2014 Gas Outlook. Projections through October 2023

Transcription

1 2014 Gas Outlook Natural Gas Supply, Demand, Capacity and Prices in the Pacific Northwest Projections through October 2023 This report, compiled by the Northwest Gas Association (NWGA) and its members, provides a consensus industry perspective of the Pacific Northwest s current and projected natural gas supply, demand, prices and delivery capabilities through The Pacific Northwest in this case includes British Columbia (BC) and the U.S. states of Washington, Oregon and Idaho. Additional information, including white papers on specific natural gas topics, can be found at

2 1 What s New From scarcity to abundance, the transformation of North America s energy landscape is remarkable. Our ability to extract hydrocarbons (e.g., oil, natural gas, propane, butane, etc.) from shale rock formations deep underground is creating supplyside shocks that reverberate across global energy markets. Because of energy resources derived from shale, North America now has the potential to realize its long-sought goal of energy independence. In the meantime, projected long-term low prices of these resources are attracting capital and infrastructure for a U.S.-based industrial renaissance and spurring investment in rapidly developing natural gas transportation options. At the same time, energy-related greenhouse gas emissions in the U.S. have been reduced to a level not seen in more than a decade, in part because of increased substitution of natural gas for coal in power generation. 1 The Pacific Northwest, ideally positioned between two prolific natural gas producing areas, is already reaping the benefits of this profuse gas supply. Manufacturers and other large natural gas consumers are considering locating or expanding in the region, spurred by access to low-cost supply. Likewise, regional electrical utilities are taking advantage of this economical, cleaner-burning fuel, proposing natural gas-fired plants as one means to reduce greenhouse gas emissions and achieve environmental objectives. The long-range affordability of natural gas continues to drive this shift in thinking about the role of natural gas in our region s environment and economy. While prices are higher than a year ago, natural gas remains an energy value especially when compared to its price levels of just five years ago and to the current price of substitute fuels. Then, expectations were that natural gas prices would range between $7 and $10 per thousand cubic feet (Mcf ), or dekatherm (Dth) 2, [Natural gas is] the bridge fuel that can power our economy with less of the carbon pollution that causes climate change. President Barack Obama, 2014 State of the Union Address Since 2000, the oil and gas sector has spent more on low and zero-carbon technologies than the federal government and all other industries combined. Since 1990, the industry has invested more than $250 billion toward improving the environmental performance of its products, facilities and operations. Jack Gerard, CEO, American Petroleum Institute, 2014 State of American Energy 1 U.S. EIA, Monthly Energy Review - U.S. Carbon Dioxide Emissions from Energy Consumption, November An Mcf is a volumetric measure. A Dth is a measure of energy content representing one million British Thermal Units (Btu). While the energy content of a Mcf varies according to a variety of factors, it is roughly equivalent to a Dth (typically 0.95 to 1.05 Dth per Mcf ). For this study, volumetric measures (thousand, million and billion cubic feet; Mcf, MMcf, Bcf ) are used interchangeably with energy measures (dekatherm, thousand dekatherm, million dekatherm; Dth, MDth, MMDth).

3 2 and would only increase over time. Today, the U.S. Energy Information Administration (EIA) projects that the average annual price of natural gas won t exceed $7 before The demand growth projections in this 2014 Outlook represent a modest uptick across most sectors, reflecting generally better economic conditions (see 2014 Regional Economic Outlook, on p. 12). Industrial demand appears to be perking up while gas use for generating electricity shows the most rapid growth rate among the sectors. Interestingly, while growth rates are the same or higher than in the 2013 Outlook, actual volumes projected for the residential and generation sectors are lower. Readers will notice a few new features in this Outlook Study. To better capture anticipated but not-yet-planned-for regional demand, the Demand section includes a couple of reasonable future demand scenarios. The first is a more aggressive regional response by existing and new industrial consumers to lower and more stable natural gas prices. The second scenario examines the effect of replacing existing coal-fired power generation (i.e. Boardman, Centralia) with natural gas. Another new element, added to the Infrastructure section, is a comparison and brief analysis of the preferred resource acquisition strategies dictated by the respective integrated resource plans (IRP) of each NWGA member company. Assembling and locating this information centrally in the Outlook study will help to inform the respective NWGA member company planning processes and other stakeholders. Finally, gas companies utilize a number of assumptions to help understand their resource requirements and plan their systems accordingly. Identifying extreme but plausible weather conditions is a critical part of satisfying their obligation to serve core customers (residential, commercial and firm industrial consumers). Appendix B provides a matrix summarizing some of the key planning assumptions of the region s natural gas utilities. North America s new reality of affordable, abundant natural gas requires new thinking and visionary policies. Many existing natural gas regulations were developed during a time when natural gas was perceived to be scarce and market fundamentals were different than they are today. Policymakers, local communities, natural gas utilities and customers must collaborate to facilitate the creation of new markets and demand for this increasingly important fuel source. We all stand to gain if we make investments and update our policies now to realize the full potential of a natural gasfueled future. For more information, visit www. fuelingthefuture.org.

4 3 Key Conclusions America s natural gas resource, made available by extracting hydrocarbons from shale rock formations deep underground, is fundamentally changing the energy landscape. continues to exceed expectations despite lower natural gas prices, reallocation of capital and concerns over shale production techniques. gas consumers benefit from their proximity to the prolific Western Canadian Sedimentary Basin (WCSB) and U.S. Rocky Mountain (Rockies) natural gasproducing regions. Executive Summary Based on analysis of our members data, we have arrived at a reasonable projection of what the natural gas market may look like in the Pacific Northwest over the next 10 years. Here are our key conclusions and some of the issues we are following closely. Supply Prices Demand Key Variables or improved production technologies and techniques. prices on investments in exploration and production (E&P), and hence on future production. concerns may have on natural gas production. legislation affecting production/extraction processes. Key Conclusions rebounded in 2013 but continue to reflect an abundance of North American natural gas. forecasts have declined significantly since 2008 when large volumes of natural gas from shale began to affect the market. consumers benefit from less price competition with eastern markets as the flow dynamics of natural gas shift from traditional producing regions to geographically diverse shale plays. Key Variables add to the cost of production or limit access to reserves. and improved production technologies. of natural gas for power generation, industrial and transportation uses. growth. changing natural gas flows across North America. storage constraints on regional pricing. North American natural gas exports to premium overseas markets. Key Conclusions Pacific Northwest over this forecast period remain about the same as in the 2013 Outlook, annual volumes start lower. showing signs of life in the region with higher loads and a faster rate of growth than projected in the 2013 Outlook. could significantly affect demand during the Key Variables gas infrastructure to support regional growth opportunities. of the growing use of natural gas for generating electricity to serve growth, balance the system and transition from coal. industrial loads (including exports) due to sustained lower natural gas commodity costs. forecast period. This Outlook explores two growth potential for natural plausible scenarios: some gas as a transportation fuel replacement of regional in a variety of applications. coal-fired generation with natural gas and accelerated energy policies on industrial demand. demand, particularly GHG legislation. (See the Demand chapter for discussion of two scenarios exploring the impact of these variables.)

5 4 Capacity Key Conclusions pipelines and storage facilities has reliably served the load requirements of the region for decades and is sufficient to meet today s needs. required within the forecast horizon to serve new demand for natural gas, particularly on a peak (design) day. Industrial and generation demand above the expected case will amplify and accelerate the need for incremental capacity. expansions have been undertaken to maintain or enhance system reliability in response to increases in base load and peak day demand. of future capacity expansions or additions, and utilization of existing infrastructure, will depend on the changing nature of regional natural gas demand. Key Variables will be needed for generation to meet growing base load power demand and peaking capacity to support intermittent renewable sources of generation. load profile on existing natural gas infrastructure. For example, the generation facilities planned to replace coal-fired power and new industrial facilities could require significant capacity. Where existing pipelines are underutilized, their load factors would increase. As annual load factors and peaking requirements increase, expansion will be needed. eased to allow construction of new or expanded infrastructure in a timely manner to address capacity shortfalls. Projects can take multiple years to develop, making foresight imperative. gas flows if one or more West Coast LNG export terminals are built. Putting the Pieces Together The profusion of natural gas and an expectation that its price will remain affordable over time is creating opportunities for incremental natural gas use across North America. The Pacific Northwest is well situated to take advantage of this low-cost abundance to address a number of objectives, including economic growth, reducing air pollution and improving public health. Faced with modest growth prospects, regional gas utilities are looking at creative ways to expand uses for this relatively clean-burning resource. A variety of projects are under consideration or being developed, especially in the transportation sector. Regional policymakers are also beginning to ask how the benefits of natural gas might be extended to currently unserved communities or expanded within constrained areas. Finally, how the current infrastructure is utilized or expanded remains an open question. The only certainty is that the existing system will need to be augmented at some point to accommodate additional and potentially more variable demand. The market will determine the type and timing of infrastructure projects as new capacity users emerge. Houses of Tomorrow are more energy efficient, use all natural gas appliances and have direct access to natural gas. Cooking Equipment Natural gas unit 3.8 Dth/yr in fullfuel-cycle energy consumption Clothes Dryer 4.4 Dth/yr in full-fuelcycle energy consumption

6 GAS OUTLOOK Supply Key Conclusions hydrocarbons from shale rock formations deep underground, is fundamentally changing the energy landscape. prices, reallocation of capital and concerns over shale production techniques. Western Canadian Sedimentary Basin (WCSB) and U.S. Rocky Mountain (Rockies) natural gas-producing regions. FIGURE S1. North American Shale Formations A Closer Look From scarcity to abundance, the scope and scale of the North American natural gas resource continues to astonish observers. Geographically spread across North America (Figure S1), shale rock formations located several thousand feet below the surface of the earth are the source of hydrocarbons like oil, natural gas and natural gas liquids. Essentially petrified mud, the low permeability of shale rock prevents hydrocarbons from readily flowing using traditional production methods. That is why the production of hydrocarbons from shale was, until recently, impractical and uneconomic. Traditional production taps into more permeable rock formations like sandstone into which hydrocarbons migrated over millennia from the shale formations situated below. The innovative application and improved efficiencies of decades-old production technologies changed all that, making it economically possible to unlock vast reserves of natural gas, oil and other hydrocarbons. Estimates of the total available North American natural gas resource have skyrocketed over the last several years. In 2012, the U.S. Potential Gas Committee (PGC) increased its estimate of the total remaining U.S. gas resource by more than 25 percent over its 2010 report (Figure S2). 3 FIGURE S2. Comparison of PGC Resource Estimates Since ,000 2,500 2,384 Trillion Cubic Feet 2,000 1,500 1,000 Shale resource not assessed separately 1,119 ~200 1, , ,057 1,052 1, Potential Gas Committee, Potential Supply of Natural Gas in the United States, April PGC is an independent, non-profit organization that has been estimating U.S. natural gas reserves since the early 1960s. Traditional Coalbed Shale

7 6 Canada s National Energy Board (NEB) ago, to one of abundance and opportunity (Figure S3). U.S. natural gas production grew expectations despite a soft market. It is upped its estimate of the remaining mar- today. North American natural gas resourc- more than 7 percent in 2011, the largest difficult to keep pace with the industry ketable Canadian natural gas resource from es are now estimated to be sufficient for year-over-year volume increase in history, as producers introduce new or enhanced 424 trillion cubic feet (Tcf ) in 2011 to 1,093 many generations to come. and almost 6 percent in A similar shift technologies and dial in the most effective Tcf in 2013, a staggering increase of more According to Navigant Consulting, from traditional to shale and tight sands gas techniques for producing from each than 250 percent. 4 As a result, natural gas shale plays made up 6 percent of North production is occurring in British Columbia particular field. Figure S4 illustrates this from shale rock formations has changed American natural gas supply in 2007, and (BC). difficulty by plotting recent forecasts of the conversation from one of limited and are expected to make up more than 60 Actual production of natural gas from natural gas production from shale against declining supplies just a handful of years percent of overall production by 2035 shale formations continues to exceed actual production. FIGURE S3. Shale Plays Dominate Future North American Gas Production FIGURE S4. U.S. EIA Forecasts and Actual Shale Production Shale Non-Shale Net LNG Imports BCf/day Bcfd Tcf/year Shale Non-Shale Net LNG Imports Actual 2010 AEO 2012 AEO 2014 AEO (ER) Source: Navigant Consulting Inc. Source: U.S. EIA Forecast - Annual Energy Outlook (AEO) Actual - Annual Natural Gas Gross Withdrawals and Production, Dec Canada National Energy Board, Canada s Energy Future 2013, November 2013

8 7 In the Pacific Northwest, we are immediately adjacent to and supplied by two large natural gas production areas (Figure S5). The WCSB includes the Canadian provinces of BC and Alberta, while the relevant Rockies producing states are Colorado, Utah and Wyoming. The region typically receives more than 50 percent of its gas from the WCSB while the remainder comes from the Rockies. The ability to source gas from different areas gives regional consumers purchasing options. Figure S6 illustrates the proportion of gas sourced from each, which typically depends on a combination of the lowest commodity price along with available pipeline capacity. Combined, these two production areas produced an average of 25 billion cubic feet per day (Bcf/d) in , or 30 percent of North America s total natural gas supply. Put this into perspective, the Northwest uses a little more than 3 Bcf/d on average through the winter months (November through March), although that number can go significantly higher when the weather becomes unusually cold. Production from these two areas is expected to be about 26 Bcf/d by Production in both regions will decline slightly in the near future before resuming a growth pattern in the latter years as new markets open up and commodity prices improve. More specifically, currently declining production of conventional reserves in Alberta will be offset by expanding shale and tight sands production in the large Montney and Horn River plays in northeast BC and continued development of shale in the U.S. Rockies (Figures S7 and S8). FIGURE S5. Supply Regions Serving the Pacific Northwest A L A S K A Liard Fort Nelson B R I T I S H C O L U M B I A Victoria Horn River Shale Gas Cordova Embayment Montney Tight Gas Fort St. John Vancouver Sumas Seattle Portland Duvernay W A S H I N G T O N Wenatchee Spokane A L B E R T A Western Canadian Sedimentary Basin Calgary Kingsgate NWGA MEMBER Pipelines Other Pipelines Natural Gas Supply Basins M O N T A N A Bakken FIGURE S6. Annual Supply Diversity in the Pacific Northwest Percentage 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 9% 9% 8% 9% 9% 8% 9% 9% 8% 7% 8% 37% 36% 41% 44% 46% Alberta Domestic 43% 48% 51% 33% 31% 10% 8% 8% 9% 10% 10% 10% 8% 10% British Columbia Storage 48% 46% 43% 34% 35% 40% 38% 44% 37% 34% % 14% Alberta/Stanfield Prices Rockies/Opal Prices British Columbia/Sumas Prices 40% 18% $9.00 $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 Prices Medford O R E G O N Bend Klamath Falls Malin I D A H O Boise Pocatello Overthrust Green River Big Horn W Y O M I N G Wind River Powder River C A L I F O R N I A Salt Lake City Uinta Denver- Julesburg N E V A D A U T A H Paradox Piceance C O L O R A D O 5 Statistics Canada, Table Annual Supply and Disposition of Natural Gas, 2012; U.S. EIA, Natural Gas Production by State (CO, UT, WY), December 2012

9 8 FIGURE S7. WCSB Production Forecast 6 Bcf/day Key Natural Gas Supply Variables The natural gas supply picture is a rosy one today and is expected to remain that way for the foreseeable future. NWGA members are monitoring a number of evolving issues that could affect supplies, including: hence on future production. 4 BC contribution to total WCSB production 2 0 WCSB Reference Case BC Reference Case WCSB Low WCSB High FIGURE S8. U.S. Rockies Production Forecast 7 16 EIA adjusted to exclude San Juan, Raton, Paradox, and Williston Basins Gas Production (Bcf/day) Production Growth 2013 to 2023 = 2.9 Bcf/d Kinder Morgan Forecast Kinder Morgan Low EIA 2013 AEO Adjusted to Wellhead Kinder Morgan High 6 Canada National Energy Board, Canada s Energy Future 2013, November, Kinder Morgan, 2013 Rockies Production Forecast, September 2013

10 9 BC Gas Supply Outlook It s long been known that BC is a major natural gas supplier, but a report released in 2013 turned gas resource estimates upside down. It s not that past projections were overstating things rather, that they were grossly conservative. The joint federal-provincial government study (by the National Energy Board, BC Oil and Gas Commission, the Alberta energy regulator and the BC Ministry of Natural Gas Development), released in November 2013, more than doubles the estimated amount of unconventional gas resources in BC. This radical change in estimates of the provincial gas supply is the result of gas producers applying new technology to develop unconventional gas economically. Enormous volumes in northeast BC are now dominating the energy supply portfolio. Specifically, there are large volumes of shale gas in the Horn River Basin, the Liard Basin, and the Cordova Embayment, and tight gas in the Montney Formation. Similar to the shale gas and tight gas surge in other producing areas of North America, such as the Marcellus in Pennsylvania and the Eagle Ford in Texas, BC s gas production and resource estimates have experienced growth over the last few years. Before 2009, unconventional gas in North America was not established commercially and gas supply estimates were limited to conventional gas resources. In BC, it was estimated less than 20 Tcf was in place. Now, with the inclusion of shale gas and tight gas, BC has more than 2,700 Tcf of estimated gas in place. 8 Estimates of unconventional gas will continue to change as new wells are developed and technology advances. Current production from most unconventional gas reservoirs only covers a portion of the entire reservoir and there is risk when applying these results over broader areas. However, as geologic understanding evolves and new technologies are made available, new resources become economic. For example, from 2009 to 2012 the Montney Formation was estimated to contain 410 Tcf gas in place. Now, based on the research done in 2013, the estimate is over 1,900 Tcf gas in place. That places the Montney play among the top natural gas basins in the world. Prepared by Brian Morse, Gas Supply Manager Spectra Energy Transmission 8 Gas in place means estimated quantities of natural gas that exist in a reservoir including both recoverable and unrecoverable volumes given existing production technologies. The data in this sidebar relate to BC only.

11 GAS OUTLOOK - Natural Gas Prices Key Conclusions North American natural gas. volumes of natural gas from shale began to affect the market. markets as the flow dynamics of natural gas shift from traditional producing regions to geographically diverse shale plays. A Closer Look Natural gas prices fell to their lowest levels in more than a decade in early This reflected both high supply and low demand due to a warmer than normal winter that year. According to the EIA, the spot price of natural gas rebounded in 2013, averaging $3.73 per Dth at the Henry Hub 9 compared to $2.75 in Current commodity prices demonstrate a continuing surplus of natural gas supply across North America, in stark contrast to the period preceding the advent of the enormous shale resource. In 2008, the spot price of natural gas at the Henry Hub averaged almost $9 per Dth (Figure P1). In addition, the price the market is currently paying for future deliveries of natural gas (futures) and short-term price forecasts indicate that the supply surplus is expected to continue for a few years (Figure P2). Because utilities pass through (without markup) the costs of purchasing natural gas, Pacific Northwest consumers have saved hundreds of millions of dollars since Most longer term forecasts project prices to average between $4 and $7/Dth FIGURE P1. Spot Price of Natural Gas at Henry Hub $14.00 FIGURE P2. EIA Short Term Price Forecast and NYMEX Futures Contract Prices $6.00 $12.00 $10.00 $5.00 $4.00 $/Dth $8.00 $6.00 $/Dth $3.00 $4.00 $2.00 $2.00 $1.00 $0.00 Jan-2008 Apr-2008 Jul-2008 Oct-2008 Jan-2009 Apr-2009 Jul-2009 Oct-2009 Jan-2010 Apr-2010 Jul-2010 Oct-2010 Jan-2011 Apr-2011 Jul-2011 Oct-2011 Jan-2012 Apr-2012 Jul-2012 Oct-2012 Jan-2013 Apr-2013 Jul-2013 Oct-2013 Jan-2014 $- Jan-2014 Feb-2014 Mar-2014 Apr-2014 May-2014 Jun-2014 Jul-2014 Aug-2014 Sep-2014 Oct-2014 Nov-2014 Dec-2014 Jan-2015 Feb-2015 Mar-2015 Apr-2015 May-2015 Jun-2015 Jul-2015 Aug-2015 Sep-2015 Oct-2015 Nov-2015 Dec-2015 NYMEX Gas Futures (2/13/14) EIA Short Term Energy Outlook (2/11/14) 9 The Henry Hub in Louisiana is the pricing point for natural gas futures on the New York Mercantile Exchange (NYMEX). Settlement prices there are used as benchmarks for the entire North American natural gas market.

12 11 through 2023 (2012$). Even factoring in a growing economy, prices are not expected to rise substantially in the next decade due to the abundance of natural gas described earlier (Figure P3). Price-lowering volumes are but one effect of shale gas. North American shale plays are also geographically dispersed across the continent. Because some of the shale plays are also close to large markets (e.g., Marcellus in Pennsylvania and New York), there is less demand from those regions for the resources the Pacific Northwest depends upon. In addition, the price risks associated with weatherrelated supply disruptions in more distant and clustered conventional sources are mitigated (e.g., hurricanes in the Gulf Coast region). Key Natural Gas Price Variables Given continuing abundance of North American supply, consumers are likely to benefit from relatively low natural gas prices for the foreseeable future. NWGA members are tracking a number of market dynamics that could influence natural gas prices going forward: uses. FIGURE P3. Long-Term Natural Gas Price Forecasts $10.00 $9.00 $ $/Dth $7.00 $6.00 $5.00 $4.00 FORECAST $3.00 $2.00 $1.00 $ Historic HH Spot Price EIA 2014 AEO (ER) HH Forecast NWPCC AECO Forecast NWPCC Sumas Forecast NW Power & Conservation Council HH Forecast

13 12 Regional Economic Outlook for 2014 With U.S. and Canadian Gross Domestic Product (GDP) growth crawling in around 2 percent for 2013, North America can again bid adieu to another year of unmemorable growth. As a result, inflation in both countries has been lower than expected and allowed both central banks to continue with accommodative monetary policies. In turn, this allowed the U.S. housing recovery to gain momentum. For 2014, most published forecasts show GDP growth in both countries will be in the percent range, with inflation in the 1-2 percent range. U.S. GDP growth is predicted to be somewhat faster than Canada s. However, there are hurdles to reaching the upper end of this GDP forecast range. First, the European economic recovery is fairly weak and could be undermined by another debt crisis, and China is experiencing a growth slowdown while transitioning to a new generation of political leaders. Weak growth in Europe and China would drag on North American export growth in Second, U.S. and Canadian households are fiscally constrained. U.S. households continue to experience slow income growth, and Canadian household debt continues to be at historically high levels. In the U.S., public sector spending is also constrained by high debt levels and national politics. Finally, there are growing signals that the Federal Reserve will reduce some asset purchases in 2014, which will increase long-term U.S. interest rates. Given that U.S. and Canadian interest rates tend to rise and fall together, this will also put upward pressure on Canada s long-term rates. This could slow real estate and investment activity in both countries. Regionally, U.S. growth in the Pacific Northwest will continue to be stronger in the urban areas around Portland, Seattle and Boise. Following 2013, employment growth in Idaho, Washington, and Oregon will continue to track U.S. growth, which will probably be in the percent range in Due to a significant slowdown in the goods producing sector, employment growth in BC will likely end 2013 near zero, significantly below national growth, which will be around 1.4 percent. The weak employment growth reflects weak growth in new construction, consumer spending and exports. Still, 4Q 2013 data for BC shows a rebound in exports and manufacturing, suggesting that BC will see stronger employment growth in Sources: Bank of Canada, B.C. Stats, Bloomberg.com, Canada Mortgage and Housing Corporation, Scotiabank, Statistics Canada, RBC, T.D. Economics, The Economist, U.S. Bureau of Labor Statistics, U.S. Federal Reserve. Prepared by Grant D. Forsyth, Chief Economist Avista Corp.

14 GAS OUTLOOK - Regional Natural Gas Demand Key Conclusions same as in the 2013 Outlook, annual volumes start lower. rate of growth than projected in the 2013 Outlook. This Outlook explores two plausible scenarios: some replacement of regional coal-fired generation with natural gas and accelerated industrial demand. TABLE D1. Projected Regional Demand Growth through 2023 Total Residential Commercial Industrial Generation Low Expected High Annual Rate Cumulative Annual Rate Cumulative Annual Rate Cumulative 0.9% 8.7% 1.5% 14.2% 2.2% 21.7% 0.7% 6.7% 0.9% 8.8% 1.1% 10.5% 0.4% 3.9% 0.8% 7.6% 1.2% 10.9% 0.7% 6.5% 0.9% 8.3% 1.0% 9.8% 1.9% 18.6% 3.3% 34.0% 5.0% 55.3% A Closer Look According to the EIA, U.S. natural gas consumption is expected to average a record high 71.2 Bcf/d in 2013, an increase of 1.5 Bcf/d (2.1%) from the previous year. In 2014, projected natural gas consumption is expected to fall by 1.6 Bcf/d (2.2%) because of the forecast 4.6% decline in heating degree days and lower natural gas use by the electric power sector. In 2015, natural gas consumption is expected to rise again by 1.4 Bcf/d with growth in use by the industrial and electric power sectors. Moderate economic growth continues across the Pacific Northwest, affecting projections for the demand of natural gas across every sector (see the Regional Economic Outlook sidebar preceding this FIGURE D1. Expected Sector Demand section). Natural gas consumption in the Pacific Northwest is expected to grow an average of 1.5 percent per year for a total volume increase of 14.2 percent (114 million Dth) over the next 10 years (Table D1). While the growth rate is generally consistent with last year s Outlook, expected annual loads average about 1 percent lower than last year s Outlook and almost 17 percent lower than the pre-recession 2008 Outlook. Much of the growth is expected to come from gasfired electrical generation and an uptick in anticipated industrial consumption. Core market demand (residential, commercial) is characterized by modest but steady growth (Figure D1). 200 Million Dth Outlook Figures-6.xlsxFIGURE8 4/2/133:04 PM / / / / / / / / / / Industrial Residential Generation Commercial 260

15 14 Core Market (residential, Industrial The Great Recession production levels. NWGA members are also annual growth rate is 3.3 percent, higher commercial) Growth rates in the cost the region more than 20 percent of reporting increased inquiries from industrial than the 2.6 percent forecast in This residential and commercial sectors remain its industrial gas load between 2007 and users interested in expanding or locating in reflects the region s expectation that, while about the same as last year (0.9 and , although industry remains the largest the region, and there are proposals to build the timing is delayed, it will increasingly rely percent, respectively). Forecasted residential user (Figure D3). A significant portion of facilities to export LNG and petrochemicals on natural gas as the marginal generation volumes, however, start out 3 percent that loss of load came from the permanent that utilize natural gas as a feedstock. In resource. The 2014 Outlook forecast for lower than in the 2013 Outlook (Figure D2). closure of a number of wood and paper response to heightened industrial interest natural gas-fired generation is consistent New housing construction, long a bastion products plants in the region. As the region and activity, we analyze an accelerated with the findings of the Pacific Northwest of dependable growth for the natural gas is now beginning to shed the effects of the industrial demand scenario at the end of this Utility Conference Committee (PNUCC) in its industry in the region, continues to lag recession, the 2014 Outlook forecasts section. LNG exports are not included in this Northwest Regional Forecast. 10 behind pre-recession levels. New customer 6 percent higher industrial volumes than in scenario. Public policy and regulatory initiatives in additions are barely keeping pace with 2013 and a faster growth rate (0.9 percent Generation Projected annual Washington and Oregon have compelled continuing declines in per-customer use vs. 0.6 percent forecast last year). Favorable generation loads are lower at the start of the pending closure of two coal-fired of natural gas due to ever more efficient gas prices are driving the growth, spurring the forecast period than in the 2013 Outlook generation facilities in the region: TransAlta s buildings and appliances. existing industries to resume pre-recession and higher at the end. The forecast average Centralia units and the Boardman plant Figure D2. Residential Demand Forecast Comparison 300 Figure D3. Historic Natural Gas Demand By Sector Million Dth 150 Million Dth * Residential Commercial Industrial Generation * 2014 Outlook Year 1 Forecast 2013 Outlook Forecast 2014 Outlook Forecast 10 PNUCC, 2013 Regional Forecast, May, 2013

16 15 operated by Portland General Electric (PGE). Though no commercial agreements have been executed, it is reasonable to expect that some portion of the output of these plants will be replaced with gas-fired generation. Therefore, we include a simple expanded generation demand scenario at the end of this section. Demand Composition How and when the region uses natural gas has changed. Industrial use of natural gas is typically constant throughout the year; it doesn t vary much with the weather. While Generation: 3% today it makes up about one-third of total annual demand (Figure D4) and its share is forecast to be less than 30 percent at the end of this forecast period. Conversely, gas-fired generation a load that can be quite variable depending on weather and other market conditions once represented a small portion of natural gas demand in the region. By 2012, however, generation claimed more than 20 percent of regional annual gas demand and, in 10 years, is expected to account for more than a quarter of all industrial loads once made up more than regional natural gas use. Residential and half of all regional natural gas demand, commercial loads are also largely weather- Figure D4. Shift In Demand Composition driven and hover around the same standards are designed to meet demand proportionate shares of annual demand. on the coldest day that could occur Overall, then, regional natural gas in a gas utility s service territory. While demand is more variable today, more each company approaches the task a subject to the vagaries of weather than little differently, peak or design days when gas was first delivered to the region are typically based on historical 24-hour more than 50 years ago. Currently, variable average temperatures actually recorded weather-sensitive loads make up more at representative locations. A comparison than two-thirds of the region s natural of the NWGA member company gas use, a share that the 2014 Outlook weather design standards can be found forecasts will increase. Consequently, the in Appendix B. While peak day loads region s infrastructure is being utilized are higher on average than last year s differently today than when it was first forecast, they remain significantly lower built. than the 2008 forecast issued prior to the System Planning Planning recession (Figure D5). Figure D5. Regional Peak Day Forecast Comparison 8 7 Industrial: 51% Residential: 26% Commercial: 20% Generation: 20% Industrial: 32% Residential: 26% Commercial: 19% Million Dth Million Dth Dth Peak Day 2014 Peak Day

17 16 Key Variables Affecting Natural Gas Demand Understanding demand how much, when, where and for what duration natural gas is needed defines the type and size of infrastructure required to serve it. Regional growth in the use of natural gas has historically been driven by the construction of new housing, commercial and institutional facilities, and new industry. The demand projections in this outlook anticipate continued modest economic growth. However, forecast data don t always reflect what s occurring in real-time. The demand for natural gas in the region is changing and NWGA members are watching a number of demand drivers that have yet to be quantified, including: support regional growth opportunities. for generating electricity to serve growth, balance the system and transition from coal. exports) due to sustained lower natural gas commodity costs. natural gas as a transportation fuel in a variety of applications. particularly GHG legislation. Market Development Successes and Challenges Residential customers typically make up a majority of a local distribution company s (LDC) revenues, while industrial customers make up the majority of the load. Many LDCs are seeing stagnant volumes and declining use per customer on the residential side coupled, until recently, with very little growth on the industrial side. With little or no growth, the utilization of a distribution system remains flat or even declines. However, the cost of safely and reliably maintaining and operating those systems is increasing. As customers face ever-increasing rates, they may choose other energy options, thereby exacerbating the situation. That s why LDCs need to grow: to increase system utilization and spread system costs across a broader base. FortisBC has employed a number of initiatives meant to increase the use of its assets, promote system investments and manage the rate impact on customers. A few examples follow. Confronted with a reduction in water heating load and installations in new buildings (primarily multifamily), FortisBC established a pilot pairing an energy efficiency incentive with a sales incentive to install high efficiency on-demand water heaters in individual suites of multifamily developments. At the end of the pilot, FortisBC had secured 19 projects, representing 1,000 individually metered customers. In every case, developers installed not only gas water heating but also other appliances such as cooktops, fireplaces, dryers, BBQs and heating. The revenues realized from the pilot paid for the project costs in less than two years. Natural gas transportation offers another great opportunity to add constant (not weather dependent) loads to the system, thereby increasing utilization and reducing rates for all customers. LDCs are targeting return-to-home fleets including waste hauling, buses, and short-haul tractor-trailers. FortisBC was successful in obtaining the support of the BC Government for these initiatives. Specifically, the Government authorized the utility to earn its authorized rate of return on up to $62 million by offering incentives to vehicle fleets to offset the incremental cost of a natural gas vehicle. To date over half of these incentives have been committed. The Provincial government also directed the British Columbia Utilities Commission (BCUC) to approve a new LNG rate schedule for FortisBC and exempt it from having to secure BCUC approval for a $400 million upgrade to its LNG facility in Tilbury, BC. In response, FortisBC will build new LNG capacity for the transportation market. Prospective demand already exceeds the project s initial proposed capacity. LDCs are also actively engaged in growing loads by helping their communities achieve reductions in greenhouse gas emissions and other pollutants. Biogas, also known as biomethane or renewable natural gas (RNG), has the dual benefit of providing a very low net carbon fuel because it is extracted from waste streams (e.g., landfills, water treatment plants, animal and other agricultural wastes). FortisBC is operating an RNG program, bringing limited volumes of RNG into its system and offering it to customers. FortisBC currently operates two projects extracting methane from a landfill and from agricultural waste. Together these projects supply RNG to more than 5,000 residential customers and several commercial customers. Prepared by Jason Wolfe, Director, Market Development FortisBC

18 17 Possible Regional Demand Scenarios We have developed two scenarios to explore the impact the above variables could have on regional demand and capacity utilization. They include an accelerated industrial growth scenario and a coal replacement scenario. NOTE: these scenarios are created wholly by the NWGA. In developing them, we accessed public information and tested whether our assumptions were reasonable with a number of regional stakeholders. They are solely intended to illustrate possible future outcomes. To our knowledge, neither scenario reflects any actual negotiations or commercial agreements, nascent or otherwise, except as can be found publicly. SCENARIO 1: Accelerated Industrial Demand The most likely candidates for new demand (as opposed to expansion of existing facilities) include L/CNG for transportation (marine, rail, trucking, etc.), food processing, fertilizer and petrochemical production. Loads for a typical facility that might locate here could range from: 3,000-5,000 Dth/day for a food processor; 8,000-12,000 Dth/day for a fertilizer plant; 25,000-50,000 Dth/day for LNG fueling facilities and 125, ,000 Dth/day for a petrochemical plant. All together, these industrial facilities could add between 59 and 79 million Dth to the last year of the expected forecast (2022/23), or an increase in industrial load of between 22 and 29 percent over the expected case. In this scenario, NWGA adjusted the expected case as follows: 5% increase for , 15% increase for and 5% increase for The scenario yields an additional 59.3 million Dth of industrial load by the end of the forecast period, an increase of 22 percent in the last year of the forecast than in the expected case (at the low end of the range described above). The average annual industrial growth rate increases to 3.2 percent from 0.9 percent in the expected case. The scenario adds 6.5 percent to total load and increases the overall growth rate from 1.5 percent to 2.2 percent. SCENARIO 2: Expanded Generation Demand In response to policy and regulatory requirements, PGE agreed to cease coal-fueled generation at the Boardman plant in TransAlta will phase out its Centralia plant, closing Unit 1 by 2020 and Unit 2 by Depending on market conditions, TransAlta intends to replace its coal-fired facility with a clean-burning natural gas plant as part of a planned Centralia 3. Per TransAlta: The Centralia 3 project develops replacement power for the current 1,340-MW capacity Centralia coal-fired plant [t]he proposed new natural gas plant is assumed initially as a roughly one-for-one replacement of Centralia s 670-MW coal-fired Unit PGE is keenly focused on developing renewable fuel alternatives to replace as much of the 550-MW capacity of the Boardman plant as possible, but it has not dismissed the possibility that natural gas generation may contribute. In addition, Grays Harbor Energy (GHE) sought and received approval from Washington s Energy Facility Site Evaluation Council (EFSEC) to add 650 MW of gas-fired generating capacity to its existing 650-MW facility (construction period of up to 22 months to begin no later than December, 2020). 12 This NWGA scenario assumes 800 MW of new combined-cycle gas combustion turbine (CCCT) generation above our expected case forecast (which already accounts for the new PGE Carty plant). Three hundred (300) MW will be added to Western Washington loads in , 200 MW to Eastern Oregon loads (off the GTN pipeline) in and another 300 MW to Western Washington loads in Further assumptions include current turbine technology with a heat rate of 7,000 Btu/kilowatt-hour 13 operated 75 percent of the time (utilization rate). The scenario yields an additional 36.8 million Dth of generation load by the end of the forecast period, an increase of 15 percent in the last year of the forecast than in the expected case. The scenario increases the average annual growth rate to 4.9 percent from 3.3 percent in the expected case. The scenario adds 4 percent to total load in the last year of the forecast and increases the overall growth rate from 1.5 percent to 1.9 percent EFSEC, Amendment 5 to Grays Harbor Energy Center Site Certification Agreement, December 21, A heat rate of 7,000 is representative of the newest CCCT generating units operating in the region (e.g. Port Westward, Mint Farm, etc.).

19 18 FIGURE D6. Additional Growth Scenarios Million Dth Dth / / / / / / / / / /23 Annual Demand Expected Case Accelerated Industrial Accelerated Generation Combined Results If both scenarios were realized, the total annual demand in the last year of the forecast would be 96 million Dth (10.5 percent) higher than the expected case and the overall annual growth rate would increase from 1.5 percent to 2.6 percent. As discussed in more detail in the following section, this suggests accelerated need for additional capacity in the region. Gas & Electric Industries Continue to Collaborate Today, natural gas is the go-to fuel for new on-demand electric generation. Natural gas power plants provide flexibility to meet changes in power demand and can help integrate intermittent resources. Gas is also used for baseload generation and will likely replace 2,000 megawatts of Northwest coal set to retire by As the region constructs more gas-fired power plants, it is important to ensure that the infrastructure can deliver gas to power plants and other users during high demand days. The PNUCC and NWGA have been and will continue to examine gas-electric issues together. One area of recent focus is the Interstate-5 Corridor. Not only does this portion of the system have a significant number of gas power plants, it is the highest populated area of the region and has potential for growing electric power and gas demand. During 2013 we examined the gas infrastructure in the I-5 Corridor under a range of scenarios, including a peak demand day. The initial findings are that the infrastructure is adequate. The report is available at: system-planning/reports. There are numerous other organizations studying gas-electric interdependence and striving to improve system reliability. The Western Interstate Energy Board is conducting an analysis of gas infrastructure in the Western Interconnection. ColumbiaGrid recently published a report examining electric transmission in the event of a gas constraint. The Northwest Mutual Assistance Agreement helps coordinate regional response during gas emergencies. FERC is attentive to the growing gaselectric overlap and is considering synchronizing the gas and electric scheduling day. Natural gas is and will continue to be an important part of the Northwest s electric generation portfolio. PNUCC looks forward to continuing to work with NWGA and other regional entities to study and discuss gas-electric interdependence. Prepared by PNUCC Staff

20 GAS OUTLOOK - Regional System Capacity Key Conclusions requirements of the region for decades and is sufficient to meet today s needs. for natural gas, particularly on a peak (design) day. Industrial and generation demand above the expected case will amplify and accelerate the need for incremental capacity. system reliability in response to increases in base load and peak day demand. existing infrastructure, will depend on the changing nature of regional natural gas demand. TABLE C1. Regional Storage Facilities Facility Owner Type Capacity 1 Max Withdrawal (MDth) (MDth/day) Jackson Prairie, WA Avista, PSE, NWP Underground 25,448 1,196 2 Mist, Table OR C1. Regional NW Storage Natural Facilities Underground 16, Underground Subtotal 41,548 1,716 Plymouth, WA NWP LNG 2, Newport, OR NW Natural LNG 1, Portland, OR NW Natural LNG Tilbury, BC FortisBC Energy LNG Nampa, ID Intermountain Gas LNG Gig Harbor, WA PSE LNG 13 3 Swarr Station, WA PSE LPG Mt. Hayes, BC FortisBC Energy LNG 1, Peak Storage Subtotal 6, Total Storage 48,388 2,582 1 Working gas capacity; gas that can be used to serve the market. 2 Start of season or full rate; storage withdrawal rates decline as working gas volumes decline below certain levels. 3 LPG= Liquid Propane Gas and Air mixture. A Closer Look The Pacific Northwest s 48,000-mile network of transmission and distribution pipelines safely and reliably serves almost 3.5 million natural gas customers. The pipelines that transport natural gas from production areas in Alberta, BC, and the U.S. Rockies can deliver more than 4 Bcf/day to the region. Combined with underground and peak storage facilities (Table C1), the region s natural gas infrastructure is currently capable of delivering more than 6.5 million Dth/day of gas at peak capacity. FIGURE C1. Pacific Northwest Infrastructure and Capacities (MDth) Pipelines Spectra BCP Williams NWP TCPL - GTN Other TCPL FortisBC SCP K-M Ruby Underground Storage Jackson Prairie Mist LNG Storage Nampa Newport Plymouth Portland Tilbury Mt. Hayes