Without a doubt, sufficient midstream natural gas infrastructure is crucial for efficient delivery and well?functioning markets. Insufficient infrastructure causes price volatility, poor netbacks for producers and interrupted delivery when unexpected incidents occur.

This executive summary of the new report—North American Natural Gas Midstream Infrastructure Through 2035: A Secure Energy Future—conducted by ICF International on behalf of the Interstate Natural Gas Association of America Foundation Inc. and released on June 28, updates the previous 2009 infrastructure report to detail the dynamic changes in the natural gas industry in recent years.

The INGAA Foundation was formed in 1990 by the Interstate Natural Gas Association of America (INGAA) to advance the use of natural gas for the benefit of the environment and the consuming public. The Foundation supports the efficient construction and safe, reliable operation of the North American natural gas pipeline system and promotes natural gas infrastructure development worldwide.

“This report shows a vibrant natural gas market in the future, and it also demonstrates the need for additional midstream infrastructure to support it,” says INGAA Foundation president Don Santa. “The good news is that the natural gas industry has a proven track record of constructing and financing this level of infrastructure.”

According to the study, interstate pipeline expenditures alone met or exceeded $8 billion per year in three of the years between 2006 and 2010, according to Federal Energy Regulatory Commission data. “This is a strong indication that the industry can and will be able to meet the nation’s gas infrastructure needs,” Santa says.

New infrastructure will be required to move natural gas from regions where production is expected to grow and to areas where demand is expected to increase. According to INGAA, not all areas will require new gas pipeline infrastructure, but many areas (even those that have a large amount of existing pipeline capacity) may require new investment to connect new supplies to markets.

Currently, natural gas producers and marketers have been the principal shippers on these new “supply push” pipelines. Anchor shippers have been willing to commit to long-term, firm contracts for gas-transportation service, thus providing a financial basis for new projects.

Going forward, producers should continue to be motivated to ensure outlets for their gas supplies via pipelines, predicts INGAA. Abundant and geographically diverse shale gas contributes to a competitive natural gas market.

The objective of INGAA’s study is to inform industry, policymakers and stakeholders as they seek to promote job growth and economic development, protect the environment, increase the nation’s energy security and reduce the trade deficit. The following is INGAA’s executive summary of the study.

Gas market outlook

The 2011 ICF reference case applied in this study projects real gas prices that rise from $4 to between $6 and $7 per million Btu (in 2010 dollars) by 2021 and through the end of the study period. This price level is sufficiently high to encourage substantial gas supply development, but not high enough to limit market growth significantly. Under the reference case gas-price scenario, both gas supply and demand are expected to increase significantly over time, creating a positive environment for new natural gas midstream infrastructure.

Economic, demand assumptions for the reference case show U.S. population will grow at an average rate of about 1% per year. U.S. gross domestic product (GDP) is assumed to grow at an average 2.8% per year, while electric load is assumed to grow at an average 1.3% per year.

Oil prices will average about $80 per barrel in real terms. Temperatures are assumed to be consistent with average conditions during the past 30 years.

Also, the study assumes that current U.S. and Canadian gas production originates from over 300 trillion cubic feet of proven gas reserves. The North American natural gas resource base is estimated to total almost 4,000 trillion cubic feet, when adding unproved resources to discovered?but undeveloped gas resource. That amount can supply U.S. and Canadian gas markets for about 150 years at current consumption levels.

The study assumes gas supply development will continue at recently observed activity levels, and that there will be no new significant or special production restrictions. The projection also assumes no significant hurricane disruptions to natural gas supply. The supply outlook is generally a market?balancing view. In other words, the abundant resource base is balanced with demand to determine the volume that is produced or supplied.

Near-term midstream infrastructure development is assumed to include existing project announcements. Unplanned projects are included in the projection when the market signals need of capacity. It is assumed that these projects are built without significant delays in permitting and construction.

In this report, natural gas gathering- and processing-infrastructure projects are included. Often, the upstream sector builds gathering and processing infrastructure as needed to support supply development. This infrastructure typically is financed as part of upstream project development.

Also, projections for oil and natural gas liquids infrastructure have been included because gas is often co?produced with these hydrocarbons. Arctic projects (specifically Alaska and Mackenzie Valley gas pipelines) are not included in the projection, because market prices do not support such development.

Also assumed is the continuing situation where net liquefied natural gas (LNG) exports occur only from Western Canada. There are no net LNG exports from elsewhere in the U.S. and Canada.

Supply and demand

Natural gas consumption in the U.S. and Canada is projected to increase by an average 1.6% per year through 2035. Total natural gas use across all sectors is projected to rise to about 110 billion cubic feet per day (Bcfd) by 2035. Incremental demand growth between 2010 and 2035 is 35 Bcfd, of which 26 Bcfd, or 75%, occurs in the power sector.

The regions with the largest demand increases are the Southeast, followed closely by the Northeast and the Southwest. These areas all exhibit significant power generation demand growth. Canada also sees large demand growth, not only related to power generation but also from natural gas required for oil sands production and development.

U.S. and Canadian natural gas supplies are projected to grow by 38 Bcfd, from about 75 Bcfd in 2010, to about 113 Bcfd in 2035, adequate to meet expanded demand projections in 2035 of 109 Bcfd. Unconventional natural gas supplies account for all of the incremental supply as production from conventional areas declines. Unconventional supplies (shale, coal bed methane and tight gas plays) will account for approximately two?thirds of the total gas supply mix in 2035.

Net liquefied natural gas (LNG) imports will make up approximately 2.5% (2.8 Bcfd) of U.S. and Canadian gas supply in 2035, compared with 1.7% (1.3 Bcfd) in 2010. U.S. and Canadian shale plays are among the world’s fastest growing production areas, with total production expected to increase from about 13 Bcfd in 2010 to 52 Bcfd by 2035.

The Barnett shale has been under development for more than a decade, while development of Fayetteville, Woodford, Marcellus, Haynesville, Eagle Ford and other shale resources began more recently, and promise to contribute to the nation’s gas supply. The strength of the shale plays was evident during the recession, when development continued despite relatively low natural gas prices and poor market conditions.

The shale plays encompass several areas with very large hydrocarbon production potential, including the gas?rich Marcellus and Haynesville fields. Other shale plays, like Bakken and Niobrara, are more liquids (NGL and oil) prone.

New infrastructure

New infrastructure will be required to move natural gas from the regions where production is expected to grow and to areas where demand is expected to increase. Not all areas will require new pipeline infrastructure, but many areas (even those that have a large amount of existing pipeline capacity) may require significant investment to connect new supplies to markets.

In analogous cases to date, natural gas producers and marketers have been the principal shippers on the new “supply push” pipelines. These anchor shippers have been willing to commit to the long?term, firm contracts for natural gas transportation service that provide the financial basis for moving forward with these projects.

Going forward, producers should continue to be motivated to ensure outlets for their gas supplies via pipelines. Abundant and geographically diverse shale gas contributes to a competitive market that benefits consumers.

Underutilized LNG import terminals also contribute less directly to competition on the supply side. The gas market model used to study the reference case shows that flows through the existing interregional natural gas pipeline system will change as a result of the shift in supply. In some cases, flows will decrease. Nonetheless, new supplies entering the interstate pipeline system will require added pipeline capacity to handle the projected increase in natural gas transportation.

The study’s reference case projects that over 43 Bcfd of incremental mainline capacity will be needed from 2010 to 2035. In addition to the new mainline transmission capacity, pipeline laterals will be required to connect new power plants, new gas-storage fields and new gas-processing facilities to the network of natural gas transmission pipelines.

New gathering system capacity also will be required to connect new producing wells to processing facilities and pipelines. The cost of new natural gas transmission infrastructure (including gas storage and lateral connections) needed over the next 25 years is projected to average approximately $5.7 billion per year, or more than $141 7 billion (in real 2010 dollars) total.

Gathering and processing adds an additional $2.6 billion per year, on average, or about $64 billion total. The gas transmission mainline category is projected to account for approximately 50% of the total capital required for midstream natural gas infrastructure in this study.

The study notes that natural gas pipeline companies do not build interstate pipeline projects unless shippers are willing to sign long?term contracts for natural gas transportation. Such long?term contracts serve two important purposes: First, the shippers’ contractual commitments provide a basis for the pipeline company to raise the capital needed to build its project. Second, the Federal Energy Regulatory Commission (FERC) is legally required to rule as to the need for a pipeline before it can issue a certificate authorizing the construction and operation of a proposed project.

Also, shipper contracts for natural gas transportation service demonstrate the need for the pipeline. There is an important relationship between the adequacy of natural gas transportation and storage infrastructure and the competitiveness of natural gas commodity markets.

In its 2009 State of the Markets Report, FERC observed that, due to investment in natural gas pipeline capacity, the U.S. was “closer than ever before to being a single natural gas market with congestion limited to a few markets for a few periods during the year.”[

This was borne out in recent years as natural gas has become increasingly abundant and affordable, notwithstanding the significant capital investments made in new pipeline infrastructure. New pipeline capacity links consumers with increased supplies of natural gas and results in greater gas?on?gas competition to the benefit of consumers.

Given that new, increased supplies of natural gas provide much of the impetus for the new pipeline construction that is forecast during the next 25 years, it can be expected that consumers similarly will benefit from this investment. Specifically, consumers will be better off if capacity constraints that limit deliveries of natural gas are removed, than if the investment in new pipeline capacity had not been made and such constraints had been permitted to remain in place.

The largest share of gas pipeline investment is required in the supply?rich Southwest region (21%), followed closely by the Central (19%) and Southeast (19%) regions. The Northeast region houses both growing Marcellus shale supply and major demand centers and will require 15% of the infrastructure investment over the next 25 years.

Historically, the industry has proven its ability to finance and construct this level of infrastructure. Industry investments in pipeline infrastructure alone equaled or exceeded $8 billion per year in three of the past four years. This level of expansion is in line with the pipeline construction that occurred during the past decade.

Interstate pipeline companies have applied for and received FERC approval to construct more than 16,000 miles of interstate pipelines, with total combined capacity exceeding 100 Bcfd. The cost of these projects totaled about $46 billion. During this span, about 14,600 miles of expansion pipeline, which added 76.4 Bcfd of capacity, were constructed and placed in service.

Big market movers

The ICF reference case represents the most likely scenario. However, a number of variables could change, resulting in either more or less natural gas market or production growth. Some variables are considered big market movers that would create significant changes in the market, while others are smaller market movers that would have less (but still a significant) impact on incremental growth.

Big market movers include natural gas passenger vehicles, a potentially huge new market for natural gas, and natural gas trucks, a smaller market than the passenger vehicle market, but still significant.

Possible limitations on the use of hydraulic fracturing, via new regulations that limit access or restrict use of hydraulic fracturing could have significant negative impact on U.S. gas production.

Also, increased or reduced GDP growth would have wide ranging impacts on gas markets. The power sector is the source of most of the projected incremental demand growth, so this is a key variable.

Other factors to be considered are that growing U.S. shale gas production may make LNG exports an attractive option for both producers and overseas consumers, coal-fired power generation markets could have wide-spread effects if changes in environmental policies result in increased or reduced capacity, and a change in nuclear-power capacities, such as if units are not retired or retired early and if any new units are built, could have an effect.

New interest in gas?to?liquids could be another potential market for growing natural gas production, or developing Alaska and Mackenzie Delta gas could add significant incremental supplies to the North American market.

Small market movers

The study’s smaller market movers details events such as oil?to?gas conversions, a scenario where high oil prices could encourage more residential and commercial consumers to convert heaters, boilers and other equipment from oil to natural gas.

Also, industrial production changes could have effects. Compared with GDP growth, changes in industrial production growth would have a smaller, but still significant, impact on gas markets.

And population growth, while not necessarily a major driver of market growth, could impact economic activity. Likewise, changes in the number of residential and commercial gas-utility customers would affect demand growth, but could be offset somewhat by end?use efficiency gains. Residential and commercial end?use efficiency, illustrated by per?customer gas use, has been declining, but the rate of decline could be faster or slower in the future.

An increase in the number of coal?fired boilers that convert to natural gas would have an impact on this subset of total industrial gas demand.

To the north, in Alberta, Canada, producing oil from oil-sand developments requires significant quantities of natural gas, so accelerated production growth would increase gas demand.

Conversely, new regulations or otherwise increased shale drilling costs could reduce market growth. Modest Appalachia drilling constraints, such as permit limits, would constrain production growth from Marcellus and Utica shale.

To the West, Rocky Mountain access restrictions would hamper supply development in this key growth region. In the South, Gulf of Mexico offshore access restrictions could have an effect. Although offshore production is not expected to grow, production could decline significantly if deepwater drilling activity does not return to pre?2010 levels or is impaired by new regulations.

Natural gas hydrates production, while a potentially huge supply source, is not currently technically or commercially competitive, and thus has no affect.

Surprisingly, higher or lower oil prices are expected to have relatively little impact on gas market growth.

Natural gas liquids

Natural gas often is produced in connection with other hydrocarbons. Varying degrees of natural gas liquids typically are produced in conjunction with natural gas. And, associated natural gas is produced in conjunction with the production of oil.

Consequently, an important factor in projecting the amount of infrastructure that will be required to produce and deliver natural gas to consumers is the extent to which natural gas is produced in oil? and liquids?rich areas. The timing and location of natural gas resource development also is affected by the relative prices of natural gas, NGLs and oil.

Under current market conditions, NGLs and oil command a significant price premium over natural gas and, consequently, some producers are opting to develop oil? and NGL?rich plays. This affects the type and location of midstream infrastructure anticipated to accompany the production and delivery of natural gas.

Oil, natural gas, and NGL markets push and pull on one another without being directly tied together by any kind of strict ratio or mathematical relationship. Their predicted infrastructure expansion is likely, probably necessary, and will be the responsibility of the producers and consumers of NGLs and oil.

Natural gas liquids production is projected to increase by about 2% annually through 2035. Ethane, propane, butane and pentanes?plus are projected to increase by 2.3%, 2%, 1.7% and1.6% per year, respectively. NGL?heavy plays include the Eagle Ford in South Texas, parts of the Marcellus, and the Utica shale play in West Virginia, Ohio and Pennsylvania, the Bakken oil play of North Dakota, and the Niobrara and Green River shale plays in Wyoming and Colorado.

To support the supply and demand balance of NGL hydrocarbons, an additional 2 million barrels per day of midstream pipeline capacity is needed to transport growing NGL production during the next 25 years. Expansion of existing NGL pipelines could add 13,000 miles of pipeline (500 miles per year) at an average capital cost of $600 million per year through 2035 or $14.5 billion (in 2010 dollars) total. Without pipeline additions, alternative modes of transportation would include rail shipments and trucking.

Oil infrastructure

U.S. and Canadian oil production is projected to increase by 1.7% per year, from 8.3 million barrels in 2010 to 12.7 million barrels in 2035. The largest areas of production growth are Western Canada and the U.S. northeastern Rocky Mountains.

Nearly all of Canada’s oil production growth comes from increases of bitumen and synthetic crude production from oil sands, which will account for more than 85% of Western Canada’s oil production in 2035 (compared with 65% in 2010).

Also, the U.S. northeastern Rocky Mountains contain several areas where oil production is projected to grow significantly. These include the Bakken and Three Forks shale formations in North Dakota and Montana and the Niobrara shale formation in the Denver, Powder River and the Green River basins of Wyoming and Colorado.

To support the balance of oil supply and demand, an additional 5 million barrels per day of midstream pipeline capacity is needed to transport increasing oil production during the next 25 years. Expansion of the existing oil pipeline grid could add 19,000 miles of oil pipeline (an average of 800 miles per year) at a capital cost of $1.3 billion per year during the next 25 years or $31.4 billion (in 2010 dollars) total. A significant amount of this infrastructure will be built in Canada and in the U.S. Central and Midwest region to transport Canadian bitumen synthetic crude to U.S. refineries.

In summary, U.S. and Canadian natural gas markets are expected to grow mostly because of increased gas use in power generation. Natural gas production is likely to increase with shale gas remaining a prolific source of new gas supply. New midstream infrastructure will be needed to gather, process and transport growing natural gas supplies to end?users.

NGL and oil production likely will increase significantly as well. This is important, because the ability to process and deliver NGLs is critical to developing natural gas resources fully and because there will be some production of associated natural gas in connection with renewed domestic oil production.

In the ICF projection, U.S. and Canadian NGL and oil production grow by about 70% and 50%, respectively, during the next 25 years. This growth will create additional need for infrastructure over time.