STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the Application of ) DTE ELECTRIC COMPANY for ) approval of Certificates of Necessity ) pursuant to MCL 460.6s, as amended, ) in connection with the addition of a ) Case No. U-18419 natural gas combined cycle generating ) facility to its generation fleet and for ) related accounting and ratemaking ) authorizations. ) REBUTTAL EXHIBITS OF DAVID SWIECH
Exhibit: A-64 Henry Hub Price Forecast Accuracy - EIA Annual Energy Outlook 2009-2015 Page: 1 of 2 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Line 2010 2011 2012 2013 2014 2015 2016 1 Actual Henry Hub Spot Price $ 4.37 $ 4.00 $ 2.75 $ 3.73 $ 4.37 $ 2.62 $ 2.52 2 3 Publication Year 2010 2011 2012 2013 2014 2015 2016 4 EIA AEO 2009 $ 7.01 $ 7.06 $ 7.33 $ 7.49 $ 7.73 $ 7.99 $ 8.30 5 EIA AEO 2010 $ 5.93 $ 6.53 $ 6.60 $ 6.67 $ 6.99 $ 7.23 6 EIA AEO 2011 $ 4.65 $ 4.79 $ 4.89 $ 5.09 $ 5.27 7 EIA AEO 2012 $ 4.24 $ 4.41 $ 4.62 $ 4.67 8 EIA AEO 2013 $ 3.28 $ 3.32 $ 3.86 9 EIA AEO 2014 $ 3.93 $ 4.41 10 EIA AEO 2015 $ 3.90 11 12 Percent Error Year 2010 2011 2012 2013 2014 2015 2016 13 EIA AEO 2009 60% 77% 167% 101% 77% 205% 229% 14 EIA AEO 2010 48% 138% 77% 53% 167% 187% 15 EIA AEO 2011 69% 29% 12% 94% 109% 16 EIA AEO 2012 14% 1% 76% 85% 17 EIA AEO 2013-25% 27% 53% 18 EIA AEO 2014 50% 75% 19 EIA AEO 2015 55% Total 20 Average Error 60% 62% 124% 55% 23% 103% 113% 82%
Exhibit: A-64 Henry Hub Price Forecast Accuracy - Market Forwards 2009-2015 Page: 2 of 2 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Line 2010 2011 2012 2013 2014 2015 2016 1 Actual Henry Hub Spot Price $ 4.37 $ 4.00 $ 2.75 $ 3.73 $ 4.37 $ 2.62 $ 2.52 2 3 Publication Year 2010 2011 2012 2013 2014 2015 2016 4 CME/NYMEX Henry Hub Futures 2009 $ 5.96 $ 6.77 $ 6.94 $ 7.05 $ 7.19 $ 7.34 $ 7.48 5 CME/NYMEX Henry Hub Futures 2010 $ 4.95 $ 5.36 $ 5.56 $ 5.69 $ 5.79 $ 5.91 6 CME/NYMEX Henry Hub Futures 2011 $ 4.55 $ 4.97 $ 5.23 $ 5.45 $ 5.65 7 CME/NYMEX Henry Hub Futures 2012 $ 3.57 $ 3.98 $ 4.19 $ 4.38 8 CME/NYMEX Henry Hub Futures 2013 $ 3.70 $ 3.97 $ 4.14 9 CME/NYMEX Henry Hub Futures 2014 $ 3.99 $ 4.09 10 CME/NYMEX Henry Hub Futures 2015 $ 3.12 11 12 Percent Error Year 2010 2011 2012 2013 2014 2015 2016 13 CME/NYMEX Henry Hub Futures 2009 36% 69% 152% 89% 64% 180% 197% 14 CME/NYMEX Henry Hub Futures 2010 24% 95% 49% 30% 121% 135% 15 CME/NYMEX Henry Hub Futures 2011 66% 33% 20% 108% 124% 16 CME/NYMEX Henry Hub Futures 2012-4% -9% 60% 74% 17 CME/NYMEX Henry Hub Futures 2013-15% 51% 64% 18 CME/NYMEX Henry Hub Futures 2014 52% 62% 19 CME/NYMEX Henry Hub Futures 2015 24% Total 20 Average Error 36% 46% 104% 42% 18% 95% 97% 70%
Page: 1 of 21 Driving the Market: Impacts of Changes in Natural Gas Supply & Demand Dynamics on Midwest Natural Gas Markets Midcontinent LDC Forum: Chicago LDC Forum Tuesday September 12 th, 2017 Michael Sloan Managing Director, ICF Gas and Liquids Advisory Services Michael.Sloan@icf.com
Page: 2 of 21 Disclaimer This presentation presents views of ICF. The presentation includes forward-looking statements and projections. ICF has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual market results to differ materially from the projections, anticipated results, or other expectations expressed in this report.
Page: 3 of 21 ICF: Fast-Growing Diverse Consultancy with Domain Expertise in Energy Markets 3
Page: 4 of 21 Overview 1) North American Supply Trends 2) North American Demand Trends 3) Implications on Midwest Natural Gas Markets
Page: 5 of 21 Improvements in Drilling Productivity Low oil and gas prices have forced producers to improve rig efficiency in order to maintain positive returns on investment. Producers applied enhancements across the spectrum of drilling activity, including optimized siting, rig performance, longer horizontal sections, and increased fracking stages. These efficiency improvements have resulted in a doubling of new production per rig over the past two years. Source: Energy Information Administration (EIA), Drilling Productivity Report 6
Page: 6 of 21 Producers are More Responsive to Price Signals Improvements in shale gas technology have made production much more responsive to gas price changes. In 2007, a 1 Bcf/d change in gas production required a 12 cent change in price. By 2010, a 1 Bcf/d change in production required only a 7 cent price change. Today, a 1 Bcf/d change in production requires only a 4 cent change in price. As shale drilling techniques continue to improve, production will become even more responsive. The increased responsiveness of production will help keep prices relatively low and less volatile. Source: ICF Strategic Gas Outlook 6
Page: 7 of 21 U.S. Natural Gas Production Growth Will Continue to Come Mostly from the Marcellus and Utica Shale gas production accounts for over 70% of the overall gas production by 2020. Marcellus-Utica production will double over the next decade and remain the focus for midstream activity despite pockets of growth in other areas. Other major growth areas include shale plays in West Texas, SCOOP and STACK, Haynesville, and Western Canada plays. Conventional production is projected to decline by more than 5% annually over the next decade. Source: ICF Strategic Gas Outlook 7
Page: 8 of 21 Marcellus/Utica will Lead Future Production Growth, but Permian and Western Canada Play a Part As Well 8
Page: 9 of 21 All Sectors are Expected to Show Growth, but Exports Lead Future Market Demand Growth U.S to become a net exporter in 2017 +22.0 Bcfd of net demand growth *LNG Exports Include 10% liquefaction fuel loss End-use demand (RCIVP) does not include Lease & Plant and Pipeline Fuel Losses Source: ICF Strategic Gas Outlook 9
Page: 10 of 21 U.S LNG Exports U.S. natural gas markets will be increasingly linked to global markets through LNG exports. Based on current global LNG market conditions, ICF assumes that 6 U.S. LNG export terminals will operation by 2020 (Sabine Pass, Freeport, Cove Point, Cameron LNG, Corpus Christi, and Elba Island), with a total capacity of 10.3 Bcfd. U.S. LNG exports will play a significant role in global LNG pricing and will accelerate the de linkage of LNG contracts and oil prices. Global LNG demand is heavily influenced by oil prices. As oil prices firm, capacity utilization is projected to be slightly over 80% by 2025 when new liquefaction capacity is needed. U.S. export terminal capacity utilization will average ~60% through 2020. Source: ICF Strategic Gas Outlook 10
Page: 11 of 21 Short-Term LNG Contracts are on the Rise Cargos shipped on spot and short-term contracts now make up over a quarter of global deliveries. ICF expects that the portion of the LNG market operating on a short-term basis will increase to 40-50% by the mid 2020s. Expiration of long term contracts, LNG on LNG competition and increase in floating LNG re gasification capacity will likely result in an increase in short-term trade and access to LNG supplies to more developing countries. 11
Page: 12 of 21 Pipeline Exports to Mexico Mexico s demand for natural gas continues to rise, while its domestic production has been declining. Since 2010, Mexico s imports of U.S. gas have gone up over 300%, reaching 3.7 Bcfd in 2016. As Mexico continues to add gas-fired generation and sponsor new pipelines from the U.S., exports will continue to grow. By 2025, ICF s projection of U.S. exports to Mexico will surpass 7 Bcfd. Source: ICF Strategic Gas Outlook 12
Page: 13 of 21 Power Generation Gas Demand Coal-fired generation has been steadily declining, and gas has been rising to take its place. In 2016, gas surpassed coal as the largest single source of electricity in the U.S. Carbon policy is not the primary driver of power generation demand Even without a Federal carbon policy, gas will continue to gain market share over coal. By 2025, ICF s projected power sector gas use will reach 11 Tcf per year (30.4 Bcfd). Source: ICF Strategic Gas Outlook 13
Page: 14 of 21 Implications for Growth in Power Generation Demand on Gas Markets Low gas prices, retirement of coal plants, and gas CC capacity additions will continue to increase power sector gas consumption. Power generation demand growth will be concentrated in the Mid-Atlantic, South Atlantic and Southwest regions. New pipeline capacity from the Northeast will be needed to support demand growth. Growth in balancing and dispatch requirements will drive demand for high deliverability storage. As the share of natural gas in the generation fuel-mix continues to increase, gas-fired power generators and LDC s will need to address fuel supply reliability. More generators will need to contract for gas services to meet their needs, e.g., No- Notice Service and high deliverability storage to allow for quick response to changes in load. LDC s with behind the citygate power generators are likely to see growth in balancing requirements. 14
Page: 15 of 21 Gas Prices are Expected to be Range Bound between $3.00 to $4.00 per MMBtu Tighter supply-demand balance expected. Normal weather coupled with an increase in LNG exports and pipeline exports to Mexico will result in higher prices. Prices from 2018 and 2020 expected to be range bound near $3.40/MMBtu. Long-term natural gas prices will rise, but price increases will be moderated by low-cost gas supplies. Source: ICF Strategic Gas Outlook 15
Page: 16 of 21 Henry Hub Price is No Longer a Valid Indicator of Supply Prices Henry Hub price is still the marker price for natural gas. LNG prices are increasingly indexed to Henry Hub. However, Henry Hub price is no longer a good indicator of production prices. Henry Hub is now closer to a demand hub than a supply hub. Source: ICF Strategic Gas Outlook 16
Page: 17 of 21 Changes in Midwest Demand from 2016 to 2025 Demand is projected to grow modestly over the next decade in all sectors. Assuming 20-year normal weather conditions. Coal will continue to play a major role in meeting the Midwestern demand in the Midwest over the next decade and is projected to decline by about 10%. Renewable power generation in the Midwest is projected to increase by more than 80% over the next decade. Source: ICF Strategic Gas Outlook *Other includes pipeline and lease and plant fuel. Midwest region includes: Ohio, Michigan, Indiana, Illinois, Wisconsin, Minnesota, Iowa, Missouri, Kansas, Nebraska, North Dakota and South Dakota. 17
Page: 18 of 21 Change in Midwest Supply Sources Supply to Midwest region currently comes primarily from the Rockies, Western Canada and Mid-Continent regions. Marcellus/Utica share of supply increases from about 9% in 2015 to about 37% in 2025 as it displaces gas from other regions. Shift to Marcellus/Utica supply occurs due to new pipeline capacity that is now online or is scheduled to come online over the next few years. Rockies Express Pipeline (REX) Reversal Rover NEXUS Source: ICF Strategic Gas Outlook 18
Page: 19 of 21 Generally, the Changes in Natural Gas Markets will Benefit Midwest Consumers Changes in natural gas and oil supply technologies are smoothing out the natural gas commodity market: Continued drilling productivity and technology improvements will support further lowcost supply growth and hold down prices. Gas supply will respond faster to price signals, smoothing out mid-term price volatility. Midwestern markets sit in relatively close proximity to low cost Marcellus/Utica supplies and WCSB supplies, and will benefit from robust supply development over time. Supply mix in the Midwestern states will become more weighted toward Marcellus/Utica supplies, but traditional supply areas remain key. Source: ICF Strategic Gas Outlook 19
Page: 20 of 21 However, the World Remains an Uncertain Place The projected incremental demand from the power sector will be affected by load growth and regulatory policies. Cost of renewable power development. Tax credits. Pipeline exports to Mexico will be affected by the development of Mexico natural gas resources and market development (price and policy dependent). U.S./Mexico trade relations may affect export levels. US LNG exports will depend on oil prices, economic growth, international pipeline trade, market share of natural gas versus other fuels, and competition from other large suppliers like Australia and Qatar. Natural gas demand growth may be constrained by: Near term Potential constraints on pipeline capacity expansions. Long term - A trend toward electrification as an approach to reduce carbon emissions. 20
Page: 21 of 21 Midcontinent LDC Forum Supply and Demand Dynamics Panel Driving the Market: Impacts of Changes in Natural Gas Supply & Demand Dynamics on Natural Gas Markets Michael Sloan Managing Director, ICF Gas and Liquids Advisory Services Micheal.Sloan@ICF.com
MichCon CityGate Basis Comparison $0.30 MichCon CityGate to Henry Hub Basis (Nominal $/Dth) Exhibit: A-66 Page: 1 of 1 $0.20 $0.10 $0.00 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 ($0.10) ($0.20) ($0.30) ($0.40) DTE Electric's CON Basis Pace 2017 Basis IHS Apr'17 Basis ICF 2017 Q3 Basis
Exhibit: A-67 Corrected Calculation of NEXUS Impact (Witness Beach CCCT Cost Model) Page: 1 of 1 CCCT Costs from E3 model CCCT 1,013 MW Capacity Factor: Strategist Duct 100 MW Choice of Rev Req 81.6% 2.2% Gas Price 1 Units Capacity factor Generation (GWh) Heat rate Fuel Consumption Base Gas Cost Rev Req Total Year CCCT Duct CCCT Duct CCCT Duct Total CCCT Duct CCCT Duct Total $/Dth MM$ MM$ MM$ 2018 0 0 - - $ - $ - $ - 2019 0 0 - - $ - $ - $ - 2020 0 0 - - $ - $ - $ - 2021 0 0 - - $ - $ - $ - 2022 0.5 0.5 76.5% 38.2% 3,394 167 3,562 6.60 9.39 22,402 1,571 23,973 3.37 $ 80.7 $ 106.5 $ 187.2 $ 52.56 2023 1 1 74% 39% 6,562 345 6,907 6.59 9.39 43,245 3,239 46,484 3.78 $ 175.9 $ 210.7 $ 386.6 $ 55.97 2024 1 1 64% 40% 5,715 353 6,067 6.62 9.39 37,832 3,310 41,142 4.28 $ 175.9 $ 205.3 $ 381.2 $ 62.83 2025 1 1 69% 41% 6,159 356 6,516 6.60 9.39 40,652 3,345 43,997 4.68 $ 205.8 $ 199.3 $ 405.1 $ 62.17 2026 1 1 63% 33% 5,578 292 5,870 6.62 9.39 36,927 2,739 39,666 4.75 $ 188.3 $ 193.5 $ 381.7 $ 65.03 2027 1 1 64% 32% 5,678 277 5,954 6.62 9.39 37,585 2,600 40,185 4.97 $ 199.8 $ 187.9 $ 387.7 $ 65.12 2028 1 1 63% 33% 5,599 285 5,884 6.62 9.39 37,062 2,681 39,743 5.17 $ 205.6 $ 182.6 $ 388.2 $ 65.98 2029 1 1 58% 29% 5,165 257 5,421 6.62 9.39 34,190 2,409 36,599 5.45 $ 199.6 $ 177.5 $ 377.0 $ 69.55 2030 1 1 59% 25% 5,223 217 5,440 6.61 9.39 34,525 2,033 36,559 5.73 $ 209.6 $ 172.6 $ 382.2 $ 70.25 2031 1 1 54% 24% 4,791 211 5,002 6.62 9.39 31,716 1,982 33,698 5.96 $ 200.8 $ 167.7 $ 368.5 $ 73.67 2032 1 1 54% 25% 4,771 218 4,990 6.62 9.39 31,587 2,050 33,637 6.11 $ 205.4 $ 163.0 $ 368.4 $ 73.82 2033 1 1 55% 25% 4,893 221 5,114 6.62 9.39 32,392 2,076 34,468 6.34 $ 218.6 $ 158.2 $ 376.8 $ 73.67 2034 1 1 55% 26% 4,868 226 5,094 6.62 9.39 32,228 2,123 34,351 6.61 $ 226.9 $ 153.4 $ 380.4 $ 74.67 2035 1 1 60% 25% 5,303 220 5,523 6.61 9.39 35,053 2,061 37,114 6.77 $ 251.2 $ 148.7 $ 399.9 $ 72.42 2036 1 1 57% 27% 5,079 234 5,313 6.62 9.39 33,626 2,198 35,824 7.10 $ 254.4 $ 144.0 $ 398.4 $ 74.98 2037 1 1 55% 27% 4,908 238 5,147 6.62 9.39 32,492 2,238 34,730 7.25 $ 251.7 $ 139.3 $ 391.0 $ 75.98 2038 1 1 57% 26% 5,036 232 5,268 6.61 9.39 33,287 2,177 35,465 7.52 $ 266.8 $ 134.6 $ 401.4 $ 76.20 2039 1 1 57% 27% 5,063 238 5,301 6.62 9.39 33,514 2,236 35,750 7.74 $ 276.6 $ 129.9 $ 406.5 $ 76.69 2040 1 1 59% 24% 5,262 209 5,472 6.61 9.39 34,783 1,966 36,749 7.80 $ 286.5 $ 125.2 $ 411.7 $ 75.24 2041 1 1 59% 24% 5,262 209 5,472 6.61 9.39 34,783 1,966 36,749 7.85 $ 288.6 $ 120.6 $ 409.2 $ 74.78 2042 1 1 59% 24% 5,262 209 5,472 6.61 9.39 34,783 1,966 36,749 7.91 $ 290.8 $ 115.9 $ 406.7 $ 74.33 Levelized 8.21% 39,737 $ 3.71 $ 1,447 $ 1,205 $ 2,653 3,790 2023-2040 Escalation: 4.8% $ 138 $ 115 $ 253 $ 66.75 55% 45% $ 36 $ 30 NEXUS Impact $ 0.37 Incorrect incremental cost calculation per Witness Beach $ 10% 3.67 5.5% Impact on Levelized Cost NEXUS Impact $ 0.09 Adjusted to account for only 45,000 Dth/day impa Corrected $ 3% 0.92 1.4% Corrected Impact on Levelized Cost
Exhibit: A-68 Pipeline Reservation Cost Assumptions Page: 1 of 2 Volume Assumptions Max Daily Volume NEXUS to Plant Dawn BH to Plant 185,234 MMBtu/day 75,000 MMBtu/day 110,234 MMBtu/day Transport from NEXUS-Ypsi to Lateral Basis MichCon Pipeline DTE Gas Receipt MichCon Generic Delivery Lateral Reservation Annual Reservation Transport from Dawn to Lateral Basis Dawn Pipeline Vector Receipt Dawn Hub Delivery Lateral Reservation-Dawn Reservation-Canada Reservation-US Annual Reservation
Exhibit: A-68 Pipeline Reservation Cost Assumptions Page: 2 of 2 Transport from Lateral to Plant Receipt Lateral interconnect w/ GLGT, Vector, or DTE Gas Delivery New CCGT Plant Tap/Meter Stn Lateral TOTAL Return on Inv Annual Reservation Compression Location Horsepower Cost per HP Return on Inv On lateral Annual Reservation Balancing Pipeline Receipt Delivery DTE Gas or Union Gas Storage Lateral Annual Reservation