A Preliminary Investigation Into the Cost of Reducing Fuel Risk in the MISO Midwest Footprint

A Preliminary Investigation Into the Cost of Reducing Fuel Risk in the MISO Midwest Footprint October 2013 MISO Policy & Economic Studies Department i

Contents 1 Executive Summary... 4 2 Introduction... 6 2 Study Overview... 7 2.1 Objectives... 7 2.2 Methodology... 7 2.3 Findings & Discussion... 8 2.3.1 Dual-fuel Conversion... 8 2.3.2 Firm Transportation Tariff Rate Survey & Calculations... 9 2.3.3 Firm Transportation Tariff Rate Alternative Approximations...14 3 Conclusion...16 4 Appendix A...17 MISO 2

List of Tables Table 1. Dual-fuel Unit Conversion Costs... 9 Table 2. Enhanced Firm Gas Transportation Services of Major Interstate Pipelines in the Midwest...11 Table 3. Example Max Tariff Rates for Firm Gas Transportation Service on Major Midwest Interstate Pipelines...17 List of Figures Figure 1. Maximum Base or Negotiated Firm Transportation Tariff Rate Ranges for Select Major Interstate Gas Pipelines...10 Figure 2 Maximum Base Enhanced or Flexible Firm Transportation Tariff Rate Ranges for Select Major Interstate Gas Pipelines...12 MISO 3

1 Executive Summary Firm gas transportation contracts and dual-fuel capability can increase the certainty that gasfired electric generators will have the fuel they need to run, when there is demand to generate. However, this increased certainty comes at a cost to asset owners, and ultimately to consumers. To better understand the economics of reducing fuel risk, MISO carried out a preliminary examination of the costs of both firm gas transportation contracts and dual-fuel conversion. Brattle was commissioned to assist with this effort. General takeaways include: - Maximum base tariff rates for firm gas transportation service vary significantly from one pipeline to the next in the MISO Midwest footprint. - Services provided per pipeline also vary, with a handful in the Midwest offering seasonal and/or flexible firm transportation of gas 1. - Conversion of combustion turbines to be dual-fuel capable is uncommon, and experiential data for cost projections is not readily available. - These factors limit the ability to project costs for dual-fuel conversion and firm gas transportation contracts on a footprint-wide basis. - This investigation identifies two possible options for reducing fuel risk; it does not identify a clear-cut economic advantage of one firm fuel option over the other and does not prescribe a firm fuel requirement. - This report is intended to provide data points for informational purposes and discussion; any follow-up conversation on incentives and flexibility for generators to address potential fuel risk should be a joint discussion with Stakeholders via MISO s Supply Adequacy Working Group. A survey of rate ranges for firm and enhanced firm gas transportation services is presented, as well as example rate calculations for gas transportation contracts for a 75 MW combustion turbine. The results of these calculations are summarized below. Firm Fuel Option Cost Assumptions Dual-fuel Conversion $700,000 - $2.4M / yr Levelized annual costs, over 20-yr operating period Firm Transportation Contract (estimated annual costs based on maximum/ negotiated base tariff rates for select major interstate pipelines in the MISO Midwest footprint) $77,000 to $3.86M / yr 10 Dekatherms/Megawatt (Dth/MWh) hour fuel burn; 18,000 Dekatherms/day (Dth/d) contract provides for 24 hours of max run time (750 Dth/h); additional (minimal) contractual fees excluded 1 Though annual contract periods for firm gas transportation are more common, many pipelines offer seasonal or monthly contract options. Additionally, a handful of pipelines in the MISO Midwest footprint offer contracts allowing non-rateable takes, i.e. greater than 1/24 of the Maximum Daily Quantity contracted, per hour, for a premium price. See Table 2. Enhanced Firm Gas Transportation Services of Major Interstate Pipelines in the Midwest. MISO 4

Enhanced Firm Transportation Contract (estimated seasonal costs based on maximum tariff rates for select major interstate pipelines in the MISO Midwest footprint) Pipelines A, B $14,100 to $153,000 / season Pipeline C $219,100 to $604,000 / season Hourly take of ¼ MDQ 2 allowed 10 Dth/MWh fuel burn; 3,750 Dth/day contract provides for 5 hours of max run time; seasonal (3 month) contract; additional (minimal) contractual fees excluded; Hourly take of 1/16 MDQ allowed 10 Dth/MWh fuel burn; 12,000 Dth/day contract provides for 5 hours of max run time; seasonal (3 month) contract; additional (minimal) contractual fees excluded based on seasonal rate A discussion of the costs of firming fuel supply should also include the issue of on-site fuel storage capability. MISO does not currently require verification of secondary fuel on-hand for the approximately 6.6 GW of dual-fuel capable units in the Midwest footprint, or otherwise account for storage capability or refueling time when modeling electric generation infrastructure. Uncertainty around fuel supply availability is not limited to gas-fired generation and further investigation into this topic may be warranted. Finally, these preliminary cost estimations do not take into account potential pancaking of rates to ensure firm delivery across multiple pipelines or the cost and time of commitment required for pipeline expansion. Even if these were accounted for, the uncertainty and variance in costs footprint-wide demand a more localized approach to cost analysis. The most economical approach to reducing fuel risk may be to determine an acceptable level of fuel risk and allow individual generators to decide how best to meet reliability targets. MISO recommends that the firming of fuel supply be incentivized through tariff applications without a mandated requirement for either firm fuel contracts or dual-fuel generation capability. 2 Maximum Daily Quantity. This is the maximum amount of gas the customer can flow per day, dictated by the customer s contract with the pipeline. MISO 5

2 Introduction Today s competitive prices and abundant supply of natural gas along with environmental compliance requirements faced by electric generators are driving a transition of the electric generation resource mix in the MISO footprint. While coal-fired generators continue to play the lead role in meeting power needs in the region, reliance upon natural gas is increasing. As the portion of demand served by gas-fired generators grows, so does the interdependency of the electric power system and natural gas infrastructure. MISO s efforts to address this issue began in late 2011 with a commissioned study of the adequacy of natural gas infrastructure in the Midwest. Since then, MISO has engaged its Stakeholders and the natural gas industry in an on-going conversation about gas-electric interdependency, its challenges and potential solutions. One of the foremost issues of discussion is that of fuel supply uncertainty, and the apparent risk of fuel shortage-related outages during the shoulder and winter months. Gas-fired generators in the MISO footprint get their fuel from a variety of sources, including directly from a single pipeline or a local utility (Local Distribution Company or LDC), or from multiple interconnects with pipelines. Fuel transportation contracting varies from one power plant to the next. Currently, about 20% of the total gas burn requirement for gas-fired generation in the MISO footprint is served under Firm Transportation contracts 3. Alternatively, some generators are dual-fuel capable and have distillate oil on-site as a backup. In MISO, about 6.6 GW of the total 36 GW of gas-fired generation are dual-fuel-capable 4, with approximately 70 M gallons of back-up fuel storage capacity 5. While dual-fuel backup and firm gas transportation contracts add to fuel certainty, they also add to unit costs. To better understand the economics of reducing fuel risk, MISO examined both the costs of firm gas transportation contracts and dual-fuel conversion. Brattle was selected to assist with this effort. 3 Based on MISO Quarterly Survey results. 4 Registered in the MISO Commercial Model. 5 Based on MISO Quarterly Survey results. MISO 6

2 Study Overview MISO s preliminary investigation compared the cost of firm gas transportation contracts with industry estimations of the cost of converting an existing combustion turbine to be dual-fuel capable. The following sections detail the study objectives, methodology and findings. 2.1 Objectives The objectives of the Brattle portion of the study included, for gas-electric reliability planning purposes, developing generic estimates for: The capital cost and timeline for retrofitting an existing single-fuel gas-fired combustion turbine (CT) or combined cycle (CC) unit with dual-fuel capability to burn distillate oil Annual costs to maintain dual-fuel capability The impact of oil-firing at a dual-fuel unit on outage rates and unit operations Additionally, Brattle was tasked with identifying and assessing alternative metrics for the cost of firm gas transportation. MISO s objectives were to: Develop a range of firm transportation contract costs on major interstate gas pipelines throughout the MISO Midwest footprint 6 To convert firm transportation costs to a $/MW metric for comparison with dual-fuel conversion costs 2.2 Methodology Both MISO and Brattle gathered data from publicly available sources, including pipeline tariffs, published studies, websites, and gas industry electronic bulletin boards. Additionally, Brattle interviewed industry contacts, including plant operators, an engineering and design firm, a turbine manufacturer, and generation owners. To provide comparable cost metrics for potential costs of firm fuel transportation, MISO used several example scenarios, with the following assumptions: For all scenarios: o The gas-fired generator heat rate is 10 MMBtu/MWh 7 Scenario 1 o Gas-fired generators purchase a 3-month (seasonal) flexible firm contract to allow for max output operation for 5 hours per day 6 See Appendix A for examples of max tariff rates for firm gas transportation contracts. 7 Based on the heat rate used in MISO s Phase I, II and III Gas Studies. This value is an approximation based on the age of the gas generation fleet and industry figures. MISO s Phase I and Phase II Gas Studies can be found at the following link: https://www.misoenergy.org/whatwedo/strategicinitiatives/pages/epacompliance.aspx. The Phase III is targeted for completion in October 2013. MISO 7

Firm Gas versus Dual-fuel Conversion o This flexible firm contract allows for an hourly take of up to ¼ MDQ 8 Scenario 2 o Gas-fired generators purchase a 3-month (seasonal) flexible firm contract to allow for max output operation for 5 hours per day o This flexible firm contract allows for an hourly take of up to 1/16 MDQ Scenario 3 o Gas-fired generators purchase a 12-month firm contract to allow for max output operation for 24 hours per day o This firm contract allows for rateable (an hourly flow up to 1/24 MDQ) takes. Additional costs for gas transportation on interstate pipelines were not considered, including the Annual Charge Adjustment 9 (ACA) and commodity charges (charge per dekatherm of gas the customer actually flows). Cost calculations for these scenarios also do not account for the ability to re-sell reserved (firm) pipeline capacity on the secondary market if the contract. Cost ranges for both firm gas transportation and flexible firm gas transportation contracts were developed by surveying maximum base tariff rates, as publically available. 2.3 Findings & Discussion The following sections present Brattle s findings on the feasibility of adding dual-fuel capability, as well as firm transportation cost estimation alternatives, and MISO s cost estimations for various firm contract scenarios. 2.3.1 Dual-fuel Conversion Capital cost estimations for converting a 75 MW combustion turbine to be dual-fuel capable range from $80 - $267/kW. Capital costs will depend on turbine type, space limitations, the size of the fuel tank, and access to demineralized water. There are no anticipated technical barriers to dual-fuel retrofits, but space limitations could impact feasibility and project cost. Permitting for a dual-fuel unit in the Midwest is estimated to take six months. Dual-fuel conversion would add minimal increases in annual operation and maintenance costs as long as the secondary-fuel operation is properly executed and used only in limited periods during emergency conditions. There is no expected impact on Capital cost estimations for converting a 75 MW natural gas combustion turbine (NGCT) to be dualfuel capable range from $80 - $267/kW. For comparison, the capital cost of building a new NGCT without dualfuel capability is approximately $676/kW. 8 Maximum Daily Quantity. This is the maximum amount of gas the customer can flow per day, dictated by the customer s contract with the pipeline. 9 The Annual Charge Adjustment is a surcharge permitted by Section 154.38 (d) (6) of FERC Regulations to permit interstate pipeline companies to recover from their shippers all Total Annual charges assessed them by FERC under Part 382 of FERC s Regulations. MISO 8

Firm Gas versus Dual-fuel Conversion forced outage rates or false starts due to oil-firing, and switching a CT from gas to oil operation can be done in a few minutes. Emission rates increase during oil-fired mode, so emissions reduction equipment or limited run hours may be necessary to control NOx and particulate matter emissions. Options for NOx control include injection of demineralized water or selective catalytic reduction (SCR) technology. No cost comparisons for these two technologies were provided. Fuel-carrying costs depend upon the minimum run-hours required by the system operator or utility. A minimum tank size of 175,000 gallons is estimated for a 75 MW CT unit for 24 hours of runtime on oil. Refueling can be executed at the same time as the oil burn, and the refuel rate can be sized to exceed the burn rate. Some of the participants in Brattle s industry survey cited refueling charges during cold snaps, and another added estimated costs for dual-fuel unit testing and verification. Overall cost additions of dual-fuel conversion are given in Table 1. Dual-fuel Unit Conversion Costs. Table 1. Dual-fuel Unit Conversion Costs Metric (unit) Low Average High Unit capital cost ($M) 6.0 12.7 20.0 Capital cost ($/kw) 80 169 267 Levelized capital cost* ($/kw-yr) 8.5 17.9 28.3 Days of fuel oil supply (days) 1 3 7 Annual fuel carrying cost* ($/kw-yr) 0.6 1.8 4.3 Total annual costs ($M/yr) 0.7 1.5 2.4 Levelized total annual costs ($/kw-yr) 9.1 19.8 32.6 *Assumed 7.3% nominal discount rate for a regulated utility and 20-yr life. Capital charge rate is 10.61%. 2.3.2 Firm Transportation Tariff Rate Survey & Calculations MISO reviewed the tariffs for each of the major interstate pipelines in the Midwest and found that tariff services and rates vary significantly from one pipeline to the next. These differences make it difficult to arrive at a typical value for firm gas transportation. Instead, maximum base tariff rates, or rate ranges, for firm transportation contracts are presented (Figure 1). Rates per service per pipeline can vary by contract duration (e.g., Viking Pipeline), seasonally, or more commonly, zonally. For example, contracting for firm transportation within a gathering or field zone is generally less costly than contracting for transportation from a field zone to a market zone, or from a market zone to a distant market zone. Other pipelines will capture long-distance transport in their rate structure by charging per 100 Dth-miles (e.g., Northern Border). As rates and services vary across pipelines, so do location, operational flexibility, age of infrastructure, customer base, etc. The range of rates presented reflects one aspect of pipeline operation. MISO 9

Figure 1. Maximum Base or Negotiated Firm Transportation Tariff Rate Ranges for Select Major Interstate Gas Pipelines ALL = Alliance Pipeline MIDW = Midwest Gas Transportation TXGT = Texas Gas Transmission ANR = ANR Pipeline MRT = Mississippi River Transmission TRNKL = Trunkline Pipeline BIS = Bison Pipeline NGPL = Natural Gas Pipeline Co. VEC = Vector Pipeline CPT = Enable Midstream Partners NB = Northern Border Pipeline WBI = WBI Energy Transmission (Formerly CenterPoint Energy Gas Transmission) NNG = Northern Natural Gas VIK = Viking Gas Transmission XRDS = Crossroads Pipeline PAN = Panhandle Eastern Pipeline GLGT = Great Lakes Gas Transmission REX = Rockies Express Pipeline GUARD = Guardian Pipeline SSC = Southern Star Central Gas Pipeline KO = KO Transmission Co. TXE = Texas Eastern Transmission MISO 10

Additionally, some pipeline companies offer enhanced or flexible firm transportation services, which generally have different rate structures. A breakdown of enhanced/flexible firm transportation services offered by major interstate pipelines in the Midwest is presented (Table 2). Table 2. Enhanced Firm Gas Transportation Services of Major Interstate Pipelines in the Midwest Pipeline Service Name Service Description ANR Enhanced Transportation (ETS), Firm Transportation (FTS-2, FTS-3) ETS allows for MHQ 10 of 1/16 MDQ 11 ; FTS-2 is a monthly firm contract less 10 days; FTS-3 allows for MHQ of 1/4 MDQ CenterPoint Energy Gas Transmission (CEGT) Enhanced Firm Transportation (EFT) EFT allows Shippers to flow gas at an accelerated rate (MHQ multiplied by factor specified daily by pipeline) for no less than 8 consecutive hours, and no more than one time/day at a given delivery point. Great Lakes Gas Transmission (GLGT) Expedited Firm Transportation (EFT) EFT allows for MHQ between 1/4 and 1/16 of contracted MDQ. NGPL Flexible Firm Transportation (FFTS) FFTS allows Shipper and pipeline to agree upon min and max number of days that firm service would be available during a specified period, e.g. 10 days during 1 month. Panhandle Eastern Enhanced Firm Transportation (EFT), Hourly Firm Transportation (HFT) EFT allows Shipper to take gas at any point of delivery, during any hour, up to 1/16th of contracted MDQ. HFT allows for contract-specified MHQ up to contracted MDQ. Texas Gas Transmission Seasonal (Short-term) Firm Transportation (SFT), Enhanced Firm Transportation (EFT) SFT allows Shipper to contract for firm service for monthly or intra-monthly periods; EFT allows for MHQ of 1/16 contracted MDQ. 10 Maximum Hourly Quantity. This is the maximum amount of gas the customer can flow per hour, dictated by the customer s contract with the pipeline. 11 Maximum Daily Quantity. This is the maximum amount of gas the customer can flow per day, dictated by the customer s contract with the pipeline. MISO 11

Firm Gas versus Dual-fuel Conversion Trunkline Enhanced Firm Transportation (EFT) EFT allows Shipper to flow at any Point of Delivery during any hour between fifty percent (50%) and one hundred fifty percent (150%) of uniform hourly quantities. Vector Hourly Firm Transportation (FT-H), Limited Firm Transportation (FT-L) FT-H allows Shippers to flow their contract quantity during a specified hourly period, no less than 4 hours and no greater than 16 hours, within a gas day; FT-L is a monthly firm contract less 10 days. The range of maximum base tariff rates for enhanced or flexible firm services is presented (Figure 2 Maximum Base Enhanced or Flexible Firm Transportation Tariff Rate Ranges for Select Major Interstate Gas Pipelines). Figure 2 Maximum Base Enhanced or Flexible Firm Transportation Tariff Rate Ranges for Select Major Interstate Gas Pipelines As described in Section 2.2, several scenarios were used to illustrate potentials costs for a 75 MW gas-fired combustion turbine to contract for firm or enhanced firm gas transportation service. These cost estimations only account for reservation charges (the cost to reserve capacity on the pipe). They do not account for commodity charges (the cost to actually flow gas) or additional fees rolled into total contract costs, such as the Annual Charge Adjustment, which MISO 12

Firm Gas versus Dual-fuel Conversion are typically minimal. Futhermore, these calculations do not take into account the ability of the generator to release and sell un-needed firm capacity on the secondary market. Scenario 1 Gas-fired generators purchase a 3-month (seasonal) flexible firm contract to allow for max output operation for 5 hours per day This flexible firm contract allows for an hourly take of up to ¼ MDQ For a 75 MW generator with a 10 Dth/MWh fuel burn, a max hourly fuel burn of 750 Dth, and the ability to take up to ¼ MDQ per hour, a 3750 Dth/d contract would provide enough fuel and flexibility for 5 hours of max operation. Midwest interstate pipelines offering a flexible firm transportation contract option with an explicit MHQ of up to ¼ MDQ include ANR and Vector. Using the maximum base tariff rate ranges for these pipelines, the estimated seasonal cost excluding commodity charges and other contract charges or fees ranges from $14,100 to $153,000. Additionally, GLGT offers an expedited service with negotiable MHQ. Assuming the total daily contract volume is taken over 5 hours, with MHQs of 750 Dth and total contract volume of 3750 Dth, the estimated seasonal cost for expedited firm transportation service on GLGT, excluding commodity charges and fees, ranges from $147,600 to $510,600, depending on the zone of transport. Panhandle Eastern also offers an expedited or hourly service with a negotiable MHQ. Rate estimations for Panhandle Eastern may include a gathering charge in addition to a transmission charge (varies zonally), and mileage rates. Scenario 2 Gas-fired generators purchase a 3-month (seasonal) flexible firm contract to allow for max output operation for 5 hours per day This flexible firm contract allows for an hourly take of up to 1/16 MDQ For a 75 MW generator with a 10 Dth/ MWh fuel burn, a max hourly fuel burn of 750 Dth, and the ability to take up to 1/16 MDQ per hour, a 12,000 Dth/d contract would provide enough fuel and flexibility for 5 hours of max operation. Texas Gas Transmission offers an enhanced firm transportation contract option with an MHQ of 1/16 MDQ. Using the maximum base tariff rate range (firm rate + enhanced firm rate) the estimated seasonal cost, excluding commodity charges and other contract charges or fees, ranges from $176,000 to $432,972. Using the maximum base tariff winter/seasonal rate range (seasonal firm rate + enhanced firm rate) the estimated seasonal cost, excluding commodity charges and other contract charges or fees, ranges from $219,100 to $604,000. Additionally, Panhandle Eastern and ANR offer enhanced firm transportation services allowing a maximum hourly take of 1/16 MDQ. MISO 13

Firm Gas versus Dual-fuel Conversion Scenario 3 o o Gas-fired generators purchase a 12-month firm contract to allow for max output operation for 24 hours per day This firm contract allows for rateable (an hourly flow up to 1/24 MDQ) takes. For a 75 MW generator with a 10 Dth/ MWh fuel burn, a max hourly fuel burn of 750 Dth, and the ability to take up to 1/24 MDQ per hour (i.e., a rateable take), an annual contract for18,000 Dth/d would ensure that the generator could get gas for max operation all hours of each day of the year, barring force majeure events. Using the maximum base tariff rate range for pipelines investigated, up to Alliance s negotiated firm rate, the estimated annual firm transportation cost excluding commodity charges and other contract charges or fees ranges from $77,000 to $3,860,000. If the max rate for firm service on Rockies Express pipeline is included, the cost cap moves to $ 10,847,455 per year. Other considerations for rate estimation include the difference in cost of firm gas transportation contracts between existing capacity and capacity on pipelines yet to be built. Additionally, depending on the location of the customer, it may be necessary to contract with more than one pipeline. Pancaked rates have a potential to increase the cost of firm gas transportation. 2.3.3 Firm Transportation Tariff Rate Alternative Approximations In many cases, the max tariff rate is not the cheapest option available to Midwest gas consumers for firm gas transportation. Discounted rates and interruptible contracts on pipelines with excess capacity offer less costly alternatives. As such, using the max tariff rate as a proxy for the price of fuel transportation may overstate the actual cost. Natural gas basis differentials the difference in prices between two natural gas pricing hubs can serve as an alternative to using max tariff rates to estimate costs of firm transportation. Basis differentials represent the economic value of transporting gas from one location to another. For example, if the natural gas spot price at Chicago is $5/MMBtu and the price at Henry Hub in Louisiana is $3/MMBtu, the basis differential is $5/MMBtu - $3/MMBtu, or $2/MMBtu. This cost of transportation, which is often regulated and cost-based, represents the costs incurred by a Shipper 12 while transporting physical quantities of gas from one location to another. In theory, the cost of transportation should be similar to the basis differentials in equilibrium and perfectly competitive markets. However, there are caveats that can distort this relationship (long lead times for new projects, high cost of entry, large long-term investment required to build pipeline, assured cost recovery due to regulatory framework, regulated costbased tariffs, etc.) Brattle s investigation into using basis differentials as a proxy returned the following: If basis differentials are greater than the cost of transportation, then there is value in having capacity rights on the pipeline (especially in a constrained system). 12 Shipper is the term commonly used in natural gas pipeline tariffs for pipeline customers, gas-fired generators. MISO 14

Firm Gas versus Dual-fuel Conversion Average annual gas basis differentials are lower than the cost of firm transportation, assuming max tariff rates. When the max tariff rate is greater than the basis differentials, the latter may be a good proxy for the cost of firm transportation. Additionally, based on a limited sampling of pipelines, Brattle found that firm tariff rates can exceed basis differentials by 2-3 multiples, or in an extreme case, over 5 times. MISO 15

Firm Gas versus Dual-fuel Conversion 3 Conclusion Firm gas transportation contracts and dual-fuel capability increase the certainty that generators will have the fuel they need to run, when there is demand to generate. However, this increased certainty comes at a cost to asset owners, and ultimately to consumers. Reliable system operation must be achieved at a reasonable cost, and this calls for a balance between increased certainty and increased expenses. This preliminary investigation focused on the costs of these two firm fuel supply options. On a long-term (20-year), footprint-wide basis, there is uncertainty as to which option would be most economical, given vast variance in rates from one pipeline to the next, as well as in the range of projected costs for dual-fuel retrofit. While a more localized approach could give insight into the costs for individual generators in the MISO footprint, the most economical way to address uncertainty around fuel availability may be to provide incentives and allow individual generators the flexibility to decide how best to improve reliability. Any movement towards a reliability target would need to be a mutual effort between MISO and its Stakeholders. MISO 16

Firm Gas versus Dual-fuel Conversion 4 Appendix A Maximum base tariff rates for firm gas transportation service are listed in each pipeline s tariff. Table 3 presents a sampling of max tariff rates for firm transportation service on pipelines in the MISO Midwest footprint, as well as select negotiated tariff rates. It is not meant to be a comprehensive list of firm transportation services. The rates below do not account for FERC s annual charge adjustment (ACA), overrun charges, commodity charges or fees for storage. The range of rates below for a given service on a particular pipeline accounts for zonal pricing schemes, i.e. greater cost corresponding to greater distance from supply points to delivery points. Table 3. Example Max Tariff Rates for Firm Gas Transportation Service on Major Midwest Interstate Pipelines Pipeline Alliance ANR Service/s Type & Comments Negotiated FT Recourse FT Specific Lateral Project Enhanced FT FT Service Charge $/Dth/Month* 17.875 16.071 19.021 4.858 to 13.608 1.750 to 14.750 Bison FT FT Negotiated 25.244 (Daily rate of 0.830) 16.522 to 17.480 CenterPoint Energy Gas Transmission (CEGT) FT 8-11 Hr Election Enhanced Firm Transportation (EFT) 12-15 Hr Election (EFT) 16+ Hr Election (EFT) 7.426 22.253 14.841 11.132 Crossroads FT 3.324 Great Lakes Gas Transportation Ltd. (GLGT) FT Expedited FT 2.733 to 9.456 EFT rate = (FT rate) x (24/EPF) where EPF = MDQ/MHQ Guardian FT 4.664 to 6.703 KO Transmission Co. FT 0.356 Midwest Gas Transportation FT 2.06 to 3.019 Mississippi River Transportation (MRT) NGPL FT Field & Market Zone FT Field Zone FT Market Zone FT Peak FT Off-peak Flex FT Peak Flex FT Off-peak 4.294 to 7.207 1.870 to 2.424 2.914 3.080 to 12.940 3.080 to 10.980 3.080 to 13.029 3.080 to 10.926 MISO 17

Firm Gas versus Dual-fuel Conversion Northern Border Northern Natural Gas (NNG) Panhandle Eastern FT FT Seasonal FT Field-Market Summer FT Field-Market Winter FT Market-Market Summer FT Market-Market Winter Mileage charges may also apply FT / HFF / EFT Gathering FT / HFT / EFT Transmission Field Zone Market Zone HFT Mileage charges may also apply 0.976 to 1.049 (per 100 Dthmiles) 0.681 to 1.310 (per 100 Dthmiles) 5.473 9.853 5.683 10.230 to 15.153 8.67 4.73 2.80 / 3.30 Rockies Express (REX) FT 7.072 to 50.2197 Southern Star Central Texas Eastern Transmission Texas Gas Transmission Trunkline Vector WBI Energy Viking Production Area FT Market Area FT Access Area FT Market Area FT FT SFT Winter/Peak SFT Summer/Off-peak EFT FT Enhanced FT FT Hourly FT Limited FT (See Table 3) FT FT (Sheyenne Expansion) FT Gathering Charge FT (<3 yr contract) FT (3-5 yr contract) FT (>5 yr contract) 5.791 4.165 1.834 to 6.588 4.137 to 10.039 2.414 to 9.552 3.612 to 14.291 1.569 to 6.208 2.475+FT/SFT contract 3.335 to 9.710 3.941 to 10.316 1.250 to 7.775 1.250 to 7.775 0.839 to 5.218 7.379 10.748 12.298 2.14 to 4.887 1.99 to 4.737 1.84 to 4.587 *Rates are rounded to 1/10 cents, and those specified as Dth/Day in tariff language were converted to Monthly rates using factor of 30.4 days/month. Tariffs in which flex or enhanced firm service rates were not specified as daily were assumed to be daily rates and were converted to monthly rates. MISO 18