tag of at Least $13B for New EPA Rules”. 25 New York Times, August 11, 2011. “New Rules and Old Plants May Strain Summer Energy Supplies”. 26 Ibid. 27 FERC’s August 1, 2011 Letter to Senator Murkowski. 28 “North American Natural Gas Midstream Infrastructure Through 2035: A Secure Energy Future - Updated Supply‐Demand Outlook”, June 28, 2011, prepared by ICF International for the INGAA Foundation.

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Source: INGAA

Figure 16: U.S. and Canadian Gas Consumption Despite the increase in natural gas use for power generation, the U.S. and Canadian natural gas markets are, and will continue to be, winter peaking. The seasonality of space heating dominates all but the southern parts of the U.S. Currently, with normal weather, U.S. and Canada demand in a peak winter month is over 60 percent above demand in a peak summer month. Shale gas continues to have enormous potential because technological advances continue to drive down drilling and production costs. To satisfy consumption levels in the EIA EO2011 Reference case, the number of lower 48 natural gas wells completed increases by 2.3 percent per year from 2009 to 2035. As a result, the average wellhead price for natural gas increases by an average of 2.1 percent per year, to $6.26/Dth in 2035 (2009 dollars). Henry Hub prices increase by 2.3 percent per year, to $7.07/Dth in 2035. Nonetheless, the Henry Hub price and average wellhead prices do not pass $5.00/Dth until 2020 and 2024, respectively.29 While demand seems certain to increase, the long-term production profile of shale gas remains a mystery. Initial production falls off much more quickly in shale than in conventional, naturally-pressurized wells. A fall off in regional production could quickly cut into the economics of expensive pipeline assets. The natural gas industry is awaiting the EPA’s 2012 and subsequent 2014 Study and potentially new regulations on hydraulic fracturing which could pave the way for more adverse regulatory impact and higher costs on the industry. LNG export facilities may also face unknown future production and regulatory adverse risk exposure since LNG export facilities require large amounts of gas throughput over long terms (up to 20 years or more) and require large amounts of predictable throughput to remain economically viable. A loss in production throughput and unforeseen regulatory costs could negatively impact these investments.

29 EIA, Annual Energy Outlook 2011 With Projections to 2035.

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Impacts on Natural Gas Infrastructures The Midwest and the MISO region is becoming a more important crossroads in the United States natural gas market. There is an extensive network of over 25 pipelines that transport natural gas from nearly all major supply basins in North America to and around this region. Historically, the Midwest and the MISO region benefited from gas supply flowing from the north from Canada and from the south and southwest (Louisiana, Texas, Oklahoma) northward to Chicago and other northern markets. These historical “longitudinal” flows in the U.S., as depicted in Figure 17: Historic “Longitudinal” Flow Patterns have seen substantial changes lately. The EIA forecasts that by 2030, interregional flows will increase predominately due to growing unconventional production in the Midcontinent, the northern Rockies and the Appalachian basins. 30 The pipeline corridors with the most significant volume increases include the REX corridor from Wyoming through the midcontinent to the U.S. northeast; the Appalachian Basin to the Northeast; the east Texas to northern Louisiana corridor to the Midwest central and northeast regions; western Canada to the Midwest and Chicago corridor and along the Gulf Coast into Florida. All these volume shifts are “supply push” increases, with the exception of Florida, where increased flow is driven by “demand pull”. LNG exports and imports will be “price driven” by overseas markets.

Historic “Longitudinal” Flow Patterns

U.S. Pipelines Central ANR / Great Lakes 2011 Shippers Meeting August 11, 2011

LNG

LNG

LNG

LNG

Figure 17: Historic “Longitudinal” Flow Patterns

This traditional south to north (Gulf and Southwest gas) and north to south (Canadian gas) has been altered by the REX, the pipelines it touches and shale gas developments, as shown in Figure 18: Today’s Developing “Grid” Flow Patterns. Increased Marcellus shale production,

30 EIA, Annual Energy Outlook 2011 With Projections to 2035.

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for example, combined with additional pipeline construction in the Northeast, has presented unprecedented flow implications for the rest of the North American gas market. The Marcellus shale's production continues to increase, impacting and affecting supply and demand shifts that affect all other production regions such as Canada, the Southwest, the Gulf areas and the Rockies. Combined with shale gas developments nationwide, pipeline infrastructure projects have created a major paradigm shift and domino-effect of altering traditional North American gas market flow patterns.

Today’s Developing “Grid” Flow Patterns

Additional Flow

Paths in Black

Flow pattern changes from traditional

“South to North” to a Grid Structure

U.S. Pipelines Central ANR / Great Lakes 2011 Shippers Meeting August 11, 2011. Greg Peters, MISO Presentation, 2012 Figure 18: Today’s Developing “Grid” Flow Patterns

In addition, INGAA estimates that changes in gas supply and demand also will require significant investment in natural gas infrastructure. Between 2009 and 2030, the U.S. and Canada will need 371 Bcf to 598 Bcf of additional gas storage capacity above the current estimated 4,000 Bcf of working gas capacity. For comparative purposes, since 2000, the U.S. has added about 1,000 Bcf of additional working gas capacity. Total expenditures on new storage capacity range from $2 to $5 billion. Much of the new storage capacity that is needed is high deliverability storage to meet the growth in gas demand for electricity generation.31 The obvious fact is that infrastructure development is driven by gas supply and gas demand issues and an array of factors ranging from environmental considerations to long-term returns on capital investments. Since 2008, delivery of unconventional shale and tight gas has been the driver, and the major lobbying effort has been by gas producers, particularly in the Rockies, to expand pipeline infrastructure. Supply-driven forces and long-term regulatory support by the FERC to build-out the national energy infrastructure, which began, and 31 North American Natural Gas Midstream Infrastructure Through 2035: A Secure Energy Future - Updated Supply‐Demand Outlook, 1/1/09, prepared by ICF International for the INGAA foundation.

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received its strongest support in the early 2000s, helped to make projects out of the Rocky Mountain states, like the REX, the Ruby Pipeline and the Bison Pipeline, a reality. As shown in Figure 19: Market Responsive Infrastructure Additions, that same impetus helped producers to find additional outlets for shale gas in north Texas and Louisiana and Arkansas with the Boardwalk Pipeline, the Midcontinent Express, Fayetteville Express Pipeline, the Tiger Pipeline and others, and numerous enhancements and expansions in the Appalachian basin and other shale-rich basins.

Market Responsive Infrastructure Additions

Figure 19: Market Responsive Infrastructure Additions

A number of factors, supply, demand, regulatory, price and investment returns and other factors helped to drive pipeline infrastructure development. Some of these are outlined below with the events, issues and impacts driving the transformation of the North American gas pipeline infrastructure growth and pipeline flow changes in today’s natural gas industry: Supply

Conventional reserves are depleting at a faster rate than replacement.

Unconventional reserves are rapidly developing beyond any historically perception of the vast reserves accessibility due to new technologies.

Paradigm shift in supply perspective due to new technologies and shale gas.

Production up in 2008 – 2012: overall gas balance indicates well-supplied markets that are now being driven by oil and NGL and associated gas.

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Prices

Prices reached record highs in 2008, and then collapsed below 5-year average.

Gas prices have returned to 2002 – 2003 levels after extreme pre-2009 price volatility.

Low prices rebalance supply and demand in short-run. Demand

2009 - 2012 deep economic recession reduced consumption growth.

Gas consumption growth is primarily due to seasonal demand and electric power generation (quickly growing as percent of total U.S. demand).

2011- 2012 is struggling to balance over-supply with demand.

Regulatory

There is a need to link production sources and markets through more efficiently operated pipeline and storage expansion and allow reasonable cost allocations and recovery to encourage greater efficiencies and lowering of costs in capacity markets.

FERC continues previous Administration’s goal to make energy infrastructure improvements and to promote the development of a strong energy infrastructure.

Infrastructure

The fall-out from the 2008 - 2009 financial markets melt-down further exacerbates credit-tightening and hampers infrastructure and production growth.

Infrastructure build-out of storage, pipelines and changing fate of LNG import/export.

Pipeline and storage construction continues, although slowed due to the economic recession, financing and compelling power generation demand may be “forced” to finance future natural gas infrastructure requirements,

More than one-third of the pipeline projects since 2008 addressed a growing need for additional natural gas pipeline capacity to support transportation of new natural gas production to regional markets. This trend continues today with the overwhelmingly clear majority of all new gas pipeline projects being driven by shale supply-driven projects and as producers tap into oil and NGL-rich shales to remain financially viable in light of lower natural gas prices.

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Such projects are concentrated in the expanding shale-rich oil, NGL and natural gas production areas throughout the United States and Canada. This layer of infrastructure is primarily providing access to local markets and interconnections with the interstate natural gas pipeline network. This trend will continue as new production opportunities develop in areas that have been overlooked for re-work, undiscovered or become economical. Taken as a whole, Figure 20: Impact of Emerging Shales and Conventional Declines to Pipelines, when viewed with Figure 19, provides a overview of how supply changes are driving infrastructure, capacity and flows.

Impact of Emerging Shales and

Conventional Declines to Pipelines

CenterPoint Energy Nov. 18, 2011 Customer Meeting Figure 20: Impact of Emerging Shales and Conventional Declines to Pipelines Arctic resources may face too many economic, public sentiment and environmental obstacles to be considered, unless the EPA seriously curtails and limits the use of hydraulic fracturing for shale gas development. LNG will become a two-way trade based on international pricing and locational basis differentials in Europe and Asia, with imports to where they are only needed to maintain existing import terminal equipment or contract obligations. The U.S. to European and Asian locational price differentials are shown below in Figure 21: World LNG Estimated January 2012 Landed Prices. The European and Asian market prices have historically been in this range over the past five (5) years. The U.S. LNG industry is evaluating and/or preparing to become a primarily export market. U.S. exports could be impacted if European and Asian publically-held and state-run oil and gas companies and are able to use hydraulic fracturing technologies in their respective regions. The high level of Asian, particularly the PRC, KOGAS and Indian and European oil and gas companies’ joint-venture, investment and purchase of U.S. companies with this expertise may make this a reality. The latest estimates for technically recoverable natural gas in the United States exceed 2.5 quadrillion cubic feet. This is more than double the US Geological Survey estimate of 1.1 quadrillion cubic feet in 1995. Canadian gas producers, which depend on U.S.

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markets, are especially hard hit by the U.S. surplus. Recent shale gas discoveries in Northeast British Columbia have pushed technically recoverable reserves from just three basins – Horn River, Montney and Cordova – to more than 1.0 quadrillion cubic feet. Five LNG export projects are now proposed along British Columbia’s West Coast.32

World LNG Estimated January 2012 Landed Prices

Figure 21: World LNG Estimated January 2012 Landed Prices

France may be an exception as the French government banned the use of hydraulic fracturing in 2011. Also, the impact of diverse European regulations, infrastructures and competing energy interests and geological are factors that have yet to be determined for their potential. In the 2009 INGAA Pipeline and Storage Projections Study33, 2009 transmission pipeline capacity between major regions throughout the U.S. and Canada was found to be approximately 130 Bcf per day. The study further found that, by 2030, the need for new interregional natural gas transport would likely increase by between 21 and 37 Bcf per day and will need approximately 29,000 to 62,000 miles of additional natural gas pipelines. Additionally, 370 to 600 billion cubic feet (Bcf) of storage capacity will be needed in order to accommodate market requirements. The majority of storage capacity additions are projected to be high deliverability salt cavern storage, which would essentially double current capacity. Insufficient infrastructure development could lead to price volatility, reduced economic growth and diminished delivery of gas supply to consumers who need it most, according to the study. Other infrastructure needed from 2009 to 2030, INGAA points out include:

32 2ND Annual North American LNG Exports Conference December 1, 2011. 33 Natural Gas Pipeline and Storage Infrastructure Projections Through 2030, October 20, 2009 submitted to: The INGAA Foundation by ICF International.

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6.6 to 11.6 million horsepower of new gas transmission pipeline compression;

15,000 to 26,000 miles of new gathering pipelines;

20 to 38 Bcf per day of new natural gas processing capacity;

3.5 Bcf per day of new LNG import- export terminal capacity. 34

The projected midstream infrastructure will have a cumulative capital expenditure ranging from $133 to $210 billion from 2009 through 2030, equating to annual expenditures ranging from $6 to $10 billion35. This need for new infrastructure would be driven predominately by a shift in production from conventional mature basins to areas of unconventional natural gas production that needs additional paths to the marketplace. Pipeline expansions will be driven by regional projects and few, if any of the mega-scale, long distance “bullet” projects will be needed as existing long-lines are looped or driven by compression only or a combination of the two, from regionalized shale gas to regionalized markets. Future pipeline infrastructure will be mostly influenced by not only the shift of production from unconventional production areas (supply-push), but more so by future demand-pull than it has in the past 40 years. Consumer natural gas consumption growth has an important, although relatively smaller influence on natural gas infrastructure development in the Midwest compared to electric power generation. Incremental pipeline infrastructure and innovative rates and services will be needed to primarily serve growth in power generation, because spare seasonal pipeline capacity may not be available. Pipelines may also need to “re-think” the flexibility of their operations to accommodate power generation demand if customers are reluctant to commit to long-term contracts to support the financial burdens of infrastructure expansion. Supply-push has historically been influenced by producers and marketers compared to “demand-pull” advocates in the “deregulated” environment. Fading memories of the “Winter of 1976-77”, the negative supply legacies of the Fuel Use Act of 1978, occasional concerns about hurricanes and well “freeze-offs”, and of course, the recent downward spiral of domestic conventional gas production has inherently reinforced supply push in the gas industry. As perplexing as it may appear today, these legacy concerns are strongly vocalized by industrial gas users groups in their opposition to the various LNG export projects under consideration. Based on current governmental regulations and other EPA issues facing the electric power industry, power generation will be the primary demand driver for the foreseeable future as it will take years, if ever, for natural gas to be a strong demand-pull for transportation and end-use demand is a low-growth prospect in competition with electric power and demand-side management. Furthermore, there are a plethora of rate issues, fixed-cost recovery and contract length issues and others that beg the question, “Who’s going to pay for it?”

34 Ibid. 35 Ibid.

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Natural Gas Pipelines in the MISO Region The Midwest and the MISO region has become a crossroads in the United States natural gas market. An extensive network of 21 major interstate pipelines transports gas from nearly all major supply basins in North America to and around the MISO region. Gas flows in the region have seen substantial changes lately. The EIA forecasts that by 2030, interregional flows will increase predominately due to growing unconventional production in the Mid-continent, the northern Rockies and the Appalachian basins. The traditional “south to north” (Gulf and Southwest gas) and “north to south” (Canadian gas) pipeline corridors have been altered over the past 3 years with significant west to east and Rockies to the Pacific pipeline (east to west), expansions creating a restructured national matrix or grid-like structure of interstate gas pipeline flows. Also, with the re-positioning of pipeline flows in the Northeast U.S. by companies like Dominion Transmission, Tennessee Gas Pipeline, Texas Eastern, National Fuel Gas and Columbia Gas Transmission, U.S. producers in the Appalachian Basin (Marcellus) are now flowing gas into Canada, backhauling supplies southward and working with the Midwest pipelines on “backhaul” of natural gas westward as evidenced by the rash of recent FERC pipeline rate and tariff filings on General Terms and Conditions governing backhaul and related services. Kinder Morgan, for example, is exploring opportunities to provide backhaul services by displacement from the Marcellus to the Midwest along sections of its 1,700-mile Rockies Express Pipeline. These types of innovations are being looked at industry-wide as gas production in the Marcellus shale narrows the price differentials between Rocky Mountain and East Coast natural gas markets and between other areas of North America as well. Increased Marcellus shale production, for example, combined with additional pipeline construction in the Northeast, has unprecedented flow implications for the rest of the North American gas market. The Marcellus shale's production continues to increase, impacting and affecting supply and demand shifts that affect all other production regions in Canada, the Southwest, the Gulf Coast area and the Rockies. Combined with shale gas developments nationwide, pipeline infrastructure projects have created a major paradigm shift and domino-effect of altering traditional North American gas market flow patterns. This is another reason why pipelines need to “re-think” about how the can operate their system to add flexibility.

Pipeline Infrastructure in the Midwest

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Transportation of Natural Gas Supplies

Traditionally, the principal sources of natural gas for the MISO region have been the panhandles of west Texas and Oklahoma, the States of Kansas and Louisiana, and eastern Texas. Currently about 61 percent of the peak-day capacity entering the Midwest via the interstate network comes from production areas in the Southwest Region. 36 However, by the close of 2009, Kinder Morgan Energy Partners LP completed the 713-mile western portion of REX37, increasing the capability to transport up to 1.8 Bcf/d of natural gas (as measured at the Missouri/Illinois border) directly from the Rocky Mountain production region to the MISO region. In 2009, the REX was extended further eastward to western PA.

Where indicated, the respective pipelines’ capacity is based on actual maximum nomination flow data from the respective pipelines’ electronic bulletin boards (“EBBs”) compiled by Bentek Energy for the period January 1, 2005 through October 31, 2011 at the measurement location(s) indicated below.

Several large interstate natural gas pipelines originating in the Southwest (west Texas and Oklahoma panhandles) provide service within the region on their way to markets in the MISO region. These natural gas pipeline systems flow northeastward primarily through Kansas, Missouri or Nebraska and Iowa to reach Midwest natural gas markets. These pipelines include the Panhandle Eastern Pipe Line “PEPL” (1.5 Bcf/d at the Missouri/Illinois border) and the two largest into the MISO region. These two are the Natural Gas Pipeline Company of America “NGPL” system (3.25 Bcf/d combined, Amarillo system at the Iowa/Nebraska border and SE Gulf Coast System at the Illinois/Missouri border) and the ANR Pipeline Company “ANR” system (3.4 Bcf/d combined, at the Northern Illinois/Wisconsin border, at the Northern east Illinois/Michigan border, and at the Southeast Central Kentucky border) which follows similar routes as NGPL, but provides more capacity in Wisconsin and Michigan.

ANR Pipeline Company (ANR) and Natural Gas Pipeline Company of America (NGPL), operate on corridors that transport supplies from the Texas, Oklahoma, Kansas, and Louisiana production areas. NGPL provides almost 15 percent of the total throughput capacity into the Midwest region and terminates in the Chicago, Illinois area. Only a limited amount of unsubscribed underground storage capacity is available to transporters along this route. However, during the nonheating season a sizeable amount of capacity on these systems is used to transport supplies for injection into storage facilities in Iowa, Illinois, Indiana, and Michigan. The ANR Pipeline with almost 15.5 percent of the total capacity into the MISO region has a number of storage sites located at the northern end of its system in Michigan. NGPL has a number of storage sites located in Iowa and Illinois.

Three systems, Northern Natural Gas Company “NNG”(1.73 Bcf/d at the Nebraska/Iowa border), Panhandle Eastern Pipeline Company, and Centerpoint Mississippi River Transmission Company “MRT” (.0234 Bcf/d at the Illinois/Missouri border) transport gas to

36 EIA website. 37 BOLDED companies’ names are the companies that were analyzed for capacity requirements.

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the MISO region from the Texas, Oklahoma, Louisiana and Arkansas production areas, while four others, Texas Gas Transmission Company “TGT” (0.588 Bcf/d at the Indiana/Kentucky border), Trunkline Gas Company (1.4 Bcf/d at the Illinois/Kentucky border), Texas Eastern Pipeline Company’s “Tetco” North 24 Leg (0.274 Bcf/d at the Missouri/Illinois border ), and Tennessee Gas Pipeline Company (eastern Ohio) systems begin in Louisiana and east Texas and proceed directly north into the MISO region. However, most of the capacity on the latter two systems is intended for markets in the Northeast. The Texas Eastern Transmission Company “Tetco” system N 24 Leg skirts the lower southeastern corner of the region, providing service into the southern parts of Illinois, Indiana and Ohio. The three most recent additions to the regional network are: the Horizon Pipeline (0.4 Bcf/day net at the Illinois/Indiana border) and the Guardian Pipeline (1.3 Bcf/day at the Illinois/Wisconsin border) interstate systems, both completed in 2002, and the Heartland Pipeline Company an intrastate pipeline, completed in 2006. The Horizon and Guardian systems receive natural gas supplies in the Chicago area from the interstate natural gas pipeline system for delivery to markets in northern Illinois and the greater Milwaukee, Wisconsin metropolitan area. The Heartland Pipeline extends from an interconnection with Midwestern Gas Transmission “MGT” (0.527 Bcf/d at the Kentucky border) in Sullivan County, Indiana, to Indianapolis-based Citizens Gas' underground storage facilities in Greene County. The Crossroads Pipeline Company (0.461 Bcf/day net at the Illinois/Indiana border), an affiliate of Columbia Gas Transmission Company, provides natural gas transportation for shippers seeking a route between interstate natural gas pipelines serving western Indiana to interconnections in central Ohio to the Columbia Gas Transmission Company system. For the most part, natural gas customers (and LDCs) in Indiana are dependent upon interstate pipelines that traverse the State. Only the Texas Gas Transmission Company system terminates in the State, where it directs about 30 percent of its total system capacity. Southern Star Central Gas Pipeline Company (0.4 Bcf/day at the Kansas/Missouri border) is a Rockies supplier from Wyoming to Missouri. The average usage rates on this and similar service lines in the area are low, primarily owing to the seasonal nature of the service: low summer time flows tend to offset the high winter flows. In 2010-2011, for instance, average annual utilization of Southern Star’s Kansas/Missouri line was only about 38 percent. Also within the MISO region is the Williston Basin Interstate Pipeline “WBIP” (.250 Bcf/d at the Montana/North Dakota border) that provides transportation, storage and gathering services in Montana, North Dakota, South Dakota and Wyoming. The pipeline is connected to several major pipelines allowing transportation of regional natural gas supplies and is a link between Canada, the Rockies and the mid-continent area. Lastly, the Bison Pipeline, LLC (0.48 Bcf/d at the Northern Border interconnect), entered commercial service on January 14, 2011. Bison is an interstate natural gas pipeline designed to transport gas from the Powder River Basin where it interconnects with Northern Border Pipeline Company’s “NBP” (2.32 Bcf/d at the Canadian Border) system near Northern Border’s Compressor Station No. 6 in Morton County, North Dakota. In 2001, Northern Border Pipeline

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Company system also interconnected with the Vector Pipeline Company (1.56 Bcf/d at the Joliet interconnect) at the Chicago hub, permitting its shippers of western Canadian (Alberta) natural gas an alternative route to reach delivery points in Ontario, Canada. Finally, while outside of MISO, additional Midwest markets include the Kansas City metropolitan area of Kansas and Missouri, served by the Southern Star Central Gas Pipeline Company (formerly Williams Gas Pipeline Central), KM Interstate Gas Transmission Company, and parts of the Panhandle Eastern Pipeline Company systems; and the St. Louis, Missouri, area, which is served by the Southern Star Central Pipeline Company (outside MISO) and Centerpoint Mississippi River Transmission Company (“MRT”) and systems. MRT also transports gas along this corridor but it terminates in the St. Louis, Missouri, area. Its operations in Illinois are confined to the area east of St. Louis. Canadian Natural Gas Imports to the MISO Region

Five interstate natural gas pipeline companies transport Canadian natural gas (from TransCanada Pipeline and Foothills Pipeline) into or out of the Midwest (see Table 2 below) with a combined capacity of approximately 8.6 Bcf/day. The largest natural gas importing pipeline in the region is the Great Lakes Gas Transmission Company (2.33 Bcf/d at the Canadian border) system, which links to the TransCanada Pipeline Ltd system at the Manitoba/Minnesota border and proceeds through the northern portion of Minnesota, Wisconsin, and Michigan and southward through Michigan to the Michigan/Ontario border.

However, a large portion (about 85 percent) of the natural gas transported on the Great Lakes Transmission Company system is delivered back into Canada for consumption in Ontario and eastern Canada. In contrast, Viking Gas Transmission Company (0.533 Bcf/d at the Canadian Border) 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 does not have any gas production; it is merely a Canadian conduit from the TransCanada system into the upper Midwest.

Natural gas transportation on the Northern Border system reaches the Midwest Region by way of the Central Region (from the Saskatchewan/Montana border, through North Dakota, South Dakota, Minnesota, and Iowa, -- then into Illinois (0.99 Bcf per day) and finally western Indiana). The Northern Border Pipeline Company system physically reached the Midwest for the first time in 1998 with completion of a 200-mile extension from Iowa (Central Region) to the vicinity of Chicago, Illinois. In the Chicago area, the Northern Border Pipeline system interconnects with Peoples Gas Light & Coke Company. Subsequently, the Northern Border system was also extended (34 miles, 0.6 Bcf/d) to just east of the Indiana/Illinois border where it provides shippers access to the Indiana market with direct interconnections to customers such as the Northern Indiana Public Service Company. A sizable portion of the natural gas transported on the Northern Border system still reaches the Midwest indirectly through interconnections with the Northern Natural Gas Company

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(“NNG”) and NGPL interstate systems in Iowa. The NNG system's 2.7 Bcf/d interconnect with Northern Border provides shippers with a liquid Canadian supply point into the Midwest Region through NNG's extensive network of pipelines throughout Minnesota, Iowa, Wisconsin, eastern Nebraska, northwest Illinois and the Upper Peninsula of Michigan. NNG also accesses significant Canadian supply through interconnects with Viking and Great Lakes. The NNG system also provides shippers with natural gas transportation services to Midwest markets from the Southwest Region's and interconnection access to the Rockies production areas. The NNG system has more than 1,400 delivery points within the MISO region. While it has the capability to transport 1.73 Bcf/d into the region from the Southwest as measured at the Nebraska/Iowa border, it also receives large volumes of natural gas from interconnections to other interstate natural gas pipelines within the region which boosts overall MISO region market area capacity to approximately 5.5 Bcf/d. The newest large capacity pipeline to import Canadian natural gas into the region is the Alliance Pipeline Company system (1.9 Bcf/d at the Canadian border). Completed in late 2000, the U.S. portion of the Alliance system extends from the Saskatchewan/North Dakota border southeast through Minnesota and Iowa, and terminates in the vicinity of Joliet, Illinois, at the Aux Sable NGL and natural gas processing plant. The U.S. portion of the Alliance system has only three delivery points between the location at which it begins, and its termination point. The "wet" gas that is processed at the Aux Sable processing plant is delivered "dry" (pipeline quality natural gas) at its tailgate to several major interstate natural gas pipelines, including ANR, NGPL, MGT and Vector, for shipment to customers in Illinois, Indiana, Ohio, Michigan, and Ontario, Canada. In addition, several intrastate natural gas pipeline companies, and LDCs, including Peoples Gas & Light Company and Northern Illinois Gas Co receive natural gas at the Aux Sable tailgate. Intrastate and LDC “Hub” Companies inside the MISO Region Within the MISO region are eleven (11) regional, Intrastate and noteworthy Local Distribution Company (LDC) systems that compose a larger “grid” system in Michigan, Illinois, Indiana and parts of the western Ohio MISO region. These are listed below in Table 1: MISO Region LDC and Intrastate Pipelines. These systems are noteworthy primarily because they have the capability to provide “Hub-like” gas transfers between the major interstate pipelines or in the case of the Michigan systems, have a limited amount of gas production behind their systems.

Their capacity availability is dependent upon the amount of upstream capacity that the interstate pipelines have that deliver to their interconnections. These systems have limited capacity that either serves to move production gas, interconnect with an LDC or perform a transfer service between two larger interstate systems.

All the intrastate systems in Table 1 perform one or more of these limited functions and are dependent on the upstream pipelines for supply deliveries. For that reason, the important determination from this analysis is to identify the available capacity on the primary interstate pipelines upstream of the local distribution and small intrastate systems in the respective States in the MISO Region.

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MISO Region LDC and Intrastate2 Pipelines

Pipeline Name Principal Supply Source(s) System Configuration (Primary/Secondary)

1. Consumers Gas Co (MI) LDC System Trunk/Grid 2. Horizon Intrastate System Trunk 3. Heartland Pipeline Co (IN) Intrastate System Trunk 4. KM Illinois Intrastate System Trunk 5. MichCon/DTE Co1 (MI) LDC/Canada export System Trunk 6. Northern Indiana PS Co (IN) LDC System Trunk/Grid 7. North Coast Gas Tran (OH) Intrastate System Trunk 8. N. Illinois Gas Co (NIGas) (IL) LDC System Trunk/Grid2 9. Saginaw Bay Pipeline (MI) Intrastate - (part of MichCon) Trunk/Grid2 10. MoGas LLC (MO) Intrastate System (feeder) Trunk/Grid2 11. Illinois Gas Trans Co. (MRT) Intrastate System Trunk2

________________ Trunk - systems are large-diameter long-distance trunklines that generally tie supply

areas to natural gas market areas. Grid - systems are usually a network of many interconnections and delivery points that

operate in and serve major natural gas market areas. 1Also operates natural gas import/export facilities located at the Canada border. 2 Function as intrastate or LDC with cross-state links or a Hinshaw pipeline

TABLE 1: MISO Region LDC and Intrastate Pipelines

Hinshaw pipelines A Hinshaw pipeline company (defined by the Natural Gas Act and exempted from FERC jurisdiction under the NGA) defined as a regulated company engaged in transportation in interstate commerce, or the sale in interstate commerce for resale, of natural gas received by that company from another person within or at the boundary of a state, if all the natural gas so received is ultimately consumed within such state. A Hinshaw pipeline may receive a certificate authorizing it to transport natural gas out of the state in which it is located, without giving up its status as a Hinshaw pipeline. Although these pipelines flow gas in interstate commerce, they are subject to simultaneous state and federal regulation.

Michigan Consolidated Gas Company - LDC

Northern Illinois Gas Company - LDC

Illinois Gas Transmission Company’s (IGTC) owned by the CenterPoint Energy system consists of 20 miles of 10 inch diameter pipes that extend from an interconnection with Natural Gas Pipeline Company (NGPL) in Glen Carbon, IL, to various delivery points in Madison County, IL. IGCT is an affiliate of MRT.

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Major Interstate Pipelines into the MISO Region The following Sections more specifically address the important capacity issues in Tasks 2 through 6 using a pipeline-by-pipeline approach to analyzing capacity, load factors, the amount of incremental capacity available above historical flows for additional power generation and the costs associated with building incremental capacity to provide natural gas delivery service to defined locations provided by the MISO. Twenty-one (21) interstate and eleven (11) intrastate/LDC “hub” natural gas pipeline companies operate within the MISO region. These pipelines are analyzed in detail in the following sections. The approach to identifying and analyzing the pipelines to address Tasks 2, through Task 6 starts with specific identification of the pipelines that MISO has identified as potentially and hypothetically having certain requirements for Combined Cycle (“CC”) and Combustion Turbines (“CTs”) under “12K” and “24K” scenarios. These are generally referred to herein as “MISO-identified” pipelines. As shown on Table 2: MISO Region Major Interstate Pipelines the “MISO-identified” pipelines are in bolded format.

The non-bolded pipelines were also specifically reviewed and analyzed in the same analytical approach, as described in the following section “Understanding How Capacity is Measured In This Analysis”, as was used for the MISO-identified pipelines. Following a brief explanation of pipeline configuration and the analytics used such as, “pipeline utilization rate” and in “Measures of Pipeline Utilization”, analytics which include load ratios and load factors and the detailed analysis of MISO-identified pipelines is followed by a similar analysis of the “non-bolded” pipelines identified in Table 2, followed by the analysis of the intrastate systems indentified in Table 1.

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MISO Region Major Interstate Pipelines

Pipeline Name Principal Supply Source(s) System Configuration (Primary/Secondary)

1. Alliance Pipeline1 Canada Trunk 2. ANR Pipeline Louisiana, Kansas, Texas Trunk/Grid 3. Bison Pipeline LLC Wyoming, Montana, North Dakota Trunk 4. Mississippi River Trans. Arkansas, Oklahoma Trunk 5. Crossroads Pipeline Interstate System (feeder) Trunk 6. Great Lakes Gas Trans. Ltd1 Canada/Canada export Trunk 7. Guardian Pipeline Interstate System (feeder) Trunk 8. KO Gas Trans Co (KY-OH) interstate System (feeder) Trunk 9. Midwestern Gas Trans. Interstate System (feeder) Trunk 10. Northern Border Pipeline1 Canada, ND (Bakken) and Bison PL Trunk 11. Natural Gas PL Co. of America Kansas, Oklahoma, Louisiana, Texas Trunk/Grid 12. Northern Natural Gas Kansas, Oklahoma, Texas Trunk/Grid 13. Panhandle Eastern PL1 Kansas, Oklahoma, Texas Trunk 14. Texas Eastern Transmission Louisiana, Texas Trunk 15. Texas Gas Transmission Louisiana, Texas Trunk 16. Trunkline Gas Louisiana, Texas Trunk 17. Viking Gas Transmission1 Canada Trunk 18. Vector Pipeline1 Interstate/export Canada System Trunk 19. Rockies Express Pipeline Wyoming, Colorado Trunk 20. Southern Star Central PL Kansas, Oklahoma, Wyoming Trunk/Grid 21. Williston Basin Interstate PL1 ND, WY, MT , Canada Trunk/Grid

Trunk - systems are large-diameter long-distance trunklines that generally tie supply areas to natural gas market areas.

Grid - systems are usually a network of many interconnections and delivery points that operate in and serve major natural gas market areas.

1Also operates natural gas import/export facilities located at the Canada border. 2 Function as intrastate or LDC with cross-state links. Bolded pipelines have “MISO-identified” facilities or units.

TABLE 2: MISO Region Major Interstate Pipelines In this analysis, the pipelines in Table 1 and Table 2 have been combined into three (3) distinct groups moving forward: (1) “MISO-Identified Pipelines”, (2) “Pipelines into MISO” (that do not have CTs or CCs identified by MISO) and (3) “Pipelines inside MISO”. In Table 3: Pipeline Flow Capacities and Relative Sizes, is shown below to understand the relative sizes of the pipelines that deliver natural gas into and in the MISO region. Note that the four largest capacity pipelines with flowing capacity inside the MISO region are ANR (12.86%), NGPL (12.28%), Great Lakes “GLGT” (8.79%) and Northern Border or “NBP” (8.77%).

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TABLE 3: Pipeline Flow Capacities and Relative Sizes

Flow Flow Flow

Pipeline Capacity Capacity Capacity

MDth/d Percent% Percent%

All INTO All IN

MISO MISO

MISO-Identified Pipes

Alliance 1,923 8.71% 7.27%

ANR N: IL-WI 713 3.23% 2.69%

ANR SE Central 1,419 6.43% 5.36%

ANR N: IL-MI 1,273 5.77% 4.81%

GLGT 2,327 10.54% 8.79%

MRT 234 1.06% 0.88%

NGPL Amarillo 1,450 6.57% 5.48%

NGPL Gulf Coast 1,800 8.15% 6.80%

NBPL 2,320 10.51% 8.77%

NNG 1,730 7.84% 6.54%

PEPL 1,500 6.79% 5.67%

REX 1,870 8.47% 7.07%

TGT 588 2.66% 2.22%

Trunkline 1,400 6.34% 5.29%

WBIP 248 1.12% 0.94%

TOTAL 20,795 94.18% 78.57%

Pipelines Into MISO

Bison 477 2.16% 1.80%

TETCO (Leg 24) 274 1.24% 1.04%

Viking 533 2.41% 2.01%

Into MISO 1,284 5.82% 4.85%

All into MISO Total 22,079 100.00% 83.42%

Pipelines Inside MISO

Crossroads 461 10.51% 1.74%

Guardian 724 16.50% 2.74%

Horizon 353 8.04% 1.33%

KM Illinois 360 8.20% 1.36%

Midwestern 527 12.01% 1.99%

Southern Star 403 9.18% 1.52%

Vector 1,560 35.55% 5.89%

Total Inside MISO 4,388 100.00% 16.58%

TOTAL 100% MISO 26,467 100.00%

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Understanding How Capacity is Measured

Overall Pipeline System Configuration

The overall pipeline system configuration should result in a comparatively lower usage level (load factor) for downstream facilities in the “Summer Period”, defined in the natural gas industry as April 1 through October 31, but a much higher, albeit shorter term, usage level during the Winter Period, defined as November 1 through March 31. The upstream trunkline portion of the system, on the other hand, could operate at a more sustained high load factor throughout the year.

With underground natural gas storage and LNG peaking facilities configured into a natural gas pipeline system, especially one serving climate-sensitive markets such as the Midwest and Northeast, system operators can minimize the facilities and costs involved in building the “trunkline” portion of their system. Natural gas shippers, on the other hand, could avoid unnecessary costs incurred if they hold firm capacity on an entire transmission system, rather than only a portion that would be used only on a few days during the winter season.

During the non-heating season, for instance, when shippers do not need all the contracted capacity to meet their customer’s current consumption requirements, natural gas can be transported and injected into storage. By the beginning of the Winter Period, storage inventory levels are generally at their annual peak. Working gas, the portion of natural gas in storage sites available for withdrawal and delivery to markets, is then withdrawn during periods of peak demand.

In addition, the pipeline company can avoid the need to expand transmission capacity from production areas by using existing, or establishing new storage facilities in market areas where there is a strong seasonal variation in demand and where the system may be subjected to operational imbalances as shown in Figure 22 below. Storage plus firm transportation can result in the most efficient and highest load factor use of firm transportation capacity.

Overview of Pipeline Utilization

Natural gas pipeline companies prefer to operate their systems as close to full capacity as possible to maximize their revenues. However, the average utilization rate (flow relative to design capacity) of a natural gas pipeline system seldom reaches 100%. Factors that contribute to outages include:

Scheduled or unscheduled maintenance; Temporary decreases in market demand; and, Weather-related limitations to operations.

Pipeline Capacity Analysis

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Most companies try to schedule maintenance in the summer months when demands on pipeline capacity tend to be lower, but an occasional unanticipated incident may occur that suspends transmission service.

Utilization Rates Utilization rates below 100% do not necessarily imply that additional capacity is available for use. A pipeline company that primarily serves a seasonal market, for instance, may have a relatively low average utilization rate especially during the summer months. But that does not mean there is unreserved capacity on a long-term basis. On the other hand, during periods of high demand for natural gas transportation services, usage on some portions of a pipeline system may exceed 100% of certificated capacity. Certificated capacity represents a minimum level of service that can be maintained over an extended period of time and not the maximum throughput capability of a system or segment on any given day. Exceeding 100% of capacity is accomplished by secondary compression and/or line packing, which means that compression, is increased, within safety limits, to raise throughput temporarily. Pipelines, for safety reasons, generally operate the far below the range of the maximum design capacity. Integration of Storage Capacity Integrating storage capacity into the natural gas pipeline network design can increase average-day utilization rates. This integration involves moving not only natural gas currently being produced but natural gas that has been produced earlier and kept in temporary storage facilities. Storage is usually integrated into or available to the system at the production and/or consuming end as a means of balancing flow levels throughout the year. Trunklines serving markets with significant storage capacity have greater potential for achieving a high utilization rate because the load moving on these pipelines can be leveled. To the extent that these pipelines serve multiple markets, they also can achieve higher utilization rates because of the load diversity of the markets they serve. As shown in Figure 22: Generalize Natural Gas Pipeline Capacity Design Schematic, capacity from the receipt point (delivery into the pipeline) can vary significantly to delivery points (delivery out of the pipeline) due to the market area storage and how the pipeline is operated. For the purposes of this review and Analysis, the level of market area storage deliverability would have been of particular significance if there was any available excess available storage capacity or definitive plans to expand existing facilities. There are a very high number of peak flows occurring in the Summer Periods on the pipelines analyzed which means at times, Summer Period capacity is limited by storage injection schedules. Storage prospects and activities will be reviewed in detail in a following Section.

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Generalized Natural Gas Pipeline

Capacity Design Schematic

Figure 22: Generalize Natural Gas Pipeline Capacity Design Schematic.

Varying Rates of Utilization Trunklines, which are generally upstream (closer to) the natural gas production fields and storage areas, may sometimes exhibit peak period utilization rates exceeding 100% because they are occasionally capable of handling much larger volumes than indicated by the operational design certificated by FERC. Utilization on the grid systems, which are closer to the consuming market areas and downstream of the storage fields, is more likely to reflect a seasonal load profile of the market being served. The grid-type systems usually operate at lower average utilization levels than trunklines and usually show marked variation between high and low flow levels, reflecting seasonal service and local market characteristics. Measures of Pipeline Utilization There are several ways that natural gas pipeline system utilization may be estimated, as demonstrated in the following cases:

As a measure of the average-day natural gas throughput relative to estimates of system capacity at State and regional boundaries;

The system wide pipeline flow rate, which highlights variations in system usage relative to an estimated system peak throughput level; and,

A system peak-day usage rate, which generally reflects peak system deliveries relative to estimated system capacity.

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The latter measure is a good indication of how well the design of the system matches shipper peak-day needs. For example, when a pipeline shows a comparatively low average usage rate (based on annual or monthly data) yet shows a usage rate approaching 100 percent on its peak day, it indicates that the system is called upon and is capable of meeting its shipper's maximum daily needs. Nevertheless, a large spread between average usage rates and peak-day usage rates may (but not always, especially if pipeline is highly underutilized all year) indicate opportunities to find better ways to utilize off-peak unused capacity. This can be seen from TABLE 4: Pipeline Load Factors, with examples, like Pipeline 21. Understanding How Capacity is Measured in this Analysis In this analysis, we used all three methods to review and analyze capacity:

As a measure of the six year average-day natural gas throughput relative to actual system capacity at state and regional boundaries.

The system-wide pipeline flow rate at border locations38 to determine days in which capacity would have been available and would not have been available, on a daily basis from November 1, 2001 to October 31, 2011. This highlights variations in system usage relative to peak and non-peak throughput levels.

A system peak-day usage rate, which generally reflects peak system deliveries relative to actual system capacity to calculate a 6 year average Load Factor and the Load Factors for the 2010-2011 Winter Period and the 2011 Summer Period - Capacity to Load Ratios or Load Factors.

Load Factor Analysis Table 4 presents, by pipeline, load factors from a 6 year average usage relative a pipeline’s maximum capacity flows. This indicates, over time, how much capacity is being used out of the total capacity available. Additionally and for comparative purposes, the most recent 2010- 2011 annual average, seasonal and peak day load factors were calculated. 2010-2011 was somewhat of a close to normal year for most of the Midwest, but certain areas did deviate to below normal or above normal. On the whole, 2010-2011 Midwest winter was colder than normal, Winter 2010-11 weather was 2% colder than normal in Chicago, but Load Factors as a whole for that winter are generally lower than the 6 year average, although the annual mean temperature was higher than normal39. While a complete 30 year normalization study would shed additional light on this observation, it is beyond the scope of this analysis.

The load factors are indicative of capacity usage and hence, capacity availability. To test this further, a more rigorous analysis was performed. A Daily Insufficiency Analysis, “DIA”, was

38 Pipeline mainline measurement locations per Bentek Energy. 39 http://www.climatestations.com/minneapolis/

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done to determine, based on actual daily flow data, from January 1, 2005 to October 31, 2011, when capacity would have been insufficient under various scenarios. The DIA was performed as a refining analytical step after the Load Factor analysis results in Table 4, below. Both the load data and DIA are based on actual nomination data from Bentek Energy from January 1, 2005 through October 31, 2011.

TABLE 4: Pipeline Load Factors

Load Ave.% per Day 2011 Spread

Pipeline 1 Factor Available Ave. to Peak

6 Yr. Ave Annual relative to System Flow 90.69% 9.31%

11/10 - 11/11 Ave. 90.91% 9.09%

W '10 -11 95.04% 4.96%

S- 2011 86.90% 13.10%

2011 Peak Day (W) 99.47% 0.53% 8.55%

Pipeline 2

6 Yr. Ave Annual relative to System Flow 37.15% 62.85%

11/10 - 11/11 Ave. 23.04% 76.96%

W '10 -11 20.09% 79.91%

S- 2011 24.29% 75.71%

2011 Peak Day (S) 66.90% 33.10% 43.86%

Pipeline 3

6 Yr. Ave Annual relative to System Flow 52.98% 47.02%

11/10 - 11/11 Ave. 73.25% 26.75%

W '10 -11 72.85% 27.15%

S- 2011 73.54% 26.46%

2011 Peak Day (W) 86.75% 13.25% 13.50%

Pipeline 4

6 Yr. Ave Annual relative to System Flow 74.63% 25.37%

11/10 - 11/11 Ave. 70.22% 29.78%

W '10 -11 41.69% 58.31%

S- 2011 91.18% 8.82%

2011 Peak Day (W) 100.00% 0.00% 29.78%

Pipeline 5

6 Yr. Ave Annual relative to System Flow 74.81% 25.19%

11/10 - 11/11 Ave. 51.84% 48.16%

W '10 -11 36.88% 63.12%

S- 2011 62.25% 37.75%

2011 Peak Day (S) 79.23% 20.77% 27.40%

Pipeline 6

6 Yr. Ave Annual relative to System Flow 43.08% 56.92%

11/10 - 11/11 Ave. 51.59% 48.41%

W '10 -11 39.57% 60.43%

S- 2011 60.07% 39.93%

2011 Peak Day (S) 84.62% 15.38% 33.03%

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TABLE 4: Pipeline Load Factors (continued)

Load Ave.% per

Day 2011 Spread

Pipeline 7 Factor Available Ave. -Peak

6 Yr. Ave Annual relative to System Flow 79.78% 20.22%

11/10 - 11/11 Ave. 72.72% 27.28%

W '10 -11 70.97% 29.03%

S- 2011 73.95% 26.05%

2011 Peak Day (S) 86.14% 13.86% 13.42%

Pipeline 8

6 Yr. Ave Annual relative to System Flow 64.75% 35.25%

11/10 - 11/11 Ave. 76.78% 23.22%

W '10 -11 80.90% 19.10%

S- 2011 73.87% 26.13%

2011 Peak Day (W) 99.61% 0.39% 22.83%

Pipeline 9

6 Yr. Ave Annual relative to System Flow 83.72% 16.28%

11/10 - 11/11 Ave. 93.25% 6.75%

W '10 -11 92.13% 7.87%

S- 2011 93.59% 6.41%

2011 Peak Day (W) 99.43% 0.57% 6.19%

Pipeline 10

6 Yr. Ave Annual relative to System Flow 51.62% 48.38%

11/10 - 11/11 Ave. 23.76% 76.24%

W '10 -11 37.99% 62.01%

S- 2011 13.73% 86.27%

2011 Peak Day (W) 70.98% 29.02% 47.22%

Pipeline 11

6 Yr. Ave Annual relative to System Flow 79.34% 20.66%

11/10 - 11/11 Ave. 74.08% 25.92%

W '10 -11 70.92% 29.08%

S- 2011 76.31% 23.69%

2011 Peak Day (S) 96.00% 4.00% 21.92%

Pipeline 12

4 Yr. Ave Annual relative to System Flow 79.16% 20.84%

11/10 - 11/11 Ave. 94.07% 5.93%

W '10 -11 95.86% 4.14%

S- 2011 92.39% 7.61%

2011 Peak Day (W) 99.89% 0.11% 5.82%

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TABLE 4: Pipeline Load Factors (continued)

Load Ave.% per

Day Spread

Pipeline 13 Factor Available Ave. -Peak

6 Yr. Ave Annual relative to System Flow 38.33% 61.67%

11/10 - 11/11 Ave. 57.78% 42.22%

W '10 -11 69.77% 30.23%

S- 2011 49.32% 50.68%

2011 Peak Day (W) 100.00% 0.00% 42.22%

Pipeline 14

6 Yr. Ave Annual relative to System Flow 54.12% 45.88%

11/10 - 11/11 Ave. 74.69% 25.31%

W '10 -11 86.81% 13.19%

S- 2011 66.14% 33.86%

2011 Peak Day (W) 87.93% 12.07% 13.24%

Pipeline 15

6 Yr. Ave Annual relative to System Flow 53.89% 46.11%

11/10 - 11/11 Ave. 51.76% 48.24%

W '10 -11 77.47% 22.53%

S- 2011 33.44% 66.56%

2011 Peak Day (W) 96.77% 3.23% 45.02%

INTO MISO

Pipeline 16

1 Yr. Ave Annual relative to System Flow 64.48% 35.52%

11/10 - 11/11 Ave. 64.48% 35.52%

W '10 -11 37.36% 62.64%

S- 2011 60.82% 39.18%

2011 Peak Day (S) 84.91% 15.09% 20.43%

Pipeline 17

6 Yr. Ave Annual relative to System Flow 77.19% 22.81%

11/10 - 11/11 Ave. 62.01% 37.99%

W '10 -11 86.08% 13.92%

S- 2011 45.03% 54.97%

2011 Peak Day (W) 100.00% 0.00% 37.99%

Pipeline 18

6 Yr. Ave Annual relative to System Flow 67.70% 32.30%

11/10 - 11/11 Ave. 63.19% 36.81%

W '10 -11 68.74% 31.26%

S- 2011 59.05% 40.95%

2011 Peak Day (S) 93.81% 6.19% 30.62%

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TABLE 4: Pipeline Load Factors (continued)

Internal MISO Load Ave.% per Day Spread

Pipeline 19 Factor Available Ave. -Peak

6 Yr. Ave Annual relative to System Flow 19.38% 80.62%

11/10 - 11/11 Ave. 11.69% 88.31%

W '10 -11 12.13% 87.87%

S- 2011 11.31% 88.69%

2011 Peak Day (W) 27.31% 72.69% 15.61%

Pipeline 20

6 Yr. Ave Annual relative to System Flow 22.79% 77.21%

11/10 - 11/11 Ave. 33.66% 66.34%

W '10 -11 57.74% 42.26%

S- 2011 16.54% 83.46%

2011 Peak Day (W) 100.00% 0.00% 66.34%

Pipeline 21

6 Yr. Ave Annual relative to System Flow 29.62% 70.38%

11/10 - 11/11 Ave. 35.39% 64.61%

W '10 -11 36.19% 63.81%

S- 2011 34.66% 65.34%

2011 Peak Day (W) 35.41% 64.59% 0.02%

Pipeline 22

3 Yr. Ave Annual relative to System Flow 20.83% 79.17%

11/10 - 11/11 Ave. 16.67% 83.33%

W '10 -11 16.67% 83.33%

S- 2011 16.67% 83.33%

2011 Peak Day (W) 44.72% 55.28% 28.06%

Pipeline 23

6 Yr. Ave Annual relative to System Flow 33.32% 66.68%

11/10 - 11/11 Ave. 32.09% 67.91%

W '10 -11 46.46% 53.54%

S- 2011 21.95% 78.05%

2011 Peak Day (S) 87.86% 12.14% 55.76%

Pipeline 24

6 Yr. Ave Annual relative to System Flow 44.78% 55.22%

11/10 - 11/11 Ave. 38.10% 61.90%

W '10 -11 44.36% 55.64%

S- 2011 33.68% 66.32%

2011 Peak Day (W) 69.98% 30.02% 31.87%

Pipeline 25

6 Yr. Ave Annual relative to System Flow 62.69% 37.31%

11/10 - 11/11 Ave. 83.21% 16.79%

W '10 -11 99.74% 0.26%

S- 2011 72.18% 27.82%

2011 Peak Day (W) 100.00% 0.00% 16.79%

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Daily Insufficiency Analysis “DIA” Daily Insufficiency Analysis, “DIA,” was done to determine actual days, starting with April 1, 2005, when capacity would have been insufficient under various 12K and 24K Retirement scenarios or cases for the MISO-identified units without year-round firm transportation arrangements. The DIA is a means to understand on a daily level over a 6 year period, the maximum design capacity flows and actual capacity flow for Tasks 2, 3 and 6. Task 2 is to determine available capacity. Tasks 3 and 6 expand on Task 2 to identify and analyze available capacity that was being used (Task 2), and Tasks 3 and 6, identify and analyze available capacity for power generation facilities. This included determining the amount of capacity that could be available based on the MISO-identified units and on pipelines that were not identified by MISO. For pipelines that were not identified by MISO, similar criteria was used in the DIA to determine if additional CTs (46,000 dth/d) or CCs (86,000 dth/d) could be supported up to where excessive unavailable capacity days occur without firm transportation service. The term “unavailable capacity” or “N/A” is a subjective reliability call, back-up fuels such as fuel oil for some CTs, and other issues related to how the units are governed on the MISO system should be considered. For example, 30 days of unavailable capacity for a CT in the 214 days of the “Summer Period” from April 1 through October 31, is difficult to compare to 30 days of unavailable capacity for a CC in the 151 days of the “Winter Period” from November 1 through March 31. The following TABLE 5: Daily Insufficiency Analysis - Unavailable Capacity for CTs and CC’s, shows the actual number of days, by Winter Period and Summer period from April 1, 2005 though October 31, 2011, in which daily capacity would have been insufficient to meet the full delivered requirement as described in above. The following DIA Section includes the various scenarios, on a pipeline-by-pipeline basis, for the 12K and 24K Retirement cases provided by the MISO. While it may be assumed that CTs would primarily be operating in the Summer Periods, the DIA also breaks down the Winter Period to include and exclude CTs, in combination with or without CCs which are usually assumed to operate on a near year-round basis. In TABLE 5, 12K and 24K refer to the MISO Retirement cases. 46K refers to the approximate 46,000 Dth/d requirements for one CT. 86K refers to the approximate 86,000 Dth/d requirements for one CC. The described cases in addition to these references include additional requirement as combinations of the 12K and 24K cases. To the extent that there are a high number of days that indicate insufficient capacity, it is a clear indicator that the pipeline would also have to be operationally creative and flexible in managing its system to provide firm transportation services. In the section “Pipeline-by-Pipeline Specific Analyses”, there are detailed analyses of each pipeline that examines the overall pipeline and incorporates the Survey results for that pipeline.

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TABLE 5: Daily Insufficiency Analysis (“DIA”) - Unavailable Capacity for CTs and CCs

MISO-Identified Pipelines

Pipeline 1 12K 24K

Season 86 K Dth/d 172K Dth/d

N/A = Not Available Days N/A Days N/A

S - '05 2 59

W - '05-06 97 119

S- '06 2 34

W - '06-'07 38 121

S - '07 - 59

W - '07 - '08 50 96

S - '08 - 54

W - '08 - '09 20 120

S - '09 - 42

W - '09 - '10 56 118

S - '10 - 62

W - '10 - '11 86 122

S - '11 - 49

Pipeline 1 is “on the edge” to support CC in the Winter Period. Further details required.

Pipeline 2 12 K 24 K 12 K 12 K 24K

CT s and CC 86 K Dth/d

172 K Dth/d

223 KDth/d

268 KDth/d

352K Dth/d

Season CC Winter CC Winter CT & CC CT &CC ALL Units

W - '05-06 3 5 10 15 51

S- '06 0 20 77 111 211

W - '06-'07 2 2 4 5 7

S - '07 0 0 6 33 88

W - '07 - '08 1 3 5 6 8

S - '08 0 4 50 79 114

W - '08 - '09 2 3 2 3 6

S - '09 0 0 0 0 26

W - '09 - '10 0 0 2 5 10

S - '10 0 0 25 38 108

W - '10 - '11 0 0 0 0 1

S - '11 0 0 0 1 1

Pipeline 2 could have supported the units primarily in the Winter Period under the 12 K Scenario, but would have possibly faced problems as seen in the 24K Case with all units.

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Pipeline 3 46K Dth/d 92 K Dth/d 138K Dth/d

Season CT CT CT

N/A = not available Days N/A Days N/A Days N/A

W - '05-06 0 0 0

S- '06 0 0 0

W - '06-'07 0 0 0

S - '07 0 0 0

W - '07 - '08 0 0 0

S - '08 0 0 0

W - '08 - '09 0 0 0

S - '09 0 0 0

W - '09 - '10 0 0 0

S - '10 0 0 0

W - '10 - '11 0 0 0

S - '11 0 0 0

Pipeline 3 could have supported all the MISO identified units and had incremental capacity for possibly 3 additional units.

Pipeline 4 46K Dth/d 92K Dth/d

Season CT CT

N/A = not available N/A N/A

W - '05-06 3 8

S- '06 >40 >60

W - '06-'07 9 14

S - '07 >50 >80

W - '07 - '08 6 9

S - '08 >75 >120

W - '08 - '09 4 6

S - '09 >45 >90

W - '09 - '10 - 2

S - '10 116 167

W - '10 - '11 12 22

S - '11 68 89

Pipeline 4 would not have had enough capacity to support CT, without the required construction to provide firm transportation.

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Pipeline 5 Scenario 1 Scenario 2 Scenario 3

Scenario (12 & 24k) 46K Dth/d 178K Dth/d 310 K Dth/d

CT and CC N/A N/A N/A

Season Days Days Days

S - '05 8 168 214

W - '05-06 33 97 136

S- '06 - 105 200

W - '06-'07 13 25 61

S - '07 - 44 178

W - '07 - '08 - 1 4

S - '08 - 46 154

W - '08 - '09 - 3 4

S - '09 - 1 33

W - '09 - '10 - 2 2

S - '10 2 18 42

W - '10 - '11 - - -

S - '11 - - -

Pipeline 5 would have had sufficient capacity to support the Scenario 2, 12 K case of 178,000 Dth/d or 3 CTs (138,000 Dth/d), but not 3 CTs and 2 CCs (310,000 Dth/d) without construction upgrades to provide firm transportation.

Pipeline 6

46 K 12 K 46K Dth/d

Season N/A

CT Days

S - '05 -

W - '05-06 -

S- '06 -

W - '06-'07 1

S - '07 -

W - '07 - '08 2

S - '08 5

W - '08 - '09 -

S - '09 -

W - '09 - '10 1

S - '10 7

W - '10 - '11 -

S - '11 2

Pipeline 6 would have had sufficient capacity to support CT. There is capacity for another CT which would have been possible but with limited interruptions the Summer Period.

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Pipeline 7 46K Dth/d 86K Dth/d 132K Dth/d

12K: CT CC CT CC 12K CT & CC

Season

N/A N/A N/A

S - '05 - - -

W - '05-06 - - -

S- '06 1 8 46

W - '06-'07 5 27 41

S - '07 3 10 18

W - '07 - '08 15 17 31

S - '08 17 18 33

W - '08 - '09 7 92 120

S - '09 20 34 36

W - '09 - '10 - - -

S - '10 - - -

W - '10 - '11 - - -

S - '11 - -

Pipeline 7 has had sufficient capacity since late 2009. Both CT and CC under the 12K case have sufficient capacity. There is sufficient capacity for 2 additional CTs or a CC. There is about 120,000 Dth/d of additional capacity.

Pipeline 8

CT & CT 46K Dth/d 92 K Dth/d

Season NA Days NA Days

S - '05 - -

W - '05-06 - -

S- '06 - -

W - '06-'07 13 15

S - '07 3 3

W - '07 - '08 5 12

S - '08 1 3

W - '08 - '09 23 35

S - '09 - -

W - '09 - '10 3 8

S - '10 8 11

W - '10 - '11 10 20

S - '11 3 3

Pipeline 8 would have interrupted one CT the Summer Period without construction upgrades for firm capacity. The addition of another CT would double the interruptions in Winter Period.

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Pipeline 9 would not have had excess capacity for the two CCs. It could not and cannot take extra capacity without significant capacity additions, regardless of lateral construction.

Pipeline 10 46 K Dth/d 86K Dth/d 92K Dth/d 178k Dth/d

CT & CC Days N/A Days N/A Days N/A Days N/A

Season CT CC CT CT & CC

S - '05 - - - -

W - '05-06 28 41 43 69

S- '06 7 10 12 19

W - '06-'07 18 31 32 47

S - '07 - 1 1 7

W - '07 - '08 42 45 46 48

S - '08 - - - -

W - '08 - '09 - - - -

S - '09 - - - -

W - '09 - '10 - - - -

S - '10 - - - -

W - '10 - '11 - - - -

S - '11 - - - -

Pipeline 10 had sufficient firm capacity for a CC on a year-round basis. But, to ensure 100% firm delivery to two CTs, No. 10 confirmed there would be additional construction costs above those indicated in the No. 10 Survey response. The location of the CTs would have been restricted during the Winter Period and a firm commitment would require upgrades.

Pipeline 9

CC 86 K Dth/d 170K Dth/d

Season N/A N/A

Days Days

S - '05 34 81

W - '05-06 19 61

S- '06 33 81

W - '06-'07 17 51

S - '07 47 108

W - '07 - '08 66 96

S - '08 17 18

W - '08 - '09 33 51

S - '09 - 2

W - '09 - '10 14 31

S - '10 79 153

W - '10 - '11 55 89

S - '11 45 163

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Pipeline 11 One CT 12K Case 24K Case

CT N/A N/A N/A

CT (12K) 46 K Dth/d 92 K Dth/d 138K Dth/d

Season CT CT CT

S - '05 - - -

W - '05-06 - - -

S- '06 - 4 26

W - '06-'07 1 12 22

S - '07 - - -

W - '07 - '08 - 7 17

S - '08 4 11 35

W - '08 - '09 2 26 45

S - '09 1 17 32

W - '09 - '10 - - -

S - '10 - - -

W - '10 - '11 - - -

S - '11 1 7 12

Pipeline 11 would have had sufficient capacity since 2009 for two CTS (12K & 24K). There was a potential for up to 12 days of insufficient days in the summer period in 2011, but otherwise no insufficient days since May 2009.

Pipeline 12 12 K Case 24 K Case

CT 46 KDth/d 92 K Dth/d

Season N/A N/A

Days Days

S - '05 50 95

W - '05-06 50 87

S- '06 50 92

W - '06-'07 50 103

S - '07 100 110

W - '07 - '08 50 115

S - '08 49 103

W - '08 - '09 49 76

S - '09 50 75

W - '09 - '10 49 50

S - '10 181 187

W - '10 - '11 111 127

S - '11 138 154

No. 12 lacks capacity to serve one CT without construction and firm transportation. Also, No. 12 would have to be creative in adjusting its operations to ensure firm deliveries.

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Pipeline 13 12K 12K 24K case

46 K Dth/d 92K Dth/d 138K Dth/d

C T CT CT (12K) CT (24K)

Season Days CT CT

S - '05 - - -

W - '05-06 - - -

S- '06 - - -

W - '06-'07 1 3 6

S - '07 - - -

W - '07 - '08 4 4 4

S - '08 - - -

W - '08 - '09 4 4 4

S - '09 - - -

W - '09 - '10 - - -

S - '10 - - -

W - '10 - '11 20 32 53

S - '11 - - 3

Pipeline 13 had sufficient capacity for a CT although the recent winter had 20 days N/A. Prior winters averaged 200,000 Dth/d of extra capacity.

Pipeline 14 12K Case 12 K Case 24K Case

Season 46K Dth/d 92 KDth/d 138K Dth/d

CT(12&12K) CT CT CT

N/A - Not available N/A N/A

S - '05 - - -

W - '05-06 - - -

S- '06 - - -

W - '06-'07 - - -

S - '07 - - -

W - '07 - '08 - - -

S - '08 - - -

W - '08 - '09 - - -

S - '09 - - -

W - '09 - '10 - - -

S - '10 - - -

W - '10 - '11 7 25 41

S - '11 - - -

Pipeline 14 had sufficient capacity for CT (12K and 24K). The 2010-11 Winter Period was the first winter since 2005 that capacity would have been restricted. The Summer Period has more than 300,000 Dth/d of extra capacity, on average.

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Pipeline 15 46 KDth/d 92 K Dth/d

CT and CT N/A N/A

Season Days Days

S - '05 - 1

W - '05-06 - 13

S- '06 - 3

W - '06-'07 - 103

S - '07 - 200

W - '07 - '08 67 145

S - '08 134 213

W - '08 - '09 62 144

S - '09 - 10

W - '09 - '10 85 100

S - '10 15 37

W - '10 - '11 55 144

S - '11 - -

Pipeline 15 does not have sufficient capacity for two CTs, individually or together in either the Summer or Winter Periods.

INTO MISO - No MISO-Identified Units

Pipeline 16 46 K Dth/d 92 K Dth/d

One or two CTs Days N/A Days N/A

S – ‘05 n/a n/a

W – ‘05-06 n/a n/a

S- ‘06 n/a n/a

W – ‘06-‘07 n/a n/a

S – ‘07 n/a n/a

W – ‘07 – ‘08 n/a n/a

S – ‘08 n/a n/a

W – ‘08 – ‘09 n/a n/a

S – ‘09 n/a n/a

W – ‘09 – ‘10 n/a n/a

S – ‘10 n/a n/a

W – ‘10 – ‘11 - 3

S – ‘11 - 4

Pipeline 16 had an average of about 100,000 Dth of extra capacity for 2 CTs or 1 CC.

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Pipeline 17 46 K Dth/d

Season Days N/A

S - '05 40

W - '05-06 140

S- '06 70

W - '06-'07 113

S - '07 95

W - '07 - '08 100

S - '08 75

W - '08 - '09 76

S - '09 64

W - '09 - '10 3

S - '10 89

W - '10 - '11 98

S - '11 71

Pipeline 17 is severely constrained and had no additional capacity.

Pipeline 18 46 K Dth/d 86 K Dth/d

1CT or 1CC Days N/A Days N/A

S - '05 7 31

W - '05-06 20 38

S- '06 15 23

W - '06-'07 39 56

S - '07 - 7

W - '07 - '08 53 99

S - '08 - 12

W - '08 - '09 11 33

S - '09 - 4

W - '09 - '10 33 52

S - '10 9 58

W - '10 - '11 21 42

S - '11 - 4

Pipeline 18 is severely constrained in the winter but would have had has sufficient capacity in the summer to support up to one CTs with up to 15 days of insufficient capacity since 2005. Major mainline capacity expansion would be required for a CC operation.

68

Internal MISO Pipelines - No MISO-Identified Units

Pipeline 19 46K

Dth/d 86K

Dth/d

One CT or CC N/A N/A

Days Days

S - '05 - -

W - '05-06 - -

S- '06 - -

W - '06-'07 - -

S - '07 - -

W - '07 - '08 - -

S - '08 - -

W - '08 - '09 - -

S - '09 - -

W - '09 - '10 - -

S - '10 - -

W - '10 - '11 - -

S - '11 - -

Pipeline 19 had sufficient capacity is available from its upstream pipelines. On average it has up to 15,000 Dth/d of extra capacity in winter and over 300,000 Dth/d extra in summer.

Pipeline 20 46K

Dth/d 86K

Dth/d

One CT or CC N/A N/A

Days Days

S - '05 - -

W - '05-06 - -

S- '06 - -

W - '06-'07 - -

S - '07 - -

W - '07 - '08 - -

S - '08 - -

W - '08 - '09 - 2

S - '09 - -

W - '09 - '10 1 2

S - '10 - -

W - '10 - '11 4 9

S - '11 - -

Pipeline 20 had sufficient capacity in the summer (over 500,000 Dth/d extra) and limited days of insufficient capacity in the winter (up to 9) for a 86,000 Dth/d CC facility or 2 CTs.

69

Pipeline 21 46k Dth/d 86K Dth/d

One CT or CC N/A N/A

Days Days

S - '05 - -

W - '05-06 - -

S- '06 - -

W - '06-'07 - -

S - '07 - -

W - '07 - '08 2 2

S - '08 - -

W - '08 - '09 1 3

S - '09 - -

W - '09 - '10 - -

S - '10 - -

W - '10 - '11 - -

S - '11 - -

Pipeline 21 had sufficient capacity in the summer (over 220,000 Dth/d extra) and sufficient capacity in the winter with a low number of insufficient days. No. 21 depends on upstream capacity from delivering pipelines.

Pipeline 22 46K Dth/d 86k Dth/d

One CT or CC N/A N/A

Days Days

S - '05 - -

W - '05-06 - -

S- '06 - -

W - '06-'07 - -

S - '07 - -

W - '07 - '08 - -

S - '08 - -

W - '08 - '09 - -

S - '09 - -

W - '09 - '10 - -

S - '10 - -

W - '10 - '11 - -

S - '11 - -

Pipeline 22 had over 150,000 Dth/d of extra capacity, year-round if upstream pipelines have supply delivery capability it could handle 2 CCs or 3 CTs.

70

Pipeline 23 46 K Dth/d 86K Dth/d

One CT & one CC N/A N/A

Season One CT One CC

S - '05 - -

W - '05-06 - -

S- '06 - -

W - '06-'07 - -

S - '07 - -

W - '07 - '08 - -

S - '08 - -

W - '08 - '09 - 1

S - '09 1 11

W - '09 - '10 - -

S - '10 - -

W - '10 - '11 - 11

S - '11 3 7

Pipeline 23 had over 200,000 Dth/d on average in the summer and on most days, enough to be able to serve at least 3 summer CTs, if upstream supply is delivery is available.

Pipeline 24 46 K Dth/d 92 K Dth/d

One or Two CTs N/A N/A

Season Days Days

S - '05 - 4

W - '05-06 - -

S- '06 - -

W - '06-'07 - 2

S - '07 - 13

W - '07 - '08 2 12

S - '08 - -

W - '08 - '09 - -

S - '09 1 3

W - '09 - '10 4 4

S - '10 - -

W - '10 - '11 - -

S - '11 - -

Pipeline 24 on average had over 150,000 Dth/d of extra capacity in the summer and most days considerable more to be able to serve at least 3 CTs in the summer. Winter could support additional CTs with limited interruptions.

71

Pipeline 25 46 K Dth/d 86 K Dth/d

One CT or CC N/A N/A

Season Days Days

S - '05 - -

W - '05-06 - -

S- '06 - -

W - '06-'07 - -

S - '07 - -

W - '07 - '08 -

S - '08 - -

W - '08 - '09 40 68

S - '09 - -

W - '09 - '10 12 28

S - '10 - -

W - '10 - '11 77 139

S - '11 - -

Pipeline 25 had very limited winter period capacity, but, on average has over 300,000 Dth/d of extra summer capacity. Pipeline 25 had sufficient capacity for at least 5 summer period operating CTs. Pipeline 25 is dependent on upstream pipeline capacity, End of TABLE 5: Daily Insufficiency Analysis - Unavailable Capacity for CTs and CC’s

72

MISO-Identified Pipelines Investment Costs

Infrastructure investment costs projects for the MISO-identified units in the 12K and 24K scenarios are based on several factors:

1) Actual cost calculations by each respective pipeline for the Units (CTs and/or CCs) assigned to their pipelines, as provided in detail from the MISO Survey responses;

2) General industry information or cost analyses estimates from recognized sources such as the FERC, INGAA, etc.;

3) Application of a combination of averages derived from #1, above, as a comparison to #2. Then reasoned application of the average costs to hypothetical units on the pipelines identified in this Analysis that could be installed in those pipelines based on the DIA analysis.

This cost analysis should be considered as an effort to determine general costs for the application in #3, above. In determining the cost of a pipeline lateral to a facility, pipeline companies select the appropriate equipment for a particular service based on both technical (e.g., flow, pressure ratio, utilization, efficiency) and commercial considerations (e.g., delivered cost, contractual underpinning, etc.). Also, each pipeline system is the unique result of its age, geographic location, original design, subsequent modifications, and shifting supply/demand patterns. As a result, technologies that may improve efficiency or may be cost effective on one pipeline system may not be feasible or economic on another pipeline system. A “one-size-fits-all” approach to transportation efficiency targets or technology prescriptions, such as mandatory efficiency targets or forced adoption of specific technologies, therefore is not practical. The weight given to these criteria varies from pipeline to pipeline and from application to application. What may improve system efficiency or be cost-effective on one pipeline system may not be cost-effective or practical on another system. Therefore, there is no one-size-fits-all efficiency prescription that will yield desired efficiency improvements on all pipeline systems. With regard to compression horsepower, the installed cost of a compressor unit may vary significantly depending upon whether it is a greenfield installation (i.e., a brand new compressor station), an additional compressor unit installed at an existing station, or the replacement of an existing compressor unit with a state-of-the-art unit. Generally, an additional compressor at an existing station is the least expensive option, followed by a state-of-the-art replacement unit and lastly, a greenfield unit is the most expensive option40.

40 Interstate Natural Gas Pipeline Efficiency, INGAA, Washington, D.C., October 2010. p36.

Pipeline Infrastructure and Investment Costs

73

TABLE 6: Estimate for Initial Cost on Site of Compression below compares the upfront capital cost of various compressors and prime movers for a 14,400 horsepower compressor replacement project in 2010. Typically, installed costs for a mid-sized natural gas compressor powered by a combustion turbine at a Greenfield location is $2,500 to $3,500 per horsepower41

TABLE 6: Estimate for Initial Cost on Site of Compression In the cost analysis based on the results of the MISO survey, as shown below in TABLE 7: Total Estimated Construction Costs for Most MISO Units, the costs and related cost input information from the all pipelines was used to calculate and average cost per mile of $2.82 Million per mile (16”). Where cost information from a Pipeline was not provided, the average cost per mile of $2.82 Million per mile (16’) was applied to their respective unit’s distance to calculate their costs. A range of costs was necessary because several pipelines provided cost ranges as shown below on Table 7: Total Estimated Construction Costs for All MISO Units. The total pipeline lateral cost estimates are in a range of $920.64 to $1,097.80 Million.

TABLE 7 Low Range High Range

$ Millions $ Millions

Pipeline 1 $40.00 $195.00

Pipeline 2 $118.20 $118.20

Pipeline 3 $35.50 $35.50

Pipeline 4 $3.37 $10.35

Pipeline 5 $40.00 $40.00

Pipeline 6 $53.40 $53.40

Pipeline 7 $21.40 $21.40

Pipeline 8 $21.40 $64.00

Pipeline 9 $205.90 $205.90

Pipeline 10 $52.00 $52.00

Pipeline 11 $92.50 $92.50

Pipeline 12 $53.40 $53.40

Pipeline 13 $87.00 $87.00

Pipeline 14 $71.07 $43.65

Pipeline 15 $25.50 $25.50

Total $920.64 $1,097.80

41 Ibid.

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The average of the range for construction costs for the MISO-identified pipelines is $1,009.22 million or about $1.0 Billion. This number is fairly precise compared to national estimates or estimates based on a “one-size-fits-all” type of analysis that uses “rules of thumb”. These estimates are estimated, with engineering inputs, by the pipelines themselves.

Another observation is the INGAA projected cost of mainline pipe and compression for the

years 2011- 2020 with regard to this Analysis’ identification of additional mainline and compression requirements on Pipeline 1, Pipeline 2 and Pipeline 3.

This Analysis’ average pipeline cost of $2,820,000 per mile for a 16-inch diameter lateral line, which equates to $176,250 per inch-mile. According to a recent study by Ziff Energy, the present national average inch-mile cost is about $188,00042. Using Ziff’s industry average of $188,000 per inch-mile, a 16-inch diameter pipeline at a cost of $188,000 per inch-mile would cost $3,008,000, which is fairly close to this Analysis, but of course, that is a national average.

To provide clarity, a 24-inch diameter pipeline at a cost of $100,000 per inch-mile would cost $2,400,000 per mile. Nonetheless, there are additional costs that the Pipelines’ cost estimates do not include and these would be additional mainline upgrades on upstream interconnecting pipelines that a have insufficient capacity. These additional costs to support downstream pipelines from upstream pipelines would require consideration of millions of more dollars in additional costs. Likewise, several pipelines have stated that there would be substantial costs above the lateral costs indicated above to guarantee firm service. Other pipelines indicated that major compression and looping projects to support year-round firm service to MISO-identified facilities would be in the hundreds of millions of dollars, also. For comparative purposes, at the Pipeline Z’ Customer Meeting on 2011, Pipeline Z revealed that is studying the potential to extend its mainline pipeline to existing pipelines at a cost of approximately $450 to $600 million depending on volume. While each pipeline’s operations are unique and expansion projects require extensive and detailed costs analyses, a general review of recent looping and compression projects that have been approved by the FERC or reported in industry journals43 over the last 3 years indicate that to provide the type of incremental capacity envisioned by several of the pipelines analyzed herein that individual projects costs average in the $250 to $350 million range. At the Seventh Annual Pipeline Opportunities Conference (O&GJ and INGAA) on April 19, 2011, David Scharf, ONEOK’s V.P., Gas Gathering and Processing, spoke to that company’s plans for development in the Bakken shale region and stated that, “While this is a relatively

42 Bang for the Buck – Ziff Energy’s Pipeline Cost Report, Pipeline News, July 29, 2011. 43

PennWells’ Oil and Gas Financial Journal and Oil and Gas Journal, Jan. 2009 – Jan. 2012.

75

small gas play, ONEOK is spending $1.6 Billion in projects to accommodate just the gas in this basin alone.” Not only projects from the Bakken shale, but early indications of activity for projects to move Appalachian Marcellus shale gas westward are gaining traction.44 Also, while details are very limited at this point, Ziff Energy research indicates at least two additional projects may be in the works to move Appalachian Marcellus shale gas westward through and past Clarington, Ohio into Michigan. The most likely pipelines in the region to be involved with projects of this nature would be Columbia Gas Transmission, DTI, Panhandle Eastern (PEPL), ANR, Spectra (Texas Eastern or “Tetco”) and/or DTE Energy with a producer(s). As shown below in Figure 23: Potential Marcellus Pipeline Expansions, these types of regional pipeline projects would not only bring increased supply into the MISO region, but would have the further effect of altering pipeline flows in the MISO region. Conceptually, moving natural gas westward would “push-backwards” (backhaul) gas supplies on PEPL, REX, Tetco and/or ANR from their current west-to-east flow patterns. This may also require these pipelines to add incremental facilities to serve new MISO region market opportunities, particularly gas-fired power generation.

Potential Marcellus Pipeline Expansions

Source: Ziff Energy Group, 2011

Figure 23: Potential Marcellus Pipeline Expansions45

44 Spectra (Tetco), American Electric Power and Chesapeake Energy’s Ohio Pipeline Energy Network (OPEN) project to move gas west (via backhaul) to Ohio. 45 An extensive search did not produce any specific references to Ziff’s noted Ohio westward projects. However, the idea is plausible based on public information from Spectra and others. Also, a large number of westward NGL and other “liquids” projects from companies like Enbridge, Enterprise, etc., are underway from Appalachia to Chicago and Patoka, IL (a southern IL oil hub trading hub). These expanding ”Rights of Ways” projects are conducive and attractive to natural gas pipelines.

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It is conceivable that the cost to accommodate projects like the ones above could easily top $2.0 Billion in addition to the $1.0 Billion in lateral costs. Current growth in the shale gas basins, from the Bakken to the Marcellus, need infrastructure outlets sooner than later because of the extensive over-supply that is anticipated over the next three years. It is possible that the changes discussed herein could necessitate these types of infrastructure projects in the 2012 – 2016 time frame as the supply “bubble” comes into equilibrium with forecasted power generation demand growth. Additionally, these types of projects would also increase the need for additional gas storage in Michigan, Ontario, Ohio, Pennsylvania and West Virginia. From the “push-backwards” perspective, this could also cause repercussions for increased storage development in Illinois and Indiana. These incremental costs are supported by the INGAA study as shown below in Figure 26: Expenditures for New Gas Storage Capacity (Billions of 2010$). The large cost forecasted for aquifer-gas storage in the Midwest and Central regions point directly at Illinois, Indiana, Iowa, Minnesota, Wisconsin and northern Kentucky, were aquifer geology is predominant, as shown further on in Figure 27: U.S. Natural Gas Storage Facilities. Natural Gas Industry Infrastructure Investment Costs Natural gas pipeline companies’ interstate pipeline projects are based on shippers’ willingness to sign long‐term contracts for natural gas transportation, not on the assumption that there will be a future market for natural gas transportation. The shippers’ commitment is needed to raise capital for a project to demonstrate a long-term revenue stream. Also, the Federal Energy Regulatory Commission (“FERC”) is legally required to rule as to the need for a pipeline before it can issue a certificate authorizing the construction and operation of a proposed project. It is easy to see that pipelines are not going to make the capital investments necessary simply by a forecast or a projection of future demand for the capacity. The pipeline industry trade organization, INGAA, has recently conducted recent studies46 47that have determined that, for North America, from January 2000 through February 2011, the interstate pipeline industry paid approximately $46 billion for 14,600 miles of interstate pipeline that added 76.4 Bcf/d of capacity. Industry investments in pipeline infrastructure equaled or exceeded $8 billion per year in three of the past four years. INGAA forecasts that the industry is poised, to add over 43 Bcf/d of new gas transmission capacity over the next 25 years to meet demand. This equates to approximately 1,400 miles per year of new natural gas mainline; 600 miles per year of new laterals to/from natural gas-

46 Natural Gas Pipeline and Storage Infrastructure Projections Through 2030, October 20, 2009 Submitted to: The INGAA Foundation by ICF International. 47

North American Natural Gas Midstream Infrastructure Through 2035: A Secure Energy Future - Updated Supply‐Demand Outlook”, June 28, 2011, prepared by ICF International for the INGAA foundation.

77

fired power plants, processing facilities, and storage fields; 24 Bcf per year new working gas in storage; and 197,000 horsepower per year for pipeline compression. INGAA projects that in North America as a whole, approximately $205 Billion over the 25 year time frame, 2011 – 2035 will be required for additional infrastructure, as shown below on regional breakout in Figure 24: Regional Gas Infrastructure Capital Requirements for 2011 to 2035.48 Of this amount, the infrastructure capital requirements from 2011 to 2035 for the Midwest Region (mostly MISO) is approximately $388 million per year, or about $9.7 billion or 5.0% of the total. Of that amount, according to INGAA, lateral construction capital requirements are forecast to be approximately $2.7 Billion. This Analysis has reviewed the INGAA Study’s analysis of the Central and Midwest regions and analyzed their finding in terms of the MISO region and how their analysis compares to the MISO region specifically. Interestingly, the cost comparisons are similar, however, this Analysis takes exception with the INGAA Study time frame. This Analysis, based on specific discussions with MISO-identified pipelines, comparable mainline and lateral expansion projects costs, NGL and oil production from shales and associated gas production projects and MISO-specific 12K and 24K retirement scenarios, estimates that infrastructure costs (including storage requirements) are likely to be near $3+Billion from 2012 to 2016 and considerably more through 2030.

Regional Gas Infrastructure Capital Requirements for

2011 to 2035 (Billions of 2010$)

Source: “Natural Gas Pipeline and Storage Infrastructure Projections Through 2030”

October 20, 2009 and updated for the INGAA Foundation by ICF International

Midwest = $9.7 Billion

Figure 24: Regional Gas Infrastructure Capital Requirements for 2011 to 2035

48

Ibid.

78

By comparison, as shown below in Figure 24: Regional Gas Infrastructure Capital

Requirements for 2011 to 2020, of the projected $98.3 Billion, the Midwest Region, capital requirements account for $4.5 Billion or 5.0% of the total.

Regional Gas Infrastructure Capital Requirements for

2011 to 2020 (Billions of 2010$)

Source: “Natural Gas Pipeline and Storage Infrastructure Projections Through 2030”

October 20, 2009 and updated for the INGAA Foundation by ICF International

Midwest = $4.5 Billion

Figure 25: Regional Gas Infrastructure Capital Requirements for 2011 to 2020

The following TABLE 8 shows are side-by-side comparison to INGAA’s projected incremental infrastructure costs for two forecast periods.

TABLE 8: Comparison of INGAA Midwest Region 2020 and 2035 Infrastructure Costs

2011 – 2035 2011 – 2020

Storage: $0.2 Billion Storage: $0.0 Billion Gas Plant: $0.2 Billion Gas Plant: $0.1 Billion Lateral Pipe: $2.7 Billion Lateral Pipe: $1.2 Billion Gathering: $0.5 Billion Gathering: $0.2 Billion Mainline Pipe & Mainline Pipe & Compression: $6.1 Billion Compression: $3.0 Billion Total: $9.7 Billion Total: $4.5 Billion

The INGAA forecast for the lateral pipeline infrastructure costs is significantly close to this Analysis cost average of $1.0 Billion. Another observation that is interesting is that the INGAA capital requirements for new storage pipeline capacity infrastructure is estimated to be $0.0 for the period 2011 – 2020 and the expenditures for storage capacity, as shown in Figure 26: Expenditures for New Gas Storage Capacity is estimated to be only $0.2 billion in the 2011-2035 INGAA forecast. This is an indicator that the INGAA study assumes that future storage

79

capacity expansion will come from existing certified storage fields or that the storage pipeline infrastructure requirements are negligible. 49

Expenditures for New Gas Storage Capacity

(Billions of 2010$)

Source: “Natural Gas Pipeline and Storage Infrastructure Projections Through 2030”

October 20, 2009 and updated for the INGAA Foundation by ICF International

49

The INGAA forecast indicates is that there were no additional storage capacity additions in the forecast period 2011- 2020. The MISO Survey revealed that none of the MISO identified pipelines had concrete plans for additional storage development in the near term or but are considering the need for such projects over the next few years. This will change as westward-looking projects from the Appalachian Utica and Marcellus shales develop.

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The MISO region has about 25% of the U.S. Working Gas capacity of approximately 4 TCF (4,000 Bcf). Working Gas capacity is the actual amount of gas that customers inject and withdraw from storage for their needs. Total capacity is the total amount of gas in underground storage. The difference is “base gas” or “cushion gas” that is permanently in the storage reservoir to maintain the storage field pressures.

TABLE 9: MISO Region Underground Storage Companies

Company Capacity

(Bcf) Capacity Percent

Working Gas (Bcf)

Working Gas

Percent

ANR 315.94 15.92% 190.17 19.09%

Blue Lake GSC 54.12 2.73% 47.09 4.73%

Blue Water GS 31.32 1.58% 25.70 2.58%

CenterPoint MRT 138.97 7.00% 71.40 7.17%

NGPL 612.66 30.86% 276.99 27.80%

NNG 216.55 10.91% 88.92 8.92%

Southwest GSC (IL&MI) 82.20 4.14% 22.17 2.23%

Texas Gas 179.87 9.06% 80.60 8.09%

WBIP 353.35 17.80% 193.35 19.41%

Wabash (on MGC) TBD TBD 14.00 1.41%

Total 1,984.98 100.00% 996.39 100.00%

Storage facilities are generally owned by the pipeline to which they are attached, however, this is not always the case because independent storage companies can develop their own facilities on a respective pipeline, such as the Wabash Gas Storage project on Midwestern Gas Company. Pipelines are required to allow transportation in and out of a storage facility under the FERC regulations governing open-access, non-discriminatory transportation. The other storage facilities above, with the exception of Wabash and Bluewater, are affiliates of pipelines in the MISO region. Blue Lake is located in the northern part of the lower peninsula of Michigan and is an affiliate of ANR and Great Lakes which are owned by TransCanada. This facility is located on ANR’s system and enhances ANR’s system flexibility to manage deliveries to the MISO-identified facilities on ANR and the Great Lakes systems. Southwest Gas Storage is an affiliate of Panhandle Eastern with underground natural gas storage facilities in Meade County, Kansas; Woods County, Oklahoma; Morgan and Sangamon Counties, Illinois; and in Livingston and Washtenaw Counties, Michigan. The Illinois and the Michigan facilities assist Panhandle in providing firm delivery flexibility in the MISO region. Southwest Gas Storage offers both firm and interruptible storage service at in its east area and west area, with a total working storage capacity of approximately 60.9 Bcf on Panhandle as a whole, but only 22.17 Bcf in the MISO region and market area.

Natural Gas Storage Serving the MISO Region

81

Bluewater Gas Storage, LLC, based in Columbus, Michigan, is a subsidiary of an oil pipeline, Plains All American Pipeline, L.P. The company offers seasonal storage services and leases third-party storage capacity and pipeline transportation capacity. Bluewater’s customers consist primarily of pipelines, utilities and marketers seeking seasonal storage services. Bluewater is located on ANR, but has 30-mile, 20-inch diameter pipeline header system that connects with three interstate and three intrastate natural gas utility pipelines in Michigan. MRT has system working gas capacity which includes the states of OK, LA of 71.40 Bcf, however, only 1.6 Bcf physically located in the MISO region and market area. MRT, however, utilizes all of its storage capacity in serving loads on its system including into the MISO region. All of the MISO Region underground storage facilities are either depleted fields or aquifer-based as shown below in Figure 27: U.S. Natural Gas Storage Facilities. There are distinct economic and geological characteristics of these types of fields that limit the customers’ ability to demand injection and withdrawal of their working gas supplies.

U.S. Natural Gas Storage Facilities

Source: EIA Figure 27: U.S. Natural Gas Storage Facilities

Storage deliverability in the MISO Region could face an infrastructure constraint because of the geology for storage in the region. Natural gas-fired power generation relies on high-deliverability storage. As shown in Figure 28: Underground Storage Comparison, the MISO region storage is limited to aquifer and depleted oil/gas reservoirs that have seasonal injection and withdrawal cycles versus salt cavern storage which has high-deliverability cycling. Pipelines can have some level of flexibility on injection and withdrawals within a season, but generally, the seasonal schedules must by fairly strict physical requirements and by tariff conditions. This is another area that pipelines need to “rethink” their operations in

82

providing flexibility to power generators. At present, almost all firm storage capacity on the pipelines in the MISO regional is fully-subscribed. While interruptible storage and flexible parking and lending services are available on the pipelines, incremental firm storage capacity would be required. Such facilities would require substantial costs and several years to complete.

Underground Storage Comparison

Source: FERC Staff Report “Underground Storage”

Figure 28: U.S. Natural Gas Storage Facilities

New Storage in MISO Area Since 2000 Since 2000, there have been eleven (11) FERC-certificated projects in the MISO region adding 92.35 Bcf (9.2%) of working gas capacity out of a total working gas capacity of 996.39 Bcf, as shown below in Figure 29: Certified Storage Projects Since 2000:

Certified Storage Projects Since 2000

Source: FERC Office of Pipeline Projects

Expansion of New Capacity

83

1. ANR Pipeline Company (Storage Realignment Project) in Lapeer Cty, MI (Map # 14), 4.1 Bcf Working Gas Capacity, CP04-79, Order date: 8/9/2004

2. Bluewater Gas Storage, LLC , in St. Clair, Macomb Cty. MI, (map # 31), 29.2 Bcf

Working Gas Capacity CP06-351, Order date: 10/27/2006

3. ANR Pipeline Company (STEP 2007), in Kalkaska Cty, MI, (map # 32), 17 Bcf Working Gas Capacity CP06-358, Order date: 11/22/2006

4. ANR Pipeline Company (Storage Enhancement Project -2008) in Kalkaska Cty, MI (map

# 39), 14.7 Bcf Working Gas Capacity, CP06-464, Order Date: 5/31/2007

5. Northern Natural Gas Company Redfield Expansion in Dallas Cty, IA, (map # 42), 2 Bcf Working Gas Capacity CP06-461, Order Date: 7/1/2007

6. Northern Natural Gas Company (Redfield Proposal) in Dallas Cty, IA (map # 53), 8 Bcf

Working Gas Capacity, CP07-108, Order Date: 3/12/2008

7. Natural Gas Pipeline Company of America (2009 Storage Expansion Project) in Kankakee Cty, IL, (map # 60), 10 Bcf Working Gas Capacity, CP08-32, Order Date: 8/11/2008

8. Kinder Morgan Interstate Gas Transmission LLC (Hunstman 2009 Expansion Project)

Cheyenne Cty. NE (map # 76), 1.2 Bcf Working Gas Capacity, CP09-109, Order Date: 9/30/2009

9. Texas Gas Transmission, LLC in multiple Counties in KY, IN (map # 88), 4.1 Bcf Working

Gas Capacity, CP10-255, Order Date: 9/16/2010

10. Natural Gas Pipeline of America LLC, Louisa Cty, IA (map # 92), 0.5 Bcf Working Gas Capacity, CP10-452, Order Date:10/21/2010

11. Northern Natural Gas Storage, LLC in Dallas Cty, IA (map # 97), 2 Bcf Working Gas

Capacity, CP10-449, Order Date: 3/30/2011

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Future Gas Storage Development A number of studies have been conducted recently that have identified the need for natural high deliverability gas storage development for power generators. However, only the Wabash project (aquifer geology rework project) is scheduled to begin service in 2013. From the Survey responses, some of the pipelines have indicated that they are considering storage development, but, because of the highly competitive nature of these projects to financial hedging and low gas costs, potential new pipeline services from competing pipelines and EPA uncertainties, there is a reluctance to divulge any plans. The only other alternative is above-ground liquefaction and re-gasification LNG facilities. Market indicators, however, point to the need to develop the least-desirable MISO-region aquifer-based gas storage for backhaul management on pipelines impacted by the Marcellus and Utica shale developments as discussed above. Aquifers are more costly than depleted oil/gas reservoirs. There is less known geologically about them than depleted oil/gas reservoirs. They have a lower working gas to base gas ratio also. They are the most costly form of underground storage with a large fixed-cost base gas requirement compared to working gas profitability. They are generally restricted to seasonal injection and withdrawal cycles and they are the least-desirable geologically-based storage option for power generators. As an alternative, capacity release options, more flexible operation of the physical facilities and innovative pipeline rate design and service offerings are needed to serve more power generation with temporary, load following and intermediary (wind) following services. Pipeline and storage operators need to continually innovate and exploit their flexibility to meet the need of CT and CCs with combinations of services or new services that can fulfill the traditional storage roles. Many of the pipelines already offer an array of creative balancing services, variations of firm storage services, and various combinations of no-notice services that combine firm transportation and storage, as well as flexibility for taking gas non-ratably.

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Few pipeline or storage projects into or in the MISO region are on the table at this time.

Those projects that are on the table today are related to moving natural gas and NGLs out of shale basins in Appalachia, south Texas and oil and associate gas out of Canada and the Bakken shales. There are several projects in the southeast, gulf coast and west from the Rockies, in addition to projects that will re-configure the Appalachian basin gas into Canada and the Northeast. There are no major projects into the MISO region, however, with the exception of these projects at this point, as identified below.

1) Northern Border (NBP) New Projects In October 2011, Northern Border Pipeline Company’s Princeton Lateral Project was placed into service. An 8.65 mile long, 16-inch diameter interstate natural gas pipeline lateral was constructed to transport 120 MMcf/d of firm transportation to Central Illinois Light Company's facilities near Princeton, Illinois at an estimated cost of $19 million. 2) Future Expansions On Northern Border (NBP) due to Bison Pipeline Future Expansion At the NBP/Bison Customer Meeting on April 13- 14, 2011, Bison revealed that is studying the potential to extend its pipeline to the south into northern Colorado and into south and west Wyoming. It involves 240 miles of 24” pipe to existing pipelines at Wamsutter or further, as shown in Figure 30: Bison Extension, below. It would cost approximately $450 to $600 million, depending on volume. The extension capacity south would add 300 to 600 MMcf/d and provide the ability to deliver up to 1.1 Bcf/d to NBP. This could signal that Northern Border Pipeline may undergo a capacity expansion in the future to move additional Rockies supplies to Midwest markets.

Bison Extension (Future Potential)

Northern Border Pipeline Customer Meeting April 13 – 14, 2011, Carefree, AZ Figure 30: Bison Extension

Future MISO Region Infrastructure Expansions Natural Gas Storage Serving the MISO Region

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In this regard, Northern Border is anticipating an increase in gas supplies into its pipeline from the Williston Basin and the Bakken Shale regions to increase from 168 MMcf/d in 2008 to 733 MMcf/d in 2012. Additionally, supplies from the Rockies via WBIP and Bison are anticipated to increase from 250 MMcf/d in 2008 to 720 MMcf/d in 2012 along with an increase in supplies from Canadian basins from 160 MMcf/d in 2008 to 220 MMcf/d in 2012. In total, this would mean in increase from 2008 input supplies of 578 MMcf/d to 1,673 MMcf/d in 2012 or within a few years thereafter, for a total increase above 2008 of 1.095 Bcf/d. These locations are identified in Figure 31: New Supply Sources from Rockies (WBIP) and Bakken Region, below.

New Supply Sources From Rockies (WBIP) and

Bakken Region

Northern Border Pipeline Customer Meeting, April 13 – 14, 2011, Carefree, AZ

Figure 31: New Supply Sources from Rockies (WBIP) and Bakken Region

3) Texas Eastern Expansion Vision In addition to Texas Eastern’s (Tetco’s) future power generation perspective, as shown below in Figure 32: Spectra Energy (TETCO) Perspective on MISO Region Opportunities, the power generation opportunity (#2) symbol is just southwest of the N Leg 24 line (Tetco Market Zone 2) that has been identified in this Analysis. At present, this area is restricted at certain times and it is estimated that it would require costly upgrades to provide firm deliveries to power generators in the MISO region. The OPEN project will impact this. Spectra also points out an opportunity (#5) which is for additional Ontario Storage. This is significant to MISO as it could mean more capacity may be required on Vector Pipeline, Great Lakes Gas Transmission (GLGT) or ANR or DTE or some combination thereof to move gas eastward to this storage area unless a complicated backhaul arrangement could be made with

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ANR. If the latter is the case, it potentially could possible enhance ANR’s capability to provide greater flexibility in managing capacity to power generation facilities.

Spectra Energy (TETCO) Perspective on

MISO Region Opportunities

Spectra Energy Presentation, Bank Of America Merrill Lynch 2011 Global Energy Conference, 11/16/11

Figure 32: Spectra Energy (TETCO) Perspective on MISO Region Opportunities

4) Wabash Storage Project

Wabash Storage Project is the only significant incremental storage project taking place or foreseen to take place into the near future. Wabash Gas Storage, LLC is a subsidiary of TPF II, L.P., a private equity fund which is managed by Tenaska Capital Management. Wabash Gas Storage, LLC (Wabash) redeveloping an abandoned aquifer natural gas storage facility in Edgar County, Illinois, south of the Chicago metroplex. The Project includes two subsurface gas storage fields, 4.5 miles of 20-inch-diameter pipeline connecting the surface facilities at the two fields, and 1.4 miles of 16-inch-diameter pipeline connecting the facility with Midwestern Gas Transmission Company’s interstate natural gas pipeline. The storage facility will have a working gas capacity of 14 Bcf with injection and withdrawal rates of 200,000 Dth per day. It is less than 2.8 miles from the Paris Compressor Station (CS-2115) of the Midwestern Gas Transmission Co. pipeline (Midwestern), which extends from northern Tennessee to the Joliet Hub near Joliet, Illinois. Midwestern interconnects to thirteen major interstate pipelines, including Rockies Express, and has numerous interconnects with power plants and local gas distribution companies. A map of the location is shown below in Figure 33: Wabash Gas Storage Project.

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Wabash Gas Storage Project

2011 Interstate Pipeline Customer Meeting, May 10 – 11, 2011, Lake Forest, Illinois

Figure 33: Wabash Gas Storage Project. 5) Northern Natural Gas’ “Northern Lights” Project Northern Lights 2009-2010 Zone EF expansion is part of the Northern Lights project, a multiphase pipeline expansion project designed to increase the capacity of Northern Natural Gas’ natural gas pipeline for its customers in its market area through 2026. Since the beginning of the project in 2007, Northern has added 667,000 Dth/day of firm winter service; 136,000 Dth/day of which resulted from the Northern Lights 2009-10 Zone EF Expansion. Northern is continuing to expand its system on a periodic basis to meet the growth needs of its customers.

Figure 34: NNG Northern Lights Project

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6) Vector Pipeline Vector Pipeline and Vector Pipeline Partnerships continue to gauge shipper interest in a third expansion of the 550 km Vector Pipelines System, which transports natural gas between Joliet, Illinois, and the storage complex at Dawn, Ontario, Canada, as shown below in Figure 35: Vector Expansion Capabilities. A binding open season was held in November 2009, but has since been delayed since not enough interest at that time was secured to move forward. The additional expansion proposes to add long-haul capacity of up to 115 MMcf/d by adding two new compressors and upgrades to the U.S. portion of the system. The expansion could also include incremental short-haul capacity by adding a loop to the US and/or Canadian portion of the pipeline system. The project was expected to be completed by November 2011. The Vector Pipeline System, constructed in 2000, has already undergone two expansion projects. The first involved the installation of compressor stations at Joliet, Illinois, and Washington, Michigan. The second expansion was completed in October 2009 and involved the construction of a compressor station at Athens, Michigan, increasing the nominal capacity of the pipeline from 1.2 Bcf/d to approximately 1.3 Bcf/d. Vector Expansion Capabilities

Vector Customer Meeting (Presentation by Enbridge) October 11, 2011 Figure 35: Vector Expansion Capabilities

7) The Ohio Pipeline Energy Network (OPEN) project, a proposed expansion of the Texas Eastern pipeline system, conjunction with AEP and Chesapeake Energy that will connect Ohio's Utica and Marcellus shale gas supplies. It will involve approximately 70 miles of new pipeline and create an additional 1 billion cubic feet per day (Bcf/d) of transportation capacity to serve local distribution companies, industrial users and gas-fired power generators in the central Ohio market. The significance of this project is that it may increase delivery into the MISO region through capacity backhaul on the Tetco N24 Leg. A binding open season for the OPEN project is planned for the first quarter 2012 with the projected in-service slated for November 2014.

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Development Cost Uncertainty The cost of developing new infrastructure projects is extremely volatile. Over-runs from hot market factors, project opposition, fewer (large diameter pipe) suppliers and regional factors (proximity to cities and other infrastructure) are more frequently issues on new projects. The current map of North American production regions is evolving more rapidly than pipelines can be built. This is important, because production without "takeaway" pipelines leaves gas and oil stranded, with little or no value. In many shale basins, prices and production being are pressured by a lack of pipeline capacity. That will lead the industry into another new phase of investment. The first phase of the shale production era saw significant amounts of capital poured into exploration and production companies with shale gas assets. That action is still in play but giving way to a second phase of pipeline development which is being tested by low natural gas prices. Today, natural gas is being “flared” in the Bakken and other shale basins for lack of gas infrastructure, as producers shift their interest to shale-oil production. Regardless of the economy, shale gas, NGL and oil resources will continue to develop. That development is changing the industry's map of flow patterns dramatically. The result implies a period of demand for new and expanded pipeline routes and capacity.

From the supply side, gathering systems feed into mainline systems. On the demand side, end-user requirements call for additional capacity to meet their needs. In between is the balance of pipeline safety, operational reliability and infrastructure financing and cost recovery issues and concerns.

Beyond the next few years, it is difficult to identify specific pipeline projects, but general predictions for new capacity can be made. Most of the capacity will be used to access new supply areas and the expansions will correspond with the increased flows as have been identified earlier in this Analysis. Also, demand-driven infrastructure requires increased regulatory cost recovery clarity. Producers of new natural gas supplies are helping to drive these pipeline investments by committing to the firm pipeline capacity needed to ensure the deliverability of these new supplies to markets. However, gas distribution companies (LDCs), marketers and power companies are in ever-increasing competition for limited pipeline and storage capacity when there are no expansion projects on the horizon.

While gas demand in the residential, commercial and industrial sectors largely has been flat in recent years, natural gas consumption for power generation has continued to grow as natural gas has become a fuel of choice for power generation. Keeping pace with these changes, midstream infrastructure investments have been substantial, but more is needed to serve the

Major Issues Facing Infrastructure Development Natural Gas Storage Serving the MISO Region

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next wave of demand, driven in large part by more stringent power generation environmental regulations. There may be increased contracting tension for capacity between traditional LDCs and electric power generators unless pipelines can be creative in their operations and services in supporting the needs of power generators.

Most LDCs will retain their storage. There are minimal amounts of storage available and much of the pipeline infrastructure is used during the summer to inject natural gas into storage. Since spare seasonal pipeline capacity may not be available, incremental pipeline infrastructure will be needed to serve an increasing summer power generation market. Power generators will have to be continually creative in their use of pipeline capacity release opportunities, parking, lending services and other pipeline services as well as operations communication and coordination with the pipelines’ Control Operators to meet summer and winter requirements. Marketers can play a key role in providing gas delivery capacity to MISO region electric power customers. While LDCs and electric companies hold a majority of capacity on the pipelines, marketers are able to assign long-term capacity to their customers who may be companies that require capacity for future electric power generation projects. Timing Issues There is a gap between the timing when the market indicates it is ready to commit to new infrastructure projects and how long it takes supply and infrastructure to respond. If infrastructure utilization approaches 100% utilization, the value of infrastructure capacity increases in the market. The problem is even though prices increase, this usually cannot result in an immediate increase in capacity. Capital Cost Recovery Uncertainty Major infrastructure projects today are often sponsored by producers who are reluctant to commit (i.e., cost of warranty) for longer than 10-15 year terms. Since regulated recovery of capital is usually for longer terms, pipeline and storage infrastructure developers are uncertain of recovering new capital investments. An approach to incentivize pipelines and power generators, in particular, is needed to move forward with greater certainty about regulatory cost recovery.

Less Spare Flexibility and Shorter-Term Contracts Most current infrastructure was sponsored and constructed during a highly regulated environment when the market supported development with long term purchase, sales and transportation contracts. The demand increase of the past twenty-five (25) years absorbed much of the previously excess supply and capacity in the system, so demand increases over the next twenty years could have a more difficult time aligning new supplies to infrastructure developments.

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LDCs, which have retreated to “short-term” contracting (3, 5, 7 years versus the 15 to 20 year contracts of old which provided cost-recovery certainties to pipelines) may be particularly fearful of entering into long-term contracts out of concern that regulators may find longer term contracts “imprudent” at a time when their transportation infrastructure and supply options are changing rapidly in today’s market. This same concern is a major problem for regulated electric utilities as well. This type of regulatory uncertainty is a major impediment to pipeline and storage infrastructure financing and a common gas and electric interdependency issue. Adding to this short-term contracting environment and increasing pipeline capacity uncertainty are the standard right of first refusal (RORF) provisions of firm transportation contracts. These encourage continuous “contract rollover” by firm contract shippers. Under ROFR, the current customer must match the rate (up to max rate) that another customer is willing to pay in order to retain the capacity. Existing customers have the security of knowing that the ROFR provisions will allow them to keep that capacity and match any offer up to the maximum rate, ad infinitum. Pipelines, therefore, are handicapped in their ability to market the capacity since a customer can retain the capacity even though others in the market are willing to pay more or contract for greater quantities over a longer term. In essence, there are four (4) options to obtain firm capacity: 1. Released capacity from existing shipper; 2. Bundled capacity with supply from marketer or asset manager; 3. Contract directly with pipeline or obtain a customized tariff service; or,

4. Pay to build capacity.

Other Uncertainties A number of variables could change, resulting in either more or less natural gas market or production growth and in turn, impact natural gas infrastructure. Important demand variables such as natural gas as a transportation fuel, limitations on the use of hydraulic fracturing, LNG exports, coal-fired capacity, economic growth, electricity demand growth, nuclear power growth and gas-to-liquids and oil production mix, and others that impact natural gas and electric infrastructure interdependency.

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Reviewed below are the four (4) capacity options in more detail. The Right of First Refusal (“ROFR”) provisions in firm transportation contracts are a problematic issue for potential firm customers (or shippers) that may value the capacity more that the current holder of the firm capacity. In our review of the MISO-identified pipelines’ firm customer contracts, the majority of contracts will enter the ROFR period starting in 2014 through 2017. Potential gas-fired power generators must be aware of this situation and be prepared to act accordingly, as this may impact whether or not firm capacity may be obtained. 1. Released capacity from existing shipper In addition to firm transportation capacity, there is also interruptible capacity. Interruptible capacity is only available if there is capacity that is not being used by a firm transportation shipper and is bought from the pipeline. There is also a category of firm transportation capacity called “released capacity”. Released capacity is capacity that a holder of firm transportation can release via a pipeline’s electronic bulletin board (EBB) on a recallable or non-recallable basis. Recallable capacity resembles interruptible capacity and the primary holder may call-back the capacity should they need it. So essentially, recallable firm capacity resembles interruptible capacity and non-recallable capacity resembles firm capacity. Along these lines, to obtain capacity, the power generator could either strike a deal with an existing holder or bid during an open season related to the ROFR capacity up to the maximum rate to become a primary holder of capacity.50 2. Bundled capacity with supply from marketer or asset manager Marketers and asset managers are mostly firm capacity holders or managers of released capacity. Large producer-marketers hold vast amounts of firm transportation capacity that they bundle with gas supply for deliveries. Asset managers manage the gas supply and transportation contracts for another party. Typically a shipper holding firm capacity on a pipeline or a number of pipelines may temporarily or longer, release all or a portion of their unused capacity and often with associated gas production, relinquish the capacity and supply to an asset manager. The asset manager will use that capacity to manage the requirements of the releasing shipper and when there is excess or unneeded capacity, uses that capacity to make releases or bundled sales to third parties.

50

Ideally in auction practice, a party that wanted to pay above the maximum rate could “out-bid” the existing ROFR shipper. However, this is not in the FERC’s Order No. 712 regulations.

Contract Issues Impacting Capacity

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3. Contract directly with pipeline or obtain a customized tariff service A third option is to contract with a pipeline to obtain a customized tariff service. It is often an alternative to the FERC-approved services and rates in the pipelines tariffs. The pipeline and the shipper (customer) will negotiate the conditions of service(s) and the rate(s) to meet a unique or specific customer’s needs. This will require the pipeline to file with the FERC, a modification to their tariff. Sometimes this type of arrangement is done with or without the added costs of construction. Typically it allows the pipeline to use their discretion and operational and asset flexibilities to meet the customer’s needs. It is a compromise option that may be considered before the “pay to build additional capacity” option if there is some available capacity that can be enhanced through the pipeline’s manageable asset and flexibility attention. 4. Pay to build capacity The “pay to build additional capacity” has been the focus of this Analysis and one of the main objectives has been to determine if there is available capacity on the MISO region pipelines and if so, how much and how many MISO-identified facilities can be supported. In this Analysis, we have “back-casted” from the period January 1, 2005 to October 31, 2011, the number of days on each respective pipeline that there would not have been enough capacity to serve the MISO-identified facilities up to their full requirements. This is the importance of the Daily Insufficiency Analyses (“DIA”). While there are several options to consider, the DIA in conjunction with the “pay to build capacity” approach provides an absolute perspective of capacity availability for dedicated firm transportation capacity and associated costs. It has been confirmed with the MISO-identified pipelines, that if the lateral construction modifications were made, the facilities will receive their required natural gas to operate on a “year-round” basis for CTs as well as CCs. However, there are three exceptions: A pipeline may not have any available firm transportation or storage even with the lateral construction options offered. One pipeline’s solution may be dependent upon another pipeline that may not have any available firm transportation or storage. The pipeline may require extensive looping and/or addition of compression to serve both the downstream pipeline and power generation facilities on its system. The costs are unknown at this juncture. However, undertakings of this sort could be in the hundreds of millions dollar range. Assumptions about CT and CC run times The MISO has done extensive analysis to estimate the approximate capacity factors to the 32 MISO-indentified facilities. The Annual Capacity Factors (CF %) for the CTs range from 8.3% to 36.8%. The annual Capacity Factors for the CCs range from 84.9% to 86.3%. While it is often considered that the CTs will primarily operate in the Summer Period and the CCs’ operations will resemble more of a baseload profile, this Analyses takes into account the need for “year-round” possible operations.

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The MISO-identified pipelines were surveyed to provide construction cost estimates, as shown in TABLE 7, in order to ensure that gas supplies would be delivered with firm transportation. The DIA (TABLE 5) analyzes the pipelines’ capacity, or lack thereof, from an interruptible transportation perspective. That is, how many days per year would there have been insufficient capacity if interruptible capacity was used. For all the pipelines, with the exception of eight pipelines of mainline segments, firm transportation capacity for the MISO-identified units looks good. However, to the extent that there are a high number of days that indicate insufficient capacity that is a clear indicator that the pipeline would also have to be operationally creative and flexible in managing its system to provide firm transportation services. CONCLUSION Generally there is sufficient pipeline capacity the MISO region to provide incremental firm transportation services for power generators. Out of 25 mainline segments and pipelines, 6 do not have sufficient capacity and 2 additional pipelines are questionable. Generally, almost all the pipelines would have to be increasingly operationally flexible to provide delivery service to the MISO power generators. The construction costs to serve the incremental will be over $3.0 billion over the next 5 years. Regulators will need to be flexible in fast-tracking pipeline construction projects to ensure that coal- to gas- fired generation and gas supply growth move in phase together. The increasing gas and electric infrastructure interdependency requires an improved collaborative process between pipelines, power generators and regulators to coordinate natural gas infrastructure projects. Meeting infrastructure needs requires improved regulatory certainty from state and federal regulators and agencies, particularly the EPA. Better certainty, commitment and will to incentivize pipelines and power generators are needed to move forward in coordinating the construction of a strong national energy infrastructure system.