The Federal Communications Commission is setting aside $300 million in 2012 as a down payment for phone companies in rural areas to build wireline broadband connections.
That $300 million is part of a Connect America Fund the FCC is establishing and funding with the $4.5 billion raised annually from the Universal Service fees paid by every telephone customer in the U.S. In the past, that $4.5 billion was distributed to phone companies so they could provide telephone service in rural areas. Some companies provided broadband too, especially in more heavily-populated rural areas. But broadband was very slow in coming to many isolated, rural areas.
Most of the $300 million downloaded by the FCC in 2012 will go to what are termed price cap carriers. These are larger companies such as Verizon, AT&T, Century Link, WindStream and Frontier who provide phone — but not much broadband — to the 18 million Americans that lack access to residential fixed broadband at or above the Commission’s broadband speed benchmark. The FCC predicts 600,000 rural Americans will get broadband in 2012 because of CAF funding.
Beyond 2012, the FCC will be develop a “cost model” whose purpose will be to divert much more of the $4.5 billion away from telephone service to broadband service in what are considered “high cost” areas, meaning isolated rural areas. In each state, incumbent price cap carriers will be asked to undertake a “state-level commitment” to provide affordable broadband to all high-cost locations in its service territory in that state, excluding extremely high cost areas as determined by the model. Carriers accepting the state-level commitment will be obligated to meet rigorous broadband service requirements — with interim build out requirements in three years and final requirements in five years — and will receive CAF funding, in an amount calculated by the model, over a five-year period, with significant financial consequences in the event of non- or under-performance.
EPA To Consider Shale Gas Wastewater Regulation
To no one’s surprise, the Environmental Protection Agency (EPA) announced in October that it will think about regulating shale gas wastewater. The Department of Energy’s shale gas subcommittee — formed at the request of President Obama — provided the impetus to the EPA by noting the “fracking” chemicals contained in the water injected into shale rock formations and the contaminants that “flowback” to the surface both should be looked at more closely in case they are contaminating drinking water sources.
But the EPA isn’t going to be moving fast on potential wastewater “pre-treatment” standards it can impose under the Clean Water Act. The first thing it plans to do is conduct extensive data gathering, including site visits, stakeholder outreach and development of a national survey of the industry. That process is likely to take years. The EPA is already trying to do a survey of hydraulic fracturing and drinking water, requested by Congress in 2010, which the agency has been trying to get off the ground for a year. Any results of that first study won’t be ready until the end of 2012, if then. And that is only a study.
The potential action under the Clean Water Act the EPA announced in late October has a more direct link to potential regulatory action. There are already effluent standards for the oil and gas industry which prohibit release of shale wastewater into oceans, rivers and streams. There are no “pre-treatment” standards pertaining either to the fracking chemicals or the wastewater disgorged from the well, which can total up to 1 million gallons from a single well within the first 30 days after fracturing.
Daniel Whitten, vice president of strategic communications for America’s Natural Gas Alliance (ANGA), says, “Like all oversight of natural gas development, wastewater disposal is actively regulated at the state level. ANGA continues to believe that state regulatory professionals are best qualified to assess the unique geological characteristics of the shale plays in their region and the appropriate water disposal requirements that arise from those conditions. As EPA officials move forward, we encourage them to partner with the states and take into serious consideration state regulators’ existing on-the-ground expertise and ongoing oversight activities.”
Wastewater associated with shale gas extraction can contain high levels of total dissolved solids (TDS), fracturing fluid additives, metals and naturally occurring radioactive materials (NORM). The big concern in terms of wastewater is TDS which is found at levels typically about 100,000 ppm and can be as high as 400,000 ppm. Available data indicates the levels of TDS in shale gas wastewaters can often exceed recommended drinking water concentrations by a factor of 200.
In terms of current wastewater disposal practices, Marcellus shale gas is generally recycled and reused. But re-use of shale gas wastewater is, in part, dependent on the levels of pollutants in the wastewater and the proximity of other fracturing sites that might re-use the wastewater.
Wastewater that is not recycled is trucked to a publicly-owned treatment works (POTW) for treatment and disposal. POTWs are likely effective in treating only some of the pollutants in shale gas wastewater, such as the conventional and organic pollutants. These treatment technologies are not designed to treat high levels of TDS, NORM, or high levels of metals.
In the Barnett Shale area, wastewater is often injected into brine disposal wells.
Senate Committee Examines LNG Exports
Exports of LNG were the only issue on the menu at hearings in the Senate Energy Committee on Nov. 8. The Department of Energy has four applications from four different U.S. companies to export LNG. But groups such as the American Public Gas Association and Industrial Energy Consumers of America oppose approval of those applications to export natural gas to countries with which the U.S. does not have a Free Trade Agreement (FTA). The DOE cannot block LNG exports to countries with which the U.S. does have a FTA.
The four companies with pending export applications are Lake Charles Exports, Freeport LNG, Dominion and Jordan Cove Energy Project. They want to export LNG to both countries with and without FTAs with the U.S. The DOE has leeway to block exports to non-FTA countries.
The DOE approved the first LNG export application last May. That was from Sabine Pass Liquefaction, which is now able to export 2.2 Bcf/d to both FTA and non-FTA countries.
The case for and against LNG exports are clear; but weighing them against each other is not easy. LNG exports create jobs and provide markets for domestic natural gas. But the exports could lead to higher natural gas prices in the U.S. That latter point is why the APGA and IECA are opposing the export applications.
At the hearings in the Energy Committee on Nov. 8, Chris Smith, deputy assistant secretary for oil and gas in the DOE office of fossil energy, said the Energy Information Administration was doing a study looking at the potential increase in natural gas prices in the U.S. which could occur if the four additional export licenses are granted. Smith did not say whether the DOE would wait for the results of those two studies before acting on the four pending export applications.
None of the members of the committee — neither Democrats nor Republicans — seemed to have much of an opinion one way or another about LNG exports, except for Sen. Lisa Murkowski (R-AK), the top Republican on the committee. She backed the continuation of LNG exports from Cook Island in Alaska, most of which goes to Japan.