North America Midstream Infrastructure through 2035: Leaning Into the Headwinds

Transcription

1 North America Midstream Infrastructure through 2035: Leaning Into the Headwinds Prepared by ICF International for The INGAA Foundation, Inc. Detailed Study Methodology and Results INGAA Foundation Final Report No ICF International 9300 Lee Highway Fairfax Virginia April 12,

2 Contents Study Overview Methodology and Assumptions Modeling Assumptions and Trends Midstream Infrastructure Overview Midstream Infrastructure Requirements Natural Gas Midstream Infrastructure Requirements Natural Gas Liquids Midstream Infrastructure Requirements Crude Oil and Lease Condensate Incremental Capital Expenditures Economic Impact Methodology Assumptions Results of Economic Impact Analysis Using IMPLAN Conclusions Glossary 1

3 Study Overview 2

4 Study Objectives As in past studies, the objective of this study is to estimate future midstream infrastructure requirements, including natural gas, natural gas liquids, and oil infrastructure requirements through Study is based on detailed supply/demand outlooks for North American energy markets. In the context of this analysis, the midstream includes: o o o Natural gas gathering and lease equipment, processing, pipeline transportation and storage, and LNG export facilities. Natural gas liquids (NGLs) pipeline transportation, fractionation, and NGL export facilities. Crude oil gathering and lease equipment, pipeline transportation, and storage facilities. Study provides an update to the INGAA Foundation s 2014 infrastructure study. Study also analyzes the impacts of midstream infrastructure investments on jobs and the economy. Study has been initiated to more fully consider recent trends and investigate the impacts of those trends, particularly declining commodity prices and an uncertain economic outlook, on future infrastructure requirements. 3

5 Scope of Work This study projects natural gas and liquids infrastructure requirements, by: Considering regional natural gas supply/demand projections. Considering well completion and production information across major supply areas. Considering gas processing requirements by region. Considering how power plant gas use is likely to change in the future. Reviewing underground natural gas storage requirements by region. Completing an analysis of NGL and oil infrastructure requirements by applying well and production information across major supply areas. Considering emerging gas uses, including LNG and Mexican exports. This study assesses the economic impacts of midstream infrastructure investments, by: Completing a regional impact analysis that relies on IMPLAN. Considering the direct, indirect, and induced impacts of the infrastructure development. This study considers new infrastructure needs. It does not investigate replacement of existing infrastructure, nor does it investigate operations and maintenance of existing infrastructure. 4

6 Study Regions Alaska Canada Western Central Midwest Northeast Southeast Southwest Offshore Includes EIA s pipeline regions with regions added for Offshore Gulf of Mexico, Canada, and Alaska. This is the same regional format as used in the INGAA 2011 and 2014 Infrastructure Studies. 5

7 Infrastructure Coverage Midstream Infrastructure Classifications Natural Gas Gas Transmission Mainline Compressors for Gas Transmission Mainline Gas Power Plant Laterals Gas Storage Laterals Gas Processing Plant Laterals Gas Gathering Line Compressors for Gas Gathering Line Gas Lease Equipment Gas Storage Fields Gas Processing Plants LNG Export Facilities Natural Gas Liquids (NGL) NGL Transmission Mainline Pump for NGL Transmission Mainline NGL Fractionation Facilities NGL Export Facilities Crude Oil Crude Oil Transmission Mainline Pump for Crude Oil Transmission Mainline Crude Oil Gathering Line Crude Oil Lease Equipment Crude Oil Storage Laterals Crude Oil Storage Tanks 6

8 Categories of Pipeline Characterized in Study Natural Gas Mainline Pipe New Line New Greenfield New Line - Extensions Expansion - Looping & Compression Expansion - Compression Only Expansion - Reversal or Repurposing Lateral Pipe Power Plant Laterals Gas Storage Field and Oil Storage Tank Laterals Gas Processing Plant Laterals Fractionation Plant Laterals Other Laterals (delivery or receipt area laterals) Gathering Pipe for Oil and Gas Wells Natural Gas Liquids (NGL) Mainline Pipe Oil Mainline Pipe 7

9 Methodology and Assumptions 8

10 Study Methodology and Assumptions Modeling Framework Midstream infrastructure development and capital expenditure requirements are determined based on ICF s Midstream Infrastructure Report (MIR) process. ICF s MIR relies on four proprietary modeling tools, namely ICF s Gas Market Model (GMM), the Detailed Production Report (DPR), an NGL Transport Model (NGLTM), and a Crude Oil Transport Model (COTM). Modeling Tools for the Midstream Infrastructure Report 9

11 Study Methodology and Assumptions (continued) Near-term midstream infrastructure development includes projects that are currently under construction or sufficiently advanced in the development process. Unplanned projects are included in the projection when the market signals the need for new capacity. Lease equipment, gathering, processing, and fractionation infrastructure projects are included for natural gas, NGL, and crude oil development. These types of projects are built as needed to support supply development. This infrastructure typically is financed as part of upstream project development, but is included in this midstream infrastructure analysis because many of the investments are funded by field services operations provided by companies that are active in the midstream space. Arctic projects (specifically the Alaska and Mackenzie Valley gas pipelines) are not included because market prices do not support the development of such projects. Net LNG exports occur from both Western Canada and the United States. 10

12 Study Methodology and Assumptions (continued) The amount of gas used by sector and region at gas prices are computed by ICF s Gas Market Model (GMM). Changes in power generation gas use are computed, and an estimate for the number of new gas power plants is provided. Changes in petrochemical gas use and LNG exports are also considered. The case also projects supply development and production growth that occurs at solved market prices. Gas production projections from the model are cross-checked with a vintage production analysis using ICF s Detailed Production Report (DPR). ICF s DPR considers the number of wells, well recoveries, and representative decline curves to estimate production trends for almost 60 different supply areas. The GMM also projects the amount of gas transmission capacity that is likely to be developed based on the market and supply dynamics. 11

13 Study Methodology and Assumptions (continued) From incremental gas production and well completions, the incremental amounts of gathering line and processing capacity have been computed. Gathering line estimates have been derived based on the number of wells per pad, estimated ultimate recovery (EUR) per well, and by assuming an average mileage of line per well. o An average of 4 wells per pad is assumed for 2015 and is assumed to increased linearly to 8 wells per pad by Higher wells per pad lowers total mileage but requires higher diameter for gathering pipelines. o Low productivity gas wells (EUR less than 0.5 Bcfd/well) and low productivity associated gas from oil wells (EUR less than 0.15 Bcfd/well) use small diameter gathering pipelines and are assumed to require an average of 0.35 miles/well and 0.25 miles/well, respectively. Higher productivity gas and oil wells require larger diameter but shorter gathering pipelines. Processing plant capacity is computed based on the average production of wells and the characteristics of the production stream. o Processing plants requirements are estimated by assuming average plant sizes that are area dependent. Storage capacity is added based on market and supply growth and by considering seasonal price spreads. Laterals mileage and size requirements are derived for gas processing plants, gas power plants, and gas storage facility. Routine replacement of older pipelines in order to comply with ongoing integrity management is included in the estimates of the gas transmission mileage. 12

14 Study Methodology and Assumptions (continued) Horsepower requirements are derived separately for gathering line and each transmission project. Compression requirements for gas gathering lines are computed based on a historical average (141 HP/MMcfd), obtained from various sources, and considering gas production growth by region. Compression requirements for gas storage fields are computed based on a historical average by storage type obtained from various sources. The compression requirements are 1,880 HP/Bcf for salt cavern storage, 610 HP/Bcf for depleted reservoir storage, and 1,200 HP/Bcf for aquifer reservoir storage. Compression requirements for new gas transmission pipelines are computed using Panhandle equations for gas flows in pipelines based on project mileage and size, gas capacity, and number of compressor stations. Crude oil and natural gas liquids (NGLs) production projections are computed in ICF s Detailed Production Report (DPR). The crude oil and NGL pipeline transmission capacity projection is determined by using ICF s Crude Oil Transport Model and ICF s NGL Transport Model, respectively. The Crude Oil Transport Model considers pipeline, rail, truck, and tanker transport of crude oil between 32 regions and over 240 network links in the U.S. and Canada. NGL Transport Model considers pipeline, rail, and truck transport of raw and purity NGLs between 27 regions and over 200 network links in the U.S. and Canada. Pipeline capacity is added based on potential supply and market growth and considering export assumptions. 13

15 Study Methodology and Assumptions (continued) Oil gathering line connections are considered for high productivity oil wells. A minimum EUR cutoff of 30 thousand barrels is assumed to differentiate high productivity wells from low productivity wells. Low productivity wells do not require gathering line as oil production is handled by using local storage and trucks. Expenditures for new trucks are not considered. Oil gathering line estimates have been derived based on number of wells per pad and by assuming an average mileage of line per well. An average of 4 wells per pad is assumed for 2015 and is assumed to increased linearly to 8 wells per pad by Higher wells per pad lowers total mileage but requires higher diameter for gathering pipelines miles/well gathering line is assumed for the 4-well pad and miles/wells for the 8-well pad. Crude oil storage capacity is added based on production growth. Number of crude oil tanks is computed based on storage capacity and assuming an average tank size of 5,000 barrels. Number of tank farms is computed based on an average of 750 tanks per farm in the U.S. and 500 tanks per farm in Canada. Pipeline laterals for the new oil storage capacity is based on average miles of laterals per tank farm (20 miles per tank farm). 14

16 Study Methodology and Assumptions (continued) NGL fractionation capacity: NGL fractionation capacity is added based on NGL production growth. Capacity cost is computed by applying an average unit cost ($/BOE) based on historical expenditure information provided by various sources. NGL export facilities: NGL export capacity is added based on NGL production growth. Assumptions for the NGL export capacities in the U.S. and Canada are 1,800 MBPD in the High Case and 1,600 MBPD in the Low Case. Capacity cost is computed by applying an average unit cost ($/BOE) based on historical expenditure information provided by various sources. LNG export facilities: Assumptions for LNG export capacity in the U.S. and Canada are 12 Bcfd for the High Case and 10.6 Bcfd for the Low Case. Capacity and costs of LNG export facilities have been obtained from DOE export applications and public sources. 15

17 Study Methodology and Assumptions (continued) Oil and gas lease equipment: Lease equipment for oil wells includes accessory equipment, the disposal system, electrification, flowlines, free water knockout units, heater treaters, LACT units, manifolds, producing separators, production pumping equipment, production pumps, production valves and mandrels, storage tanks, and test separators. Lease equipment for gas wells includes dehydrators, disposal pumps, electrification, flowlines and connections, the production package, production pumping equipment, production pumps, and storage tanks. Lease equipment cost estimates have been derived based on cost per well ($/well) that is area/play dependent, derived from EIA Oil and Gas Lease Equipment and Operating Costs data. The cost is adjusted to current cost based on Producer Price Index Industry Data from Bureau of Labor Statistics. Unit cost measures have been derived for pipeline and gathering ($/inch-mile), horsepower ($/HP), processing capacity ($/MMcfd), and storage ($/Bcf) based on historical expenditure information provided by various sources. Detailed cost assumptions are provided in Modeling and Cost Assumptions Section Unit cost measures are applied to estimate total expenditures for midstream infrastructure. 16

18 Midstream Infrastructure Cost Assumptions in 2015$ Pipeline Regional Factors Gathering Line Costs Region Regional Cost Factors Canada 0.80 Central 0.68 Midwest 1.25 Northeast 1.61 Offshore 1.00 Southeast 0.88 Southwest 0.81 Western 1.03 Unit costs assumed for midstream infrastructure development remain constant in real terms throughout the projection. Average pipeline costs are $155,000 per inch-mile in 2015$, varying regionally. The average cost was $163,000 (in 2015$) per inch-mile in the 2014 Study. Pipeline costs determined by Oil & Gas Journal survey of U.S. pipelines, and the small 5% change is due to the inclusion of a broader set of pipeline projects in the current study. Costs for gathering lines vary by diameter. Diameter (Inches) Gathering Line Costs (2015$/inch-mile) 1 $55,147 2 $41,360 4 $34,467 6 $28,827 8 $30, $47, $81, $131, $145,701 17

19 Midstream Infrastructure Cost Assumptions in 2015$ (continued) Compression and pumping costs are $3,000 per horsepower (HP), varying regionally. The average cost was $2,800 per horsepower in the 2014 Study. Costs for lease equipment are $103,000 per gas well and $250,000 per oil well. Gas processing costs (not including compression) are about $525,000 per million cubic feet per day (MMcfd). Costs for NGL fractionation facilities average $6,600 per barrel of oil equivalent (BOE) of NGL processed. Costs for NGL export facilities are purity dependent: $6,300 per BOE of ethane processed, $5,100 per BOE of propane processed, and $5,100 per BOE of Butane processed. Costs for crude oil storage tanks average of $15 per barrel of oil. LNG export facility costs average $5-6 billion per Bcfd of export. Compression and Pumping Regional Factors Region Regional Cost Factors Canada 1.00 Central 1.31 Midwest 1.34 Northeast 1.09 Offshore 1.00 Southeast 0.90 Southwest 0.87 Western 0.80 Field Type Expansion New Salt Cavern $30 $35 Depleted Reservoir Natural Gas Storage Costs (Millions of 2015$ per Bcf of Working Gas Capacity) $17 $20 Aquifer $34 $42 18

20 Modeling Assumptions and Trends 19

21 Study Scenarios Current oil and gas markets are in turmoil. There are significant uncertainties for market growth. Asian economic outlook uncertain. Low oil prices can impact the timing and volume of North American LNG exports. Timing of carbon emission regulations is uncertain, and Energy Efficiency (EE) and penetration of renewables resources could reduce the need of gas-fired power generation. The amount of uncertainty makes it is difficult to foresee a single set of assumptions that applies to the future. Hence, this study considers two scenarios an Optimistic or High Case and a Less-Optimistic or Low Case which can be considered as plausible cases for how oil and gas markets and the associated midstream infrastructure may evolve over time. The Low Case does not reflect a distressed case, due to sustained downturn for a long time, that result in significant bankruptcies that affect existing contracts for pipeline projects. 20

22 Demand Assumptions for the Cases Assumption INGAA High Case (Optimistic) INGAA Low Case (Less-Optimistic) Macroeconomic/Demographic U.S. Economic Growth Rate (GDP Growth Rate) Industrial Production Growth Rate Oil Price in real 2015$/Bbl (Refiners' Average Cost of Crude) 2016 onwards: 2.6% 2.3% per year = $46-$ forward = $ = 2.0% 2026-forward = 2.6% = 1.7% 2026-forward = 2.3% = $30-$ forward = $75 Inflation Rate Natural Gas Demand Electric Sales Growth (Net of Energy Efficiency) Gas demand for bitumen production from Alberta Oil Sands LNG Exports Exports to Mexico 1.0% in % (2016 onwards) change: 0.9 percent per year change: 1.0 percent per year Bitumen production increases to over 3.5 million barrels per day by 2030 Gas use for oil sands development increases to 2.4 Bcfd by 2030 U.S. Gulf Coast: peak at 8.8 Bcfd by 2025 U.S. East Coast: peak at 1.0 Bcfd by 2024 U.S. West Coast: NO LNG EXPORTS British Columbia: 1.4 Bcfd by 2028 Increases to 6 Bcfd by 2025 to 6.8 Bcfd by % in % (2016 onwards) 2016 onwards: 0.3 percent per year Bitumen production increases to 2.75 million barrels per day by 2030 Gas use for oil sands development increases to 1.75 Bcfd by 2030 U.S. Gulf Coast: peak at 6.0 Bcfd by 2029 U.S. East Coast: peak at 0.7 Bcfd by 2028 U.S. West Coast: NO LNG EXPORTS British Columbia: 0.9 Bcfd by 2032 Lower than High Case by 5% 21

23 Production Assumptions for the Cases Assumption INGAA High Case (Optimistic) INGAA Low Case (Less-Optimistic) Oil and Gas Production U.S. and Canadian developable resource base Exploration and Production Costs Totals 4,000 Tcf, of which 60% is shale gas resource; on average, 1000 Tcf of gas resource is developable below $4 per MMBtu. Relative to 2014 study, costs are lower by 20% in 2015, and 25% from 2016 onwards Resource development less robust due to relatively low capital investment Relative to High Case, drilling & completion costs lower by 5% LNG Imports LNG imports continue at existing terminals, but at minimal levels Natural Gas Plant Liquids Crude Oil and Lease Condensate NGL production is expected to increase by 2.3 million BEO/d between 2015 and 2035 Production is flat between 2016 and 2025 and declines thereafter due to reserve depletion Less robust NGLs production especially from tight oil plays due to lower oil prices Further restrictions on oil development due to lower oil prices 22

24 North American Natural Gas Resource Base In total, the U.S. and Canada have over 4,000 Tcf of resource that can be economically developed using current exploration and production (E&P) technologies. It includes 440 Tcf of proven reserves. This represents recoverable resource at gas price below $20/MMBtu. The recoverable resource is approximately 2,700 Tcf and 1,200 Tcf at gas prices below $10/MMBtu and $5/MMBtu, respectively. At current levels of consumption, this is enough resource for about 120 years, 85 years, and 35 years for gas prices below $20, $10, and $5, respectively. As technologies improve and new discoveries are made, the total gas resource is likely to grow. About 60% of the assumed resource is shale gas. If communities or local governments ban shale gas production in specific areas, then overall cost of production would increase, lowering market growth. U.S. and Canada Natural Gas Resource Base (Economically Recoverable Resource, Assuming Current E&P Technologies) Note: Resource base includes all area in the North America, without any restrictions; however, risk for development is considered (e.g., development urban areas, national parks, etc. has higher risk). 23

25 Crude Oil Price Assumption U.S. Refiner Acquisition Cost of Crude Oil (RACC) is expected to recover slowly after the precipitous drop since summer of 2014 to the long-term equilibrium marginal production cost of about $75/Bbl. Global oil inventory is increasing. Short-term global demand recovery remains pessimistic. U.S. oil inventories are rising to unprecedented levels. Oil production from Iran might also add to the already over supplied market in the near term. In the high case, Refiner Acquisition cost of crude oil (RACC) is assumed to rise from current levels to the long-term equilibrium marginal production cost of about $75/Bbl by 2025 and remains flat post In the low case, RACC in 2016 is assumed to average at about 30$/Bbl (2015 real dollars) and below $40 per barrel until 2018 before recovering to $75 per barrel by

26 Projected Natural Gas Price Projected Henry Hub gas prices are likely to average between $3 and $5.5 per million British thermal unit (MMBtu) in the longer term in the high case versus $3 and $4.5 per MMBtu in the low case. Low well drilling costs combined with productivity and efficiency gains will keep price below $4 per MMBtu until 2018 in the high case, and until 2028 in the low case. Henry Hub prices increase from 2016 to 2020 due to ramp up of LNG Exports and increase in power generation gas demand. Accelerated price growth after 2030 reflects incremental power generation demand for nuclear capacity replacement. 25

27 Summary of Key Market Trends (Tcf) Low Case High Case U.S. and Canada % change 15 to % change 15 to 35 Gas Consumption % % Gas Use in Power % 13% Generation Industrial Gas Use % % Gas Production % % Conventional Onshore % -50% Gas Production Unconventional % Onshore Gas 47% Production Shale Gas Production % % Offshore Production % % LNG Imports % % LNG Exports NA NA Net Exports to Mexico % % 26

28 Projected Natural Gas Demand (Average Annual - Bcfd) Low Case High Case *Other includes lease, plant, and pipeline fuel gas use. *Other includes lease, plant, and pipeline fuel gas use. Total gas consumption (including LNG exports and Mexico exports) in the low case is projected to be about 20 Bcfd lower than the high case by 2035, dominated by changes in the power sector. Power gas demand is about 15 Bcfd lower in the low case by 2035 due to lower electric load growth, higher RE and EE penetration. LNG exports in the low case is roughly 2.2 Bcfd lower by 2035 due to lower oil-gas price spreads. The RCI demand mostly unchanged between the two cases. 27

29 High Case - Regional Natural Gas Demand* (Bcfd) U.S. Demand increases are due mostly to power generation growth, LNG exports, and Mexico exports. Canada s gas demand growth is driven by increased industrial and power demand. The growth also includes BC LNG exports. Gulf Coast LNG exports decline slightly after 2030 due increasing gas prices relative to oil prices. *Includes LNG Exports and Mexico Exports. 28

30 Low Case - Regional Natural Gas Demand* (Bcfd) Natural gas demand is down across all regions in the low case mainly due to decrease in power generation gas demand. The largest drop in demand in the low case occurs in the Southeast region followed by Northeast, Southwest, Midwest and Western regions, relative to the high case. *Includes LNG Exports and Mexico Exports. 29

31 Natural Gas Production (Average Annual Bcfd) Low Case High Case Total gas production increases by 1.8% per year in the high case, and 1% per year in the low case by In the high case, shale gas including associated gas from shale/tight oil, grows to nearly 75% of the total production by Conventional gas production declines significantly in both cases at similar rates. In the low case, about 70% of the shale gas reduction occurs in Marcellus, Haynesville, Barnett, Fayetteville, Eagle Ford and Western Canadian shale plays. 30

32 High Case - Regional Natural Gas Production (Bcfd) Northeast and Midwest growth is mostly from the Marcellus and Utica Shales. Growth in the Southwest is driven by production from the Woodford (including the SCOOP & STACK), Haynesville, and Eagle Ford shale plays. Canada production growth is mostly from Horn River and Montney shale plays in British Columbia. Planned offshore projects result in slight increase in gas production. 31

33 Low Case - Regional Natural Gas Production (Bcfd) Low-cost Marcellus and Utica plays continue to dominate growth in gas production even under the low growth assumptions. However, compared with the high case, production is lower by about 5 Bcfd. Lower production in the southwest is mostly due to drop in shale production in the Permian, Eagle Ford, and Barnett plays. 32

34 Liquids Production (Average Annual - MMBPD) Low Case High Case Projected U.S. and Canadian crude oil and condensate production in the high case decreases from current levels in 2015 due to lower oil prices in the near term. NGL production in the U.S. and Canada grows by 2.2% per year, rising to 6.5 MMBPD by 2035 in the high case. Lower projected oil price in the low case has a large impact on crude oil production. U.S and Canada crude oil production in the low case is 2.7 million BPD lower by 2035; nearly half of the reduction in growth occurs in the Alberta oil sands. Projected NGL production in the low case is down by 13% by 2035, versus the high case. 33

35 High Case - Regional Natural Gas Liquids Production (MMBPD) Major NGL production growth regions include: Marcellus (Northeast). Western Canada s Shales including the Montney and Horn River plays. Woodford and Eagle Ford Shale (Southwest). NGL production is dominated by growth in the Marcellus. 34

36 Low Case - Regional Natural Gas Liquids Production (MMBPD) Projected NGL production in this low case is down by 0.8 million BPD compared with the high case by By 2035, NGL production decreases by about 13% in the low case versus the high case NGL production in the low case in southwest, central and Canada regions is down by 33%, 24%, and 20% respectively versus the high case. 35

37 High Case - Regional Crude Oil and Lease Condensate Production (MMBPD) Most of the regions in the U.S. will experience declining crude oil and lease condensate production except the offshore region with deepwater Gulf of Mexico production. Canada production is expected to grow driven by oil sands production in Alberta. By 2035, crude oil and condensate production from U.S. and Canada in the high case is down by about 25% compared to the prior study Base Case due to the reduction in oil prices. 36

38 Low Case - Regional Crude Oil and Lease Condensate Production (MMBPD) By 2035, crude oil and lease condensate production decreases by more than 20% in the low case versus the high case. Drop in Canadian production accounts for more than 50% of the total reduction. Drop in Central and Southwest is due decline in tight oil production in the Bakken, Niobrara, Permian, and Eagle Ford. 37

39 Comparison of Trends with the 2014 Study Oil price trends in both the high and low cases are lower compared with the oil prices assumed in the prior study Base case. Even though the current study projects cumulative gas well completions to be lower in both cases compared with the prior study Base Case, shale gas production growth is still robust and it continues to yield significant development of natural gas infrastructure. Relative to prior study, higher productivity due to improvements in technology and drilling operations, particularly in the most prolific and economically attractive plays, results in greater investments in gathering line and processing capacity. The current slate of gas transportation projects generally require less miles of pipe and rely to a greater extent on using existing infrastructure in different ways - for example, adding compression to increase line capacity and reversing lines to accommodate growth from new production areas. This results in higher gas pipeline and storage compression costs relative to the prior study. Increase in gas use and production leads to greater investments in new laterals to power plants, gas storage, and processing plants. Current study assumes greater new LNG export capacity, resulting in higher capital expenditures relative to the prior study. Oil production growth in the current study is throttled due to much lower crude oil price projection leading to reduced infrastructure needs for oil processing, transport, and storage versus the prior study Base Case. NGL infrastructure investments in the in the high case of the current study are similar to the levels in the prior study Base case. 38

40 Midstream Infrastructure Requirements Overview 39

41 Capital Expenditures for New Infrastructure Total infrastructure investments in both cases are substantial. Even in the Low Case, there is still infrastructure expenditure due to production and demand growth. However, the overall expenditure is lower by $150 Billion in the Low Case, relative to the High Case, with oil and gas being more impacted than NGLs. 40

42 Total Capital Expenditures for New Infrastructure The top graph shows expenditures as reported in the year the projects are completed ( Year of Commissioning ), as in the previous Study. However, the actual CapEx spending spans multiple years before the commissioning, and the bottom graph shows the expenditures, where the CapEx for each project is spent equally across three years (two years before the project, and the year the project comes online) Three-Year Spread. Robust development of between $40 and $50 billion per year during the past five years. Projected annual expenditures, while still significant, decline by a large amount over the next five years. o Still plenty of momentum behind near-term projects, particularly those that are concentrated in constrained areas like the Marcellus and Utica. Post-2020 expenditures average $10 to $20 billion per year, well below recent averages. Average annual expenditure $5 to $10 billion less in the Low Case, versus the High Case. In the subsequent slides, the capital expenditures are based on the Year of Commissioning methodology, unless otherwise noted. 41

43 Pipeline Miles, Compression, and Associated Capital Expenditures from ,000 Miles 1" to 8" > 8" to 16" Low Case > 16" to 24" > 24" Total % of Total 1,000 Miles 1" to 8" > 8" to 16" High Case > 16" to 24" > 24" Total % of Total Natural Gas % NGL % Crude Oil % Total % 1,000 HP 1" to 8" > 8" to 16" > 16" to 24" > 24" Total % of Total Natural Gas 3,897 5, ,621 11,881 91% NGL % Crude Oil % Total 4,079 5, ,372 12, % Billion 2015$ 1" to 8" > 8" to 16" > 16" to 24" > 24" Total % of Total Natural Gas $27.8 $36.5 $25.3 $51.9 $ % NGL $1.5 $16.1 $2.1 $0.2 $ % Crude Oil $7.8 $0.4 $1.5 $12.2 $ % Total $37.2 $52.9 $28.9 $64.3 $ % Natural Gas % NGL % Crude Oil % Total % 1,000 HP 1" to 8" > 8" to 16" > 16" to 24" > 24" Total % of Total Natural Gas 4,875 6, ,861 15,930 86% NGL % Crude Oil ,964 2,165 12% Total 5,213 7, ,841 18, % Billion 2015$ 1" to 8" > 8" to 16" > 16" to 24" > 24" Total % of Total Natural Gas $33.6 $48.0 $45.6 $81.8 $ % NGL $2.0 $21.0 $3.1 $0.2 $26.3 9% Crude Oil $9.4 $0.9 $4.2 $31.8 $ % Total $45.1 $69.9 $52.8 $113.9 $ % 264,000 to 329,000 miles of pipeline (midpoint = 296,500 miles) to 18.5 million HP for pipelines (midpoint 15.7 million HP). $183 to $282 billion CAPEX (midpoint = $227 billion CAPEX). 42

44 Similarities to and Differences from the 2014 Study There is great uncertainty about producer bankruptcies, economic activity, and market development, so this study considers two scenarios, each reflecting very different potential for supply growth and market development. Even though each of this study s scenarios project lower well completions, versus the 2014 study, shale gas production growth is still robust and it continues to yield significant development of natural gas infrastructure. But, the current slate of gas transportation projects continue to require less miles of pipe and also continue to rely to a greater extent on using existing infrastructure than projects completed before Even though less miles of pipe are required, investment in new gas pipelines are still very significant because of continued production growth from areas like the Marcellus and Utica. NGL production growth will generally track natural gas production growth as much of the new natural gas production has a relatively high liquids content. Oil production growth is not as significant, and infrastructure development associated with the delivery of oil is much less than it was in the 2014 study. Even though continued infrastructure development is significant, future development is less than it has been recently as the market has undergone a very robust period of development. This study, like the 2014 study, projects significant job impacts from new infrastructure development. 43

45 Midstream Infrastructure Requirements Natural Gas 44

46 Natural Gas Flows in 2015 (MMcfd) 45

47 Natural Gas Flows in 2035 Low Case (MMcfd) 46

48 Natural Gas Flows in 2035 High Case (MMcfd) 47

49 Summary of Capacity Additions Period High Case Low Case Robust midstream infrastructure development of $40 to $50 billion per year, with aggressive development of shale and tight oil resources 2016 Continued robust buildout of midstream infrastructure for gas, oil, & NGLs Takeaway capacity out of Marcellus and Utica continues to increase LNG export facilities begin to come online Marcellus and Utica takeaway capacity increases by roughly 12 Bcfd Substantial increases in capacity to support natural gas exports Oil-focused development slows Roughly 15 Bcfd in capacity added (1 Bcfd per year), mostly to satisfy growth in gas-fired power generation Marcellus/Utica development and export activity slows Development similar to High Case; capacity comes online due to momentum of ongoing projects and resource development Between 10-20% reduction in capacity development, versus the High Case Midstream development hindered by slower production and market growth No oil-focused development Only half of the natural gas capacity added in the High Case enters service Gas-fired generation growth much more modest 48

50 Pipeline Capacity Added for Natural Gas Transport (Bcfd) Takeaway capacity projected at 44 to 58 Bcfd midpoint of 51 Bcfd % of the capacity originates from the Marcellus and Utica. Significant capacity also required for LNG and Mexican exports. Development slows after the next 5 years. Note: The takeaway capacity total includes the capacity of inter-regional pipelines that move gas from one region to another region, as well as intraregional pipeline capacity. The capacity of intraregional pipelines are included in this study because there are a number of new intra-regional pipeline projects designed to support production, particularly in the Marcellus/Utica region and in Canada. This definition of takeaway capacity is different than the 2014 Study, which only considered inter-regional pipelines Low Case Average Annual U.S. and Canada U.S Canada Central Midwest Northeast Offshore Southeast Southwest Western High Case Average Annual U.S. and Canada U.S Canada Central Midwest Northeast Offshore Southeast Southwest Western

51 Natural Gas Metrics Low Case, Low Case Average Annual High Case, High Case Average Annual Average Annual Average Annual Change Change (%) Gas Well Completions (1000s) % Oil Well Completions (1000s) % Total Well Completions (1000s) % Miles of Transmission Mainline (1000s) % Miles of Laterals to/from Power Plants, Storage Fields and Processing Plants (1000s) % Miles of Gas Gathering Line (1000s) % Inch-Miles of Transmission Mainline (1000s) Inch-Miles of Laterals to/from Power Plants, Storage Fields and Processing Plants (1000s) % % Inch-Miles of Gathering Line (1000s) % Compression for Pipelines (1000 HP) 4, , % Compression for Gathering Line (1000 HP) 7, , % Number of New Gas Power Plants % Gas Storage (Bcf Working Gas) % Processing Capacity (Bcfd) % LNG Export Facilities (Bcfd) % 50

52 Natural Gas Metrics, Current Study Versus Prior Study, Current Study Low Case Average Annual Current Study High Case Average Annual Prior Study Base Case Average Annual Gas Well Completions (1000s) Oil Well Completions (1000s) Total Well Completions (1000s) Miles of Transmission Mainline (1000s) Miles of Laterals to/from Power Plants, Storage Fields and Processing Plants (1000s) Miles of Gas Gathering Line (1000s) Inch-Miles of Transmission Mainline (1000s) Inch-Miles of Laterals to/from Power Plants, Storage Fields and Processing Plants (1000s) Inch-Miles of Gathering Line (1000s) Compression for Pipelines (1000 HP) Compression for Gathering Line (1000 HP) Number of New Gas Power Plants Gas Storage (Bcf Working Gas) Processing Capacity (Bcfd) LNG Export Facilities (Bcfd)

53 Miles of New Natural Gas Pipeline Added (Including Gathering Line) Between 170,000 and 210,000 miles of new pipeline will be added over the next 20 years (midpoint of 190,000 miles). Gathering line accounts for roughly 80% of the total. Future buildout averages between 8,500 and 10,500 miles per year (midpoint of 9,500 miles per year), versus roughly 13,000 miles per year over the past five years, a decline of 20-35% from recent activity. Low Case High Case 52

54 Miles of New Natural Gas Pipeline Added (Excluding Gathering Line) 18,000 and 29,000 miles of new gas pipelines from 2015 through 2035 midpoint of 23,000 miles. Averaging 850 and 1,400 miles per year midpoint of 1,100 miles per year. Activity maintained by buildout from areas like the Marcellus and Utica. Low Case High Case 53

55 Natural Gas Capital Expenditures (Billions of Real Dollars) Low Case, (2015$) Low Case Average Annual (2015$) High Case, (2015$) High Case Average Annual (2015$) Average Annual Change (2015$) Average Annual Change (%) Gas Transmission Mainline Pipe $46.2 $2.2 $76.5 $3.6 -$1.4-40% Laterals to/from Power Plants, Gas Storage and Processing Plants $30.6 $1.5 $50.4 $2.4 -$0.9-39% Gathering Line (pipe only) $28.4 $1.4 $33.7 $1.6 -$0.3-16% Gas Gathering Line Compression $23.5 $1.1 $29.8 $1.4 -$0.3-21% Gas Lease Equipment $23.7 $1.1 $27.0 $1.3 -$0.2-12% Gas Pipeline & Storage Compression $12.8 $0.6 $18.4 $0.9 -$0.3-31% Gas Storage Fields $2.3 $0.1 $4.8 $0.2 -$0.1-52% Gas Processing Capacity $28.3 $1.3 $34.9 $1.7 -$0.3-19% LNG Export Facilities $70.8 $3.4 $76.8 $3.7 -$0.3-8% Total Capital Expenditures $266.6 $12.7 $352.5 $16.8 -$4.1-24% 54

56 Natural Gas Capital Expenditures, Current Study Versus Prior Study Base Case, (Billions of Real Dollars) Current Study Low Case Average Annual (2015$) Current Study High Case Average Annual (2015$) Prior Study Base Case Average Annual (2015$)* Gas Transmission Mainline Pipe $2.2 $3.6 $4.2 Laterals to/from Power Plants, Gas Storage and Processing Plants $1.5 $2.4 $2.2 Gathering Line (pipe only) $1.4 $1.6 $1.7 Gas Gathering Line Compression $1.1 $1.4 $1.1 Gas Lease Equipment $1.1 $1.3 $1.3 Gas Pipeline & Storage Compression $0.6 $0.9 $0.5 Gas Storage Fields $0.1 $0.2 $0.5 Gas Processing Capacity $1.3 $1.7 $1.2 LNG Export Facilities $3.4 $3.7 $2.2 Total Capital Expenditures $12.7 $16.8 $14.9 *Capital expenditures reported in the prior study were converted from 2012$ to 2015$ using 4.3% inflation factor. 55

57 Natural Gas Capital Expenditure Trends Robust investments in 2016 (roughly $40 billion) and almost all of the projects are under construction. Investments in are also robust in both cases as most of the projects are either under construction or well along in the planning stage. The low case, however, signals that projects are at risk if shippers back out of projects due to prolonged uncertainty. After 2019, the investments for gas infrastructure are much lower in both cases due to the overbuild in the period. Average investments are about a quarter of the investments during The Three-Year Spread shows declining spending in gas infrastructure developments starting next year through Increased investments around 2025 in both cases is related to LNG export projects in Western Canada. In the subsequent slides, the capital expenditures are based on the Year of Commissioning methodology, unless otherwise noted. 56

58 Regional Natural Gas Pipeline Metrics and Capital Expenditures Low Case, Central Midwest Northeast Offshore Southeast Southwest Western Canada Arctic Total Miles of Mainline (1000s) Miles of Laterals (1000s) Miles of Gathering Line (1000s) Compression Transmission (1000 HP) , , ,252 Compression Gathering Line (1000 HP) , , , ,628 CapEx Mainline (Billion 2015$) $0.3 $6.0 $21.2 $0.1 $4.0 $2.8 $0.0 $11.8 $0.0 $46.2 CapEx Laterals (Billion 2015$) $1.2 $2.4 $14.2 $0.0 $5.2 $4.5 $0.4 $2.7 $0.0 $30.6 CapEx Gathering Line (Billion 2015$) $3.8 $0.1 $5.8 $0.2 $0.1 $13.1 $0.4 $4.7 $0.1 $28.4 CapEx Mainline Compression (Billion 2015$) $0.4 $2.1 $3.6 $0.0 $1.0 $1.8 $0.1 $3.7 $0.0 $12.8 CapEx Gathering Line Compression (Billion 2015$) $2.8 $0.2 $10.6 $0.8 $0.0 $4.4 $0.1 $4.6 $0.0 $23.5 Total CapEx (Billion 2015$) $8.5 $10.8 $55.4 $1.2 $10.4 $26.6 $1.0 $27.5 $0.1 $141.5 High Case, Central Midwest Northeast Offshore Southeast Southwest Western Canada Arctic Total Miles of Mainline (1000s) Miles of Laterals (1000s) Miles of Gathering Line (1000s) Compression Transmission (1000 HP) , , , ,205 Compression Gathering Line (1000 HP) , , , ,726 CapEx Mainline (Billion 2015$) $1.6 $7.3 $28.7 $0.1 $20.6 $5.3 $0.4 $12.5 $0.0 $76.5 CapEx Laterals (Billion 2015$) $1.6 $5.0 $22.3 $0.1 $10.6 $6.5 $1.0 $3.3 $0.0 $50.4 CapEx Gathering Line (Billion 2015$) $4.9 $0.1 $6.5 $0.3 $0.1 $15.6 $0.5 $5.5 $0.1 $33.7 CapEx Mainline Compression (Billion 2015$) $0.8 $2.2 $4.7 $0.0 $4.0 $2.5 $0.2 $3.9 $0.0 $18.4 CapEx Gathering Line Compression (Billion 2015$) $3.8 $0.2 $12.8 $1.2 $0.0 $6.2 $0.1 $5.5 $0.0 $29.8 Total CapEx (Billion 2015$) $12.8 $14.9 $75.0 $1.7 $35.3 $36.2 $2.3 $30.7 $0.1 $

59 Regional Natural Gas Capital Expenditures in High Case, (Billions of 2015$) 58

60 Regional Natural Gas Capital Expenditures in Low Case, (Billions of 2015$) 59

61 Midstream Infrastructure Requirements Natural Gas Liquids 60

62 NGL Flow Comparison Low Case High Case In the high case, NGL transport capacity increases between the Marcellus and Utica region to the Gulf Coast, and then expanded further in the early 2020 s. Growing Marcellus and Utica production serves Gulf Coast petrochemical and export demand. Diluent is transported to Western Canada for Oil Sands development and transportation. In the low case, less NGL capacity is constructed between the Northeast and the Gulf Coast, as a result of lower petrochemical and export demand. NGLs coming from West Texas arrive via track rather than pipeline. 61

63 Pipeline Capacity Added for NGL Transport (Million BPD) U.S. and Canadian NGL takeaway capacity projected at 1.1 to 2.3 million BPD midpoint 1.7 million BPD. New capacity distributed across a number of areas. Development much more limited in the Low Case, as oil prices and global economic activity have a more pronounced impact on liquids markets. Originating Region Low Case High Case Average Annual U.S. and Canada U.S Canada Central Midwest Northeast Offshore Southeast Southwest Western Average Annual U.S. and Canada U.S Canada Central Midwest Northeast Offshore Southeast Southwest Western

64 Natural Gas Liquids Metrics Miles of Transmission Mainline (1000s) Inch-Miles of Transmission Mainline (1000s) Pump for Transmission Mainline (1000 HP) Fractionation Capacity Built (MBOE/d) NGL Export Facility Capacity Built (MBOE/d) Low Case, Low Case Average Annual High Case, High Case Average Annual Average Annual Change Average Annual Change (%) % % % 2, , % 1, , % 63

65 Natural Gas Liquids Metrics, Comparison with Prior Study, Current Study Low Case Average Annual Current Study High Case Average Annual Prior Study Base Case Average Annual Miles of Transmission Mainline (1000s) Inch-Miles of Transmission Mainline (1000s) Pump for Transmission Mainline (1000 HP) Fractionation Capacity Built (MBOE/d) NGL Export Facility Capacity Built (MBOE/d)

66 Natural Gas Liquids Capital Expenditures (Billions of Real Dollars) NGL Transmission Mainline (pipe and pump) Low Case, (2015$) Low Case Average Annual (2015$) High Case, (2015$) High Case Average Annual (2015$) Average Annual Change (2015$) Average Annual Change (%) $20.0 $1.0 $26.3 $1.3 -$0.3-24% Pipe $18.7 $0.9 $24.3 $1.2 -$0.3-23% Pump $1.3 $0.1 $2.0 $0.1 $0.0-33% NGL Fractionation $16.3 $0.8 $20.2 $1.0 -$0.2-20% NGL Export Facilities $7.0 $0.3 $8.0 $0.4 $0.0-12% Total Capital Expenditures $43.3 $2.1 $54.6 $2.6 -$0.5-21% 65

67 Natural Gas Liquids (NGL) Capital Expenditures, Current Study Versus Prior Study Base Case, (Billions of Real Dollars) Current Study Low Case Average Annual (2015$) Current Study High Case Average Annual (2015$) Prior Study Base Case Average Annual (2015$) NGL Transmission Mainline (pipe and pump) $1.0 $1.3 $1.2 Pipe $0.9 $1.2 $1.1 Pump $0.1 $0.1 $0.1 NGL Fractionation $0.8 $1.0 $1.0 NGL Export Facilities $0.3 $0.4 $0.3 Total Capital Expenditures $2.1 $2.6 $2.4 66

68 NGL Capital Expenditure Trends As in the gas infrastructure, similar investment levels in both cases in the NGL infrastructure through 2019 result from under-construction and advanced projects. In 2020, incremental Appalachia takeaway capacity is needed, particularly in the High Case. This capacity in not necessary in the Low Case. Under the Three Year Spend approach, investments in this projects are spread evenly from 2018 resulting in declining trend in NGL infrastructure spending from today s level. In the subsequent slides, the capital expenditures are based on the Year of Commissioning methodology. 67

69 Regional Natural Gas Liquids Capital Expenditures in High Case, (Billions of 2015$) 68

70 Regional Natural Gas Liquids Capital Expenditures in Low Case, (Billions of 2015$) 69

71 Midstream Infrastructure Requirements Crude Oil and Lease Condensate 70

72 Crude Oil Flow Comparison Low Case High Case In the high case, increasing Canadian Oil Sands production is transported eastward via pipeline. Oil Sands production also moves to the US Upper Midwest to be either refined in Illinois, or transported further to the Gulf Coast. Pipelines are constructed to move crude from Cushing and West Texas to the Gulf Coast. In the low case, less Oil Sands production does not support oil pipeline development in Canada, and most of the crude moves to the Central US region. More oil is transported via rail due to uncertainty. 71

73 Pipeline Capacity Added for Crude Oil and Condensate Transport (Million BPD) U.S. and Canadian oil capacity projected at 4.5 to 6.9 million BPD. But, much of the capacity has already been built, and was placed into service in late Most, if not all of the projects to be commissioned in 2016 are likely to be completed already under construction. Most projects are less likely to be completed. Low Case projects that no additional capacity is needed. Originating Region Originating Region Low Case High Case Average Annual U.S. and Canada U.S Canada Central Midwest Northeast Offshore Southeast Southwest Western Average Annual U.S. and Canada U.S Canada Central Midwest Northeast Offshore Southeast Southwest Western

74 Crude Oil Metrics Low Case, Low Case Average Annual High Case, High Case Average Annual Average Annual Change Average Annual Change (%) Oil Well Completions (1000s) % Miles of Crude Oil Gathering Line (1000s) % Miles of Transmission Mainline (1000s) % Miles of Crude Oil Storage Laterals (1000s) Inch-Miles of Crude Oil Gathering Line (1000s) Inch-Miles of Transmission Mainline (1000s) Inch-Miles of Crude Oil Storage Laterals (1000s) Pump for Transmisson Mainline (1000 HP) % % % % , % Crude Storage Capacity Built (MMBbl) % Number of Crude Storage Tanks Built 5, , % Number of Crude Storage Farms Built % 73

75 Crude Oil Metrics, Comparison with the Prior Study, Current Study Low Case Average Annual Current Study High Case Average Annual Prior Study Base Case Average Annual Oil Well Completions (1000s) Miles of Crude Oil Gathering Line (1000s) Miles of Transmission Mainline (1000s) Miles of Crude Oil Storage Laterals (1000s) Inch-Miles of Crude Oil Gathering Line (1000s) Inch-Miles of Transmission Mainline (1000s) Inch-Miles of Crude Oil Storage Laterals (1000s) Pump for Transmisson Mainline (1000 HP) Crude Storage Capacity Built (MMBbl) Number of Crude Storage Tanks Built Number of Crude Storage Farms Built

76 Crude Oil Capital Expenditures (Billions of Real Dollars) Low Case, (2015$) Low Case Average Annual (2015$) High Case, (2015$) High Case Average Annual (2015$) Average Annual Change (2015$) Average Annual Change (%) Crude Oil Gathering Line (pipe only) $7.7 $0.4 $9.3 $0.4 ($0.1) -17% Crude Oil Lease Equipment $115.2 $5.5 $142.8 $6.8 ($1.3) -19% Crude Oil Transmission Mainline (pipe and pump) $13.8 $0.7 $36.4 $1.7 ($1.1) -62% Pipe $10.8 $0.5 $29.4 $1.4 ($0.9) -63% Pump $3.0 $0.1 $7.0 $0.3 ($0.2) -57% Crude Oil Storage Laterals $0.3 $0.0 $0.7 $0.0 ($0.0) -48% Crude Oil Storage Tanks $0.4 $0.0 $0.7 $0.0 ($0.0) -40% Total Capital Expenditures $137.5 $6.5 $189.8 $9.0 ($2.5) -28% 75

77 Crude Oil Capital Expenditures, Current Study Versus Prior Study Base Case, (Billions of Real Dollars) Current Study Low Case Average Annual (2015$) Current Study High Case Average Annual (2015$) Prior Study Base Case Average Annual (2015$) Crude Oil Gathering Line (pipe only) $0.4 $0.4 $0.6 Crude Oil Lease Equipment $5.5 $6.8 $9.1 Crude Oil Transmission Mainline (pipe and pump) $0.7 $1.7 $2.5 Pipe $0.5 $1.4 $2.2 Pump $0.1 $0.3 $0.4 Crude Oil Storage Laterals $0.0 $0.0 $0.1 Crude Oil Storage Tanks $0.0 $0.0 $0.1 Total Capital Expenditures $6.5 $9.0 $

78 Crude Oil Capital Expenditure Trends As expected, the peak crude oil infrastructure investment is in 2014 when oil prices were well above $100 per barrel. Declining infrastructure developments starting in 2015 are expected to continue in both cases through 2018 due to low oil prices. Crude oil price recovery in the two cases, starting in 2020, has a positive impact in infrastructure development thereafter. In 2022, condensate exports from British Columbia results in higher expenditures in both cases. The Three-Year Spread shows a smoother near-term spending trend. 77

79 Regional Crude Oil Capital Expenditures in High Case, (Billions of 2015$) 78

80 Regional Crude Oil Capital Expenditures in Low Case, (Billions of 2015$) 79

81 Incremental Capital Expenditures 80

82 Methodology and Assumptions PHMSA s Gas Transmission Integrity Management Rule (49 CFR Part 192, Subpart O) specifies how pipeline operators must identify, prioritize, assess, evaluate, repair and validate the integrity of gas transmission pipelines that could affect High Consequence Areas (HCAs) i.e., specific areas with populated and occupied areas. Capital expenses associated with routine replacement and refurbishment of natural gas transmission pipelines is already included in the expenditures shown earlier. However, pipeline owners are expecting to spend incremental capital expenditure on conforming to new pipeline integrity requirements and to ensure that NOx emissions from compressors are compliant with the new National Ambient Air Quality Standards (NAAQS) for ozone and the one-hour nitrogen dioxide (NO2) emissions. Incremental capital expenditure is planned for in-line inspection, hydrostatic testing, and valve automation. For compressors, incremental capital expenditure is planned for upgrading existing reciprocating engines with low NOx control upgrading to meet the new NAAQS standards. 81

83 Incremental Capital Expenditure Estimates in U.S. (Billions of 2015$), Gas Pipelines and Compressors Central $4.4 Midwest $3.4 Northeast $2.4 Offshore $0.2 Southeast $3.7 Southwest $7.6 Western $2.1 Arctic $0.1 Total $23.9 Note: Data for the incremental expenditure for the compressors and gas pipelines in the U.S. was provided by INGAA Total capital expenditures for integrity management on pipelines and installing low-nox equipment on compressors will be about $24 billion from 2015 through Most of the expenditures will be in the Southwest region, followed by Central and Southeast regions. 82

84 Total Capital Expenditure for Midstream Infrastructure Adding the $24 billion incremental capital expenditures brings the total midstream infrastructure investments to about $621 billion and $471 billion (in 2015$) in the High Case and the Low Case, respectively. These total expenditures are used for the economic analysis that will follow in the next slides. 83

85 Economic Impact Methodology Assumptions 84

86 IMPLAN Modeling Analysis relies on IMPLAN modeling, a proprietary model maintained by the Minnesota IMPLAN Group ( IMPLAN is a widely used and effective regional economic analysis model that uses average expenditure data from industries. IMPLAN uses multipliers to trace and calculate the flow of dollars from the industries that originate the economic activity to supplier industries that generate additional activity. These multipliers are thus coefficients that describe the response of the economy to a stimulus (a change in demand or production). Three types of impacts used in IMPLAN: Direct represents the economic impacts (e.g., employment or output changes) due to the direct investments, such as payments to companies in the relevant industries for the asset category in this study. Indirect represents the economic impacts due to the industry inter-linkages caused by the iteration of industries purchasing from industries, brought about by the changes in final demands (e.g., when pipeline manufacturer purchases steel from another company). Induced represents the economic impacts on all local industries due to consumers consumption expenditures arising from the new household incomes that are generated by the direct and indirect effects of the final demand changes (e.g., a worker purchases new clothing or purchases food in restaurants). 85

87 Sector Allocations of Investment Expenditures (Direct Output) for National-Level Economic Impact Analysis Industry Sector Gathering Line (excludes compressors) Lease Equipment Gas Processing Pipeline (excludes compressors and pumps) Compressors (gathering line, pipeline, and gas storage) Oil, Gas & Other Mining 5.8% 0.0% 0.2% 5.8% 5.3% 5.3% Construction 36.2% 39.7% 28.0% 36.2% 30.1% 27.6% Manufacturing 29.4% 22.2% 44.9% 29.4% 37.7% 40.2% Wholesale and retail trade 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Transportation 2.1% 2.1% 1.5% 2.1% 2.0% 2.0% Services & All Other 26.5% 36.0% 25.4% 26.5% 24.9% 24.9% Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Pumps Industry Sector Underground Gas Storage (excludes compressors and pipelines) LNG Plant NGL Fractionation Plant NGL Export Facility Crude Oil Storage Tanks All Infrastructures Analyzed Oil, Gas & Other Mining 69.9% 0.3% 0.2% 0.3% 5.3% 8.9% Construction 4.5% 28.3% 28.0% 28.3% 31.3% 28.9% Manufacturing 13.6% 32.9% 44.9% 32.9% 36.5% 33.2% Wholesale and retail trade 0.1% 0.0% 0.0% 0.0% 0.0% 0.0% Transportation 8.1% 2.1% 1.5% 2.1% 2.0% 2.5% Services & All Other 3.7% 36.3% 25.4% 36.3% 24.9% 26.4% Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 86

88 National Tax Rates on Gross Domestic Product (GDP) Federal Tax Rate on GDP Weighted Average State/Provincial and Local Tax Rate on GDP Total U.S % 15.3% 33.0% % 15.6% 34.9% % 15.8% 35.4% % 16.0% 35.8% % 16.2% 36.3% Canada % 19.6% 31.0% 87

89 Distribution of National-Level Economic Impacts Across Regions using Region-Level Allocators National-level economic impact results, by individual infrastructure category, are distributed across regions based on region-level allocators. National direct impacts (e.g. direct value added) are distributed to regions and states based on expenditure allocators. Expenditure allocators are calculated from infrastructure investment expenditures. In this analysis, investment expenditures for the U.S. Offshore region is assumed to be spent in the Southwest region. National indirect impacts (e.g. indirect value added) are distributed to regions based on a combination of expenditure allocators (60% weight) and Indirect Industrial Jobs allocators (40% weight). National induced impacts are distributed to regions based on a combination of the Direct & Indirect Value Added allocators (40% weight) and State Personal Income in 2013 (60% weight). Direct & Indirect Value Added allocators are calculated from the sum of regional direct and the indirect Value Added, as discussed above. Region Region-Level Allocators Indirect State Personal Industrial Jobs a Income 2013 b Central 6.6% 7.7% Midwest 26.8% 15.9% Northeast 25.7% 27.5% Southeast 16.5% 17.4% Southwest 12.7% 11.7% Western 11.6% 19.6% Arctic 0.0% 0.3% Total 100.0% 100.0% a Weighted average of industries that support construction and equipping industrial activities based on IMPLAN input-output model and U.S. Bureau of Labor statistics data. b State personal income FY 2013 from Tax Policy Center (Urban Institute and Brookings Institution). State and Local General Revenue as a Percentage of Personal Income FY Tax Policy Center, 24 November, 2015: Washington, DC. 88

90 Distribution of U.S. Tax Revenues Across Regions Using State/Local Tax Allocators National-level tax revenues (federal and state/provincial/ local) are calculated from Total Value Added and tax rates on GDP (federal and state/provincial/local). For the U.S., total state and local tax revenues are distributed across the regions based on region-level State/Local Tax allocators. Region U.S. State/Local Tax Allocators State and Local Tax Rate on GDP FY 2013* Central 15.6% Midwest 15.2% Northeast 15.0% Southeast 14.7% Southwest 14.6% Western 15.0% Arctic 33.9% * State and Local General Revenue as a Percentage of Personal Income FY 2013, Urban Institute and Brookings Institution, ct.cfm?docid=510 89

91 Results of Economic Impact Analysis Using IMPLAN 90

92 U.S. and Canada: Economic Impacts, Impact Type Employment (Jobs each Year) Annual Wages and Benefits (2015$ Per Job) Labor Income (Billions of 2015$) Low Case, Total Expenditures = $471.2 (Billions of 2015$) Value Added (Billions of 2015$) Direct 107,752 $77,689 $175.8 $215.7 Indirect 86,556 $66,489 $120.9 $193.9 Induced 128,839 $50,733 $137.3 $245.4 State/Provincial and Local Tax Revenues (Billions of 2015$) Federal Tax Revenues (Billions of 2015$) Total 323,146 $63,941 $433.9 $655.0 $107.3 $116.1 High Case, Total Expenditures = $620.8 (Billions of 2015$) Direct 141,530 $77,971 $231.7 $282.6 Indirect 114,088 $66,631 $159.6 $256.3 Induced 168,960 $50,800 $180.2 $322.3 Total 424,579 $64,111 $571.6 $861.2 $140.9 $ ,000 to 425,000 jobs per year for new infrastructure development 91

93 U.S. and Canada Total Employment by Asset Category, (Jobs each Year) Low Case (323,146) High Case (424,579) 2,953 1% 1,451 0% 27,276 8% 10,750 3% 53,789 17% 5,336 2% 286 0% 24,590 8% 91,648 28% 6,097 2% 13,357 3% 3,031 1% 35,438 8% 6,082 2% 58,370 14% 29,344 7% 473 0% 112,012 26% 86,372 27% 18,696 6% 137,324 32% 23,050 5% 92