NATURAL GAS INFRASTRUCTURE IN THE PACIFIC NORTHWEST

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1 VOLUME 4, ISSUE 1 NATURAL GAS INFRASTRUCTURE IN THE PACIFIC NORTHWEST IN THIS ISSUE Status of the region s existing infrastructure Why the region will need new delivery capacity in the future Projects already proposed to keep gas flowing I f location is the key to real estate value, Pacific Northwest natural gas consumers are sitting on some very hot property. Situated between two prolific gas production areas the Western Canadian Sedimentary Basin (WCSB) and the U.S. Rockies the Northwest has historically enjoyed abundant natural gas supplies. Access to these large and growing gas supply basins will prove even more valuable to regional consumers in the years ahead. Although the recent economic downturn has slowed demand growth in the short term, there are other forces at work expected to boost the region s appetite for natural gas in the longer term, notably new climate change policies. By mandating reductions in carbon emissions, newly enacted energy laws provide incentives to boost energy efficiency and switch to more environmentally friendly fuels and energy sources. Because natural gas is a clean, efficient and abundant source of energy, that means it will play a vital role in our future energy portfolio whether heating homes, generating electricity, powering industry or fueling vehicles. Why do climate change policies encourage the use of natural gas? Because it emits far less carbon and other pollutants than coal and fuel oil when burned, is domestically abundant, and is 90% efficient when used directly, such as to heat a home. And we can count on it when the sun isn t shining and the wind isn t blowing. facilities is measured in years, not months. If we don t plan ahead, we will be ill-prepared for the future. Infrastructure developers are already pursuing several projects to add or expand delivery capacity. These efforts, triggered by the market s need for more supply as well as additional supply alternatives, are expected to result in a mix of new pipelines, storage capacity and import terminals to serve the Northwest in the future. They will provide access to more gas from the abundant supply areas traditionally serving the region, and also the option of accessing new and emerging supplies across the continent and globe. The question is, then, how do we keep natural gas flowing to ensure regional consumers needs are met in the future? We may have adequate delivery capacity now, but growing demand will require additional infrastructure. And the time it takes to plan, obtain permits, secure financing, and build such This white paper takes a brief look at the region s existing natural gas supply infrastructure and explores what market influences will eventually require new delivery capacity, the process for building new delivery facilities, and what projects are already being pursued to serve our future energy needs.

2 INFRASTRUCTURE SERVING THE REGION NOW Currently, 48,000 miles of natural gas transmission and distribution pipelines serve more than 3.1 million residential, commercial, industrial and electric power generation customers in the Pacific Northwest. 1 Combined with underground and liquefied natural gas (LNG) storage facilities, the region s natural gas system is currently capable of delivering 6.3 million Dekatherms per day (Dth/day) at peak capacity. That s more energy than five Grand Coulee Dams. This capacity includes pipeline and storage expansions completed in recent years. Additional storage expansions are also under way which will increase the region s peak day delivery capacity to almost 6.5 million Dth/day in (Stored gas plays a vital role providing cost-effective supply during peak use periods, such as extremely cold winter days.) Key Pacific Northwest Infrastructure Station Projected Annual Demand By Sector - Base Case Million Dth Residential Commerical Generation Industrial According to the Northwest Gas Association (NWGA) 2009 Northwest Gas Outlook, 2 if demand for natural gas grows as expected (called the base case growth scenario), these facilities appear sufficient to serve average regional needs for the next few years Sumas 1292 Kingsgate Starr Road Stanfield 638 Malin 2119 Pipelines Spectra Energy Western Canadian Operations Terasen S. Crossing TransCanada GTN Williams NWP Nova Inventory Transfer 62 Kemmerer 655 Storage Facilities Jackson Prairie Mist LNG Storage Facilities Nampa Newport Plymouth Tilbury Portland 1 This includes Washington, Oregon and Idaho in the U.S. and British Columbia (BC), Canada. The region will need to expand its natural gas infrastructure eventually, and here s why: Regional demand continues to grow. While the recent recession has slowed growth in natural gas demand, this is expected to be temporary and won t likely change cumulative growth projections. According to the NWGA s 2009 Outlook, natural gas demand in the Northwest is projected to grow 1% per year, on average, or a cumulative 8.6% in the next decade. Most of this increase will be driven by demand for gas-fired electrical generation, now encouraged by environmental mandates, and continued growth in residential demand. Under this expected scenario, the region s existing natural gas pipelines and storage facilities are expected to be sufficient to serve average regional needs under normal weather conditions for the near term. But notice the qualifiers: average and normal. As we know, Northwest weather cannot be counted on to be normal every day of every year; one or more cold weather events usually affect the region in winter. Analyses conducted by the NWGA have found that weather-driven spikes in demand could stretch the region s delivery capability. Pipeline capacity. While Rockies gas is an important part of the region s supply, the existing pipeline carrying gas west from the Rockies production area is fully contracted. There is, however, capacity available on pipelines bringing gas south from the WCSB. The Northwest already depends 2 Published and posted at November Northwest Gas Association - (503)

3 on the WCSB for 60 percent or more of the gas it consumes. Regional gas utilities and other large users are investigating the costs and value of balancing their supply portfolios by adding more Rockies gas or pursuing other supply options. Canadian gas will always be part of the region s natural gas portfolio, but expanded access to the Rockies and other sources ensures adequate and diverse supply alternatives. Production is growing in our traditional supply basins, but so is competition for those resources. While huge unconventional gas finds (see sidebar) in both the WCSB (northern BC) and Rockies supply basins show great promise for future production increases, other markets are gaining access to Rockies and Canadian natural gas. The largest example: The 1,679-mile Rockies Express Pipeline (REX) stretching from Colorado to Ohio will send about 1.8 billion cubic feet per day (Bcf/d; enough gas to serve 4.1 million homes) of Rockies gas to expanding markets in the Midwest and Northeast when fully operational in the fall of Other examples: the Alliance Pipeline ships gas from northern BC and Alberta to Chicago, and the Kern River Pipeline moves Rockies gas to Southern California and the desert Southwest. In short, more competition for gas supplies from our existing sources could make gas more expensive for Northwest consumers, making access to alternative sources more valuable. The availability of capacity can affect prices. As the region s energy consumers are well aware, natural gas prices have been on a roller coaster over the past 10 years, with sharp increases followed by reductions, followed by more increases and reductions. That volatility resulted from many different factors including available infrastructure capacity. For example, when Rockies production exceeded take-away capacity in the recent past, the price of spot market Rockies gas briefly dropped as low as $0.25 per Decatherm (Dth; 1 million British thermal units). However, since the REX pipeline came online, relieving the bottleneck, prices have returned to more typical levels (comparable to WCSB prices). By the same measure, when demand exceeds delivery capacity, prices spike as occurred during the energy crisis at the beginning of this decade (as high as $42 per Dth). What does this mean? Adequate delivery capacity serving the Northwest is crucial to help stabilize prices and to ensure access to least-cost supply sources. WHO DECIDES WHAT INFRASTRUCTURE IS BUILT? Ultimately, the market decides when and where infrastructure is built. Industry participants pipeline operators, utilities, industrial gas consumers, investors or a consortium of these are encouraged to expand or build new facilities when market conditions indicate a need. Expansion of existing facilities is a first choice when possible, because it is typically most cost-effective and poses fewer environmental impacts. Generally, after holding an open season to secure contracts supporting new capacity, a project developer files plans with all required government entities to begin the public vetting process. Regulators then review and determine conditions for approval through permitting and other public processes. This process can take three to five years, which is why it s important to pursue infrastructure projects well before additional capacity is required. Emerging natural gas resources North America is in the midst of a dramatic natural gas supply surge, thanks to recent technology advances that allow extraction of natural gas from shale, tight sands and coal bed methane (CBM) reserves. That means we have more gas available within the continent than once projected, now estimated at 100 years of supply at current rates of consumption. According to the Potential Gas Committee (administered by the Colorado School of Mines), the U.S. sits on top of massive reservoirs of natural gas an estimated 1,836 trillion cubic feet (Tcf), of which shale gas accounts for one third. That represents more energy than all the oil in Saudi Arabia. Northeastern BC alone, according to the Province of BC, contains more than 700 Tcf of unconventional gas potential - possibly 500 Tcf of shale gas potential in the Horn River Basin alone. Recoverable reserves from such potential is about 10 to 25 percent. Besides these sources, the region s future natural gas portfolio could include: Frontier gas supplies The Mackenzie River Delta (Canada) and the Alaska North Slope contain some 65 Tcf and 35 Tcf* in reserves, respectively. Pipelines are being pursued to bring this gas to the lower 48 within the next decade. Offshore resources An estimated 420 Tcf* of natural gas sits immediately offshore in the U.S., and another 43 Tcf* off the BC coast. Both the U.S. and Canadian governments are now exploring limited new offshore development where environmentally feasible. Liquefied natural gas (LNG) Proven natural gas reserves around the globe approach 4,000 Tcf.* Technology improvements and growing worldwide demand for clean-burning natural gas have made the full cycle cost of LNG more competitive, spurring development of new global LNG capacity. * Sources of data cited in 2009 Outlook. Northwest Gas Association - (503)

4 Projects can usually be divided into three types: those initiated by gas producers ( producer push projects), end-use consumers ( market pull projects) or a hybrid of the two. Under the producer-push scenario, a gas producer needs additional regional export capacity to transport new or expanded gas production to additional markets. Both the REX and Alliance pipelines are examples of producer-push pipelines. Proposed Regional Pipeline Projects Southern Crossing Pipeline Extension Many pipelines proposed to serve the region (detailed in next section) reflect the market-pull scenario. This means demand-side interests e.g., utilities delivering gas to residential and commercial customers or large industrial consumers like pulp and paper mills or food processors are prompted by growing demand for natural gas to pursue additional capacity. Palomar Cascade Blue Bridge There is, of course, no such thing as a free lunch. Infrastructure developers will not invest in speculative projects; they must be able to recoup their costs. These costs are incorporated into rates charged to subscribing customers, usually in long-term binding capacity contracts. And subscribers, such as local gas utilities or large industrial customers, will not enter into long-term contracts for new capacity unless they anticipate needing it and it makes economic sense. If the subscriber is a utility, those costs must first be approved by the state or provincial utility commission before they can be recovered over the long term through rates paid by customers. For that reason, such sizable investments are not pursued unless market conditions including the price of gas make them cost effective for both developers and customers. NEW CAPACITY PROPOSED TO SERVE REGION Several projects have been proposed to expand delivery capacity in the Northwest, including several new pipelines and LNG import terminals. Pipeline projects Four pipeline projects have been proposed to serve the region. The Ruby pipeline would expand access to Rockies production areas. The other three Blue Bridge, the Southern Crossing Pipeline Extension and Palomar Cascade would increase natural gas availability within the I-5 Corridor. The market dynamics described in the section above will dictate which projects are ultimately built. Here is a brief look at each of the proposals: Blue Bridge Pipeline Williams/Northwest Pipeline is proposing this project, which includes building up to 119 miles of looping pipeline and installing additional Ruby compression. The project will be designed to deliver up to 300 MMcf/d from Plymouth, Wash., to the I-5 Corridor. The project would generally follow Northwest Pipeline s existing pipeline corridor for most of its route. FERC recently held public meetings on the project. Palomar Gas Transmission - A partnership between NW Natural and TransCanada, Palomar Gas Transmission is a proposed 217-mile, 36-inch-diameter pipeline that would extend from TransCanada s Gas Transmission Northwest system near Madras, Ore., to a point on the Columbia River where it would interconnect with the proposed Bradwood Landing LNG Terminal. Palomar would be bi-directional with initial capacity of up to 1 Bcf/d. Palomar is filing for the full 217 miles but the project is configured as two segments of roughly equal length. The Cascade segment would stretch from GTN to a point near Molalla (southeast of Portland) where it would connect with NW Natural s large-diameter system. The Willamette segment would run from Molalla to the Columbia River. The project s partners say the Cascade segment Bi-directional pipelines have the capability to transport gas in either direction, reversing flow depending on customer needs and market demands. would be built irrespective of whether the Bradwood Landing facility comes on line. Federal approval to build is expected in late Northwest Gas Association - (503)

5 Ruby Pipeline El Paso Natural Gas is proposing to build this 675-mile, 42-inch diameter pipeline from Opal, Wyoming, to Malin, Oregon, with an initial design capacity of up to 1,500 MMcf/d. The project application has been filed with the Federal Energy Regulatory Commission (FERC); construction is expected to begin pending financing and final regulatory and environmental clearances. Southern Crossing Pipeline Extension Terasen Gas is exploring options to extend its Southern Crossing Pipeline from southern BC near Kingsgate, Idaho, to Kingsvale, BC, where it would connect with the Spectra Energy system. Initial design capacity is projected to be 200 MMcf/d, expandable to 400 MMcf/d. The project is bi-directional, allowing new production coming from northern BC to move into the eastern part of the region via the GTN system or into the western part of the region via Spectra during peak periods. Proposed LNG Terminals and Associated Pipelines Kitimat LNG Kitimat, B.C. Pacific Trail Pipeline Spectra Energy Western Canadian Operations Terasen Southern Crossing TransCanada s GTN System Williams Northwest Pipeline A note on LNG import terminals Although proposed LNG import terminals and their associated pipelines have received much public attention in recent years, they are only one consideration in the blend of new capacity facilities needed to serve the region. What role they play, and whether one or any are built, will depend on market dynamics (including subscriber support), financing and the success of ongoing permitting processes. But whether terminals are built in the Northwest or elsewhere in North America, it is certain LNG imports will continue to play some role across the continent. According to the Energy Information Administration (EIA), development of new continental supplies will help reduce our reliance on LNG imports over the next 20 years, but North America will always need some imports to meet demand. ( oiaf/aeo/execsummary.html) Oregon LNG Warrenton, OR Jordan Cove LNG Coos Bay, OR Pacific Connector Northern Star Bradwood, OR LNG terminals There are three LNG import terminal projects proposed in the region, including Bradwood Landing on the Columbia River near Clatskanie, Oregon; Oregon LNG in Warrenton, Oregon, and Jordan Cove in Coos Bay, Oregon. In addition, Kitimat LNG is proposing an export terminal in Northwest BC to capitalize on new supply sources there. Each LNG project includes one or more proposed pipelines that will be built if the associated terminal is built. Here is a brief look at each: A 117-mile pipeline would connect Oregon LNG s proposed terminal in Warrenton, Oregon, to the existing NW Natural and Williams Northwest Pipeline systems near Molalla, Oregon. The 231-mile Pacific Connector Gas Pipeline would extend from the proposed Jordan Cove LNG terminal in Coos Bay, Oregon, across southwest Oregon to the California border at Malin to serve the Pacific Northwest and California markets. The 291-mile Pacific Trail Pipeline would connect natural gas from Spectra Energy Transmission s pipeline at Summit Lake, north of Prince George, BC, to the proposed Kitimat LNG export terminal in BC s Bish Cove. Northwest Gas Association - (503)

6 LOOKING AHEAD Tracking the myriad proposals to augment the region s natural gas delivery system can be a daunting task. But one thing is clear: the market is working. Given economic signs that natural gas demand is beginning to tax the region s peak delivery capacity, market participants are reacting by proposing a mix of solutions. Each of these multi-milliondollar investments would not be under consideration if investors did not believe the projects were viable. But what mix of pipes, storage facilities and import terminals is best? That, too, is ultimately up to the market industry participants, consumers, regulators and policy-makers to decide, although it is sometimes not an easy decision. The industry takes justifiable pride in its painstaking approach to protecting the environment during gas facility construction, and for its stellar safety record. Nevertheless, major infrastructure projects like these sometimes generate localized and often intense concerns. Balancing these concerns with the public s region-wide needs and interests is difficult, but paramount. One thing is for certain: taking no action, or waiting too long to take action, is not an option. Natural gas has become a necessity, accounting for 54% of total non-transportation related energy consumed in the region (includes gas used for electrical generation). As discussed, environmental mandates and consumer demand will likely increase the region s reliance on natural gas, challenging delivery systems to keep pace. And given the three to five years new infrastructure projects can take to permit and build, we must prepare for the future now. The goal is to ensure our regional system of natural gas infrastructure is nimble enough to allow greater access not only to our tried-and-true supply resources but also to emerging new sources. Such flexibility allows the market to optimize resources, take advantage of the lowest cost supply at any given time, and ultimately benefits consumers with more stable prices. For more details on the subjects covered in this white paper, including sources of cited data, see the NWGA s annual Outlook report. The most recent version can be found on the NWGA s website at nwga.org. TERMINOLOGY Throughout this white paper we have used terminology specific to the natural gas industry. This includes the most common units of energy used to describe natural gas a measure of volume, and therms a measure of energy (or heat). Here are some basic definitions for the various units of energy discussed to help you make comparisons should the need arise. While the energy content of natural gas varies according to its specific composition, we have generally used the value of 1,030 British thermal units (Btus) per cubic foot of natural gas when making conversions. Btu British thermal unit A measure of energy content (non metric). The energy required to increase the temperature of one pound of water one degree Fahrenheit under standard (defined) conditions. Equivalent to the energy produced by striking a wooden match stick. MMBtu One million Btus Unit by which natural gas is bought and sold. MMcf 1 million cubic feet Equivalent to 1.03 MDth. Bcf 1 billion cubic feet Equivalent to 1.03 MMDth. Tcf 1 trillion cubic feet Dth Decatherm Equivalent to 10 therms, 1 million Btus or0.975 Mcf. This White Paper was published by the Northwest Gas Association (NWGA) to provide the public, policy makers, opinion leaders and the media with accurate and timely information about the region s existing natural gas infrastructure and expansion proposals to keep pace with growing demand. NWGA members include six natural gas utilities serving communities in Oregon, Washington, Idaho and British Columbia, and three interstate pipelines that move natural gas from supply basins into and through the region. NWGA members deliver or distribute all the natural gas consumed in the Pacific Northwest. For more information, contact us or visit our Web Northwest Gas Association - (503)