Yesterday, I excerpted some key facts and figures presented by Acting EIA Administrator Howard Gruenspecht at a Senate Energy and Commerce hearing on the future of natural gas. Today I summarize some of the main points presented in testimony by MIT Professor Ernest Moniz.

Global Gas Resources — Scale and Cost

Global natural gas resources [including resources not economically recoverable at current prices] are estimated to be between 12,400 trillion cubic feet (Tcf) and 20,800 Tcf, with a mean estimate of 16,200 Tcf. For perspective, 2009 global gas consumption amounted to 109 Tcf. These estimates do not include shale gas outside of North America. EIA recently estimated that an additional 5,300 Tcf of shale gas exists in regions lacking large conventional resources.

Much of the global resource base can be developed at relatively low prices. Globally, over 4,000 Tcf can be developed at or below $2.00/MMBtu, with 9,000 Tcf at or below $4.00/MMBtu. For perspective, yesterday (July 19, 2011), U.S. natural gas traded at $4.53/MMBtu on the New York Mercantile Exchange (NYMEX).

Unlike oil, the cost of transporting gas long distances (via pipelines or in tankers as liquefied natural gas [LNG]) is high. An additional charge of $3.00-$5.00/MMBtu is required to cover transport costs.

 Global Gas Production – Recent Trends

Over the past two decades global production of natural gas has grown by almost 42% overall from approximately 74 Tcf in 1990 to 105 Tcf in 2009. This is almost twice the growth rate of global oil production during the same period.

The most rapid growth was in the United States and Russia.

Greater production has expanded gas markets and cross border trade. From 1993 to 2008, global cross-border gas trade almost doubled, growing from 18 Tcf (25% of global supply), to 35 Tcf (32% of global supply). Most cross-boarder gas movements have historically been via pipeline. However, LNG plays an increasing role. In 1993, 17% of cross-boarder gas trade was via LNG. By 2008 the proportion had increased to 23%, and the absolute volume had increased by 5 Tcf, or 166%.

U.S. Natural Gas Supply – A New Paradigm

Two technologies — hydraulic fracturing (“fracking”) and horizontal drilling – have rapidly increased natural gas production from shale formations. The proportion of total U.S. gas production coming from shale resources grew from less than 1% in 2000, to 20% in 2010. By the end of 2011, this is expected to reach 25%. Shale gas now makes up an estimated 36% of all U.S. gas resources.

U.S. Shale Gas Resource – Uncertainty and Relative Economics

MIT’s mean estimate of recoverable shale gas volumes is 630 Tcf, or just over 30% of all U.S. gas resources.

Shale gas is “moderate cost gas,” not “cheap gas.” Of the 900 Tcf of U.S. gas recoverable at or below $8.00/MMbtu, 470 Tcf is shale gas.

Of U.S. gas available in the “moderate” price range of $4.00-$8.00/MMBtu, over 60% is shale.

Shale Gas Development - Environmental Concerns and Impacts

“The risk of groundwater contamination via gas migration or from the drilling fluid [used in fracking] can be effectively dealt with if best practice case setting and cementing protocols are rigorously enforced.” [For more on this issue, see the House Science Committee May 11, 2011 hearing on hydraulic fracturing technology.] 

MIT recommends:

• Regulatory best practices should be applied uniformly to all shale plays.
• Complete public disclosure of all fracture fluid components. [For more on this issue, see here and here.]
• A DOE-EPA study to assess claims that fracking releases more methane — a potent greenhouse gas [GHG] – than conventional gas production. [For more on this issue, see here, here, and here.]

The Role of Natural Gas in a Carbon-Constrained World

MIT modeled the energy market impacts of a global GHG control regime requiring a 50% reduction in industrial country emissions below 2005 levels by 2050, with no offsets; a 50% reduction in large emerging economy emissions by 2070; and no emission reductions from least developed countries. Driven by “ruthless economics,” MIT’s model projects:  

• Significant demand reduction from business as usual.
• Significant increase in natural gas consumption.
• Total displacement of coal generation with natural gas by 2035.
  • Among the reasons: “Carbon capture and sequestration (CCS) is too expensive to make inroads for many decades.”
• By around 2045, natural gas becomes too carbon-intensive to meet the GHG reduction targets, and starts to decline. Nuclear scales up to replace gas in MIT’s pre-Fukushima model run.

Natural Gas Substitution for Coal in the Power Sector

U.S. natural gas generation has a bigger “nameplate capacity” (technical, full-load sustained output) than does U.S. coal generation, but gas supplies only 23% of our generation compared to 44% from coal. ”This demonstrates that there is significant unused natural gas capacity,” Moniz writes. [Comment: It also demonstrates that coal is a better buy!]

Natural gas combined cycle [NGCC] generation units in the USA in 2009 had an average “capacity factor” (the ratio of actual output over a period of time to nameplate capacity) of only 42% but they are capable of capacity factors around 85%. Although relatively inexpensive to build (compared to nuclear and coal power plants), natural gas plants “typically have the highest marginal cost (although that is changing) and tends to get dispatched after other sources of generation. This is because marginal cost is dominated by fuel cost.” In other words, the cheapest power is dispatched first.

MIT estimates that an environmental policy requiring the dispatch of surplus NGCC before coal would:

• Reduce CO2 emissions by 20%
• Cost $16 per ton of CO2 avoided
• Reduce mercury emissions by 33% and nitrogen oxide (NOx) emissions by 32%
• Increase natural gas consumption by 4Tcf

Moniz clearly favors this policy. His testimony does not estimate the impacts on consumer electric rates or natural gas prices.

Natural Gas Substitution for Coal in the Industrial Sector

Industrial consumers account for about 35% of U.S. natural gas demand. About 85% of industrial demand is the manufacturing sector, and 36% of manufacturing demand is for industrial boilers. In other words, about 11% of U.S. natural gas demand is for industrial boilers. Around 68% of large industrial boilers are coal fired.

EPA’s Boiler MACT (maximum available control technology) Rule (proposed and then withdrawn for reconsideration) assumed that manufacturers would retrofit coal boilers with post-combustion emission controls rather than switch to natural gas boilers. However, says Moniz, ‘The price of gas assumed in the EPA analysis was $9.58 per MMBtu in 2008; today’s price is less than half that.” Using EPA’s methodology but plugging in current gas prices, MIT concludes that it costs less to comply with MACT by replacing coal boilers with super high efficiency natural gas boilers than by retrofitting coal boilers.

Gas Substitution for Electricity in the Buildings Sector

U.S. buildings, both residential and commercial, account for about 40% of total national energy demand. The Department of Energy (DOE) has historically set building and appliance efficiency standards based on “site efficiency” – how much useful energy is provided on site versus how much retail energy is consumed. A more accurate measure, Moniz argues, is ”full fuel cycle or ‘source’ efficiency (accounting for all energy used to extract, refine, convert and transport the fuel as well as the efficiency of the end use appliance).”

For example, using a site calculation, a gas furnace consumes 10% more energy than an electric furnace. When source energy is considered, an electric furnace consumes 194% more energy than a gas furnace. Moniz recommends incorporating such considerations in energy efficiency standards, though he cautions that fuel cycle standards are “complicated to establish because of regional climate and regional electricity supply mix.” [Comment: All coercive efficiency standards have serious downsides (see here, here, here, and here). But note the implication of Moniz's analysis: DOE efficiency standards are promoting inefficiency!]

Today, the Senate Energy and Natural Resources Committee held a hearing on “The Future of Natural Gas.” There were no partisan or ideological fireworks. The expert witnesses were Howard Gruenspecht (U.S. Energy Information Administration), Ernest Moniz (MIT), and George Blitz (Dow Chemical).

Moniz argued the environmental risks associated with natural gas were “challenging but manageable.” Blitz sounded a note of caution. Industry uses natural gas both as a feedstock and as a manufacturing fuel. Policy-driven increases in natural gas demand due to, for example, a Clean Energy Standard, EPA’s Utility MACT Rule, or tax incentives for natural gas vehicles could do what high gas prices did in the early 2000s — close factories and offshore jobs.  I may blog on their testimonies later on.

Gruenspecht’s testimony provides a valuable primer on natural gas production, demand, reserves, and trends. This post excerpts some of the key facts and figures he presented.

Production. After a decade of stagnation, U. S. natural gas production increased by almost 17 percent between 2006 and 2010, reaching 21.6 trillion cubic feet (Tcf) in 2010, the highest level since 1973. Production has continued to increase despite a significant and sustained decline in natural gas prices since mid-2008.

The growth in U.S. supplies over the past few years is largely the result of increases in production from shale gas formations. Shale gas production grew from less than 3 billion cubic feet per day (bcf/d), representing 5 percent of overall production in 2006, to 13 bcf/d, accounting for 23 percent of overall production in 2010.

Imports. Increased domestic production has greatly diminished the Nation’s need for natural gas imports, while lower prices have reduced foreign producers’ incentive to supply the United States. In 2010, net imports to the United States dropped to 2.6 Tcf, representing 10.8 percent of U.S. consumption, marking the lowest volume of net imports since 1994 and the lowest percentage since 1992. As recently as 2007, net imports were the highest on record, equaling roughly 16 percent of consumption.

Demand. Natural gas provides about 25 percent of the primary energy used in the United States, heating about half of U.S. homes, generating almost one-fourth of U.S. electricity, and providing an important fuel and feedstock for industry. About 31 percent of the natural gas consumed in 2010 was used for electric power generation, 33 percent for industrial purposes, and 34 percent in residential and commercial buildings. Only a small portion is used in the transportation sector, predominately at pipeline compressor stations, although some is used for vehicles.

Reserves and Resources. U.S. total natural gas proved reserves [resources that can be extracted economically] grew 11 percent in 2009 and are now at the highest level since 1971. Shale gas proved reserves grew 76 percent after having grown by 48 percent in 2008, reflecting continued strong drilling activity even as natural gas prices declined from their mid-2008 level.

Estimates of the mean technically recoverable resource of natural gas — that is, resources that are technically producible using currently available technologies and industry practices — have also been increasing. EIA’s Annual Energy Outlook 2011 uses a total resource estimate for U.S. natural gas (onshore and offshore, including Alaska) of 2,543 Tcf, including 862 Tcf of shale gas, (35 Tcf of proved reserves plus 827 Tcf of technically recoverable unproved resources.)

Production Growth to 2035. In EIA’s Reference case projection, which assumes no changes in public policy, total natural gas production grows by 26 percent, from 21.0 to 26.3 Tcf, between 2009 and 2035, due primarily to significant increases in shale gas production, which comprises about 47 percent of U.S. dry gas production by 2035. Production increases faster than demand resulting in net imports declining to below five percent of consumption by 2023.

Price Projections to 2035. In EIA’s Reference case projections, natural gas production costs and prices are expected to rise over time as production shifts away from the most attractive “sweet spots” to less productive areas. Average annual wholesale natural gas prices remain under $5 per million Btu (all prices are in real 2009 dollars) through about 2020, increasing to higher levels thereafter.

Oil prices, which were typically 1 to 1.5 times higher than natural gas prices on an energy equivalent basis during the 1995 to 2005 period, are now over 3 times higher than natural gas prices. In EIA’s AEO 2011 Reference case projection, the ratio of oil-to-natural gas prices remains above 3 on an annual average basis, as the balance of gas supply and demand within North America limits natural gas price increases at a time when the world supply-demand balance for oil is expected to push oil prices up at a faster rate.

Demand outlook to 2035. Demand for natural gas in the Reference case grows by over 16 percent between 2009 and 2035. Consumption growth is driven by the industrial and electric generation sectors. Natural gas use in the industrial sector grows by 25 percent from 2009 to 2035, reflecting the recovery in industrial output and relatively low natural gas prices, which spurs a large increase in natural gas consumption for combined heat and power (CHP) generation more than offsetting the decline in natural gas use for feedstock.

Electric generation also shows strong growth in natural gas use, where 65 percent of capacity additions between 2010 and 2035 are expected to be natural gas fired. In addition to capital cost considerations, uncertainty about future limits on greenhouse gas emissions and other possible environmental regulations reduce the competitiveness of coal-fired plants.