MEC&F Expert Engineers : 11/27/14

Thursday, November 27, 2014

LOST AND UNACCOUNTED FOR NATURAL GAS AND COST RECOVERY



Lost and unaccounted for natural gas and cost recovery




Lost and unaccounted for gas (LAUG) “is the difference between the gas measured into the distribution system and the gas measured out of the utility system or otherwise accounted for.”  Gases are more difficult to measure than liquids because changes in pressure and temperature cause large changes in volume.  Source: American Gas Association Rate Round-Up, December 2009, available at http://www.aga.org/SiteCollectionDocuments/RatesReg/RateDesign/LUAF%20Cost%20Recovery%20Mechanisms.pdf (accessed on January 8, 2014).
The term LAUG includes actual leaks of methane and meter differences that do not reflect actual leaks.


Lost and unaccounted for gas is not necessarily gas leaked into the air.  Unaccounted for natural gas is defined as “differences between the sum of the components of natural gas supply and the sum of components of natural gas disposition.  These differences may be due to quantities lost or to the effects of data reporting problems.  Reporting problems include differences due to the net result of conversions of flow data metered at varying temperatures and pressure bases and converted to a standard temperature and pressure base; the effect of variations in company accounting and billing practices; differences between billing cycle and calendar-period time frames; and imbalances resulting from the merger of data reporting systems that vary in scope, format, definitions, and type of respondents.”  EIA Tech Dictionary, available at http://energy.techdictionary.org/EIA-Energy-Dictionary-C-2/Unaccounted_for_natural_gas (accessed January 7, 2014).
Pipeline companies have been able to recover costs from their customers for leaks and LAUG since the early days of the American natural gas industry.  The U.S. Supreme Court discussed this issue in a 1934 case that dealt with natural gas rates: “The company made claim to an allowance for ‘unaccounted for gas,’ which is gas lost as a result of leakage, condensation, expansion or contraction. There is no dispute that a certain loss through these causes is unavoidable, no matter how carefully the business is conducted.”  West Ohio Gas Co. v. Pub. Util. Com’n of Ohio, 294 U.S. 63, 67, 55 S.Ct. 316, 319 (1935) citing Consol. Gas Co. v. Newton, 267 F. 231, 244 (S.D.N.Y. 1920) and Brooklyn Union Gas Co. v. Prendergast, 7 F.2d 628, 652, 671 (E.D.N.Y. 1926).


In current natural gas sales contracts, shippers (e.g. local distribution companies and marketers) pay for the cost of natural gas transmission. Pipeline companies publish a tariff for recovering “prudently incurred costs” through cost of service rates for transmission service. Cost of service rates include a charge to the shipper purchasing the gas for LAUG and natural gas used as fuel for the compressors on the pipeline. Typically the charge is for .5% of throughput for LAUG and 3% of throughput for compressor fuel. This means a hypothetical shipper that needs 1Bcf (1 billion cubic feet) of natural gas would pay for 1.035 Bcf of natural gas.
State utility commissions regulate rates and enforce safety standards for natural gas pipelines and distribution lines under their jurisdiction.  States generally allow gas distributors to recover costs of shipping natural gas to their customers, including gas lost between the transmission hub and the gas meter.  Massachusetts, for example, passes the cost of LAUG on to ratepayers using the state’s cost of gas formula in its utility regulations.
Source: Conservation Law Foundation, Into Thin Air at 10-11 (citing 220 C.M.R. 6.00) available at http://www.clf.org/static/natural-gas-leaks/WhitePaper_Final_lowres.pdf (accessed January 7, 2014).


This reduces the incentive for gas distributors to repair gas leaks or replace old gas lines that are especially prone to leaking.  The Massachusetts Department of Public
Utilities recently implemented incentive programs to encourage distributors to replace old cast iron and bare still lines, which, as mentioned above, are more likely to leak.  America Pays for Gas Leaks: Natural Gas Pipeline Leaks Cost Consumers Billions, A Report Prepared for Senator Edward J Markey, p. 2 (August 1, 2013) available at http://www.markey.senate.gov/documents/markey_lost_gas_report.pdf (accessed January 8, 2014.
A confluence of economic and regulatory factors are likely to drive an increasing proportion of America’s power generation, transportation, industrial and space heating fuel use toward natural gas. Facilitating this transition while balancing some of the inherent benefits of natural gas against safety, economic and environmental concerns will be a key policy focus for federal, state and local regulators and the natural gas industry on the whole.


Key questions
Significant changes will be required to meet the transformational challenges posed by the Shale Era.  DOE is seeking public input on key questions relating to gas-related infrastructure including:
·         Who should pay for new pipeline capacity and how should those costs be allocated? How can electricity markets incentivize flexibility and reliability of gas-fired generators, to ensure they have fuel when they are most needed?
·         What have been the key safety trends recently in the natural gas transmission, storage, and distribution segment of the gas industry?  What are chief actions that could be taken to improve safety                for this segment?
·         What could be the impact of distributed natural gas generation on infrastructure demands?
·         Are there conflicts between federal, state, regional and local policies and regulations that serve as a barrier to improving gas-electric coordination?  If so, what’s the best way to resolve them?
·         What natural gas-related interdependencies should be examined form an energy security and resilience perspective?
·         What existing policies are problematic for maintaining system reliability, adaptability and resilience?
·         What emerging technologies offer opportunities or pose challenges to improving the delivery of natural gas?
·         What information could better inform policy decisions about natural delivery infrastructure?
·         What investments, if any, need to be made in natural gas infrastructure to backstop growth in intermittent supplies like wind and solar generation?
·         What new Will distributed energy resources at the distribution level increase or decrease the need for fast-ramping natural gas generators?
·         Are gas pipeline compressors stations vulnerable to power outages, and to what degree would gas TS&D systems be affected by a relatively long-term regional power outage?


FERC is seeking comments on a proposed Policy Statement regarding Cost Recovery Mechanisms for Modernization of Natural Gas Facilities.  The proposed Policy Statement, issued on November 20, 2014 in Docket No. PL15-1, notes that interstate pipelines are likely to incur costs associated with modernizing their facilities pursuant to obligations imposed by the Pipeline and Hazardous Materials Safety Administration (PHMSA) and with complying with greenhouse gas emission requirements imposed by the Environmental Protection Agency (EPA).  FERC is proposing a means to permit pipelines to recover these costs in a manner that will continue to ensure that pipeline rates remain just and reasonable and that natural gas consumers are protected from excessive costs.
FERC’s policy is to preclude pipelines from implementing cost trackers in order to ensure that pipelines do not have guaranteed means of cost recovery and have incentives to operate efficiently.  The proposed Policy Statement is a break from the policy against trackers.  Specifically, FERC proposes to permit pipelines to implement tracker or surcharge mechanisms to recover these costs, subject to five conditions:
·         •Pipelines must establish base rates to which trackers or surcharges would be added.  The Commission suggests that pipelines may meet this obligation by either reaching pre-negotiated rate settlements with their shippers or by filing full NGA Section 4 rate cases when seeking to implement a tracker.
·         •Pipelines must ensure that only costs associated with eligible facilities are recovered through the tracker and may not recover costs associated with general system maintenance under tracking mechanisms and must specifically identify the projects subject to the tracker.  The costs recovered through trackers should be one-time costs associated with complying with regulations such as those that may be imposed by PHMSA or EPA.
·         •Pipelines must propose mechanisms to ensure that costs are not shifted to captive customers.  In a recent Columbia Gas proceeding, the Commission approved a PHMSA-related tracker that provided for a billing determinant floor to protect captive customers against cost shifts that might result if the pipeline loses customers.
·         •Pipelines must provide for periodic review of their proposed trackers.
·         •Pipelines must attempt to obtain broad customer support for their proposed trackers.



FERC also seeks comment regarding whether pipelines should be allowed to use accelerated amortization methods to recover costs associated with modernization programs and whether its reservation charge crediting policy should be modified if a pipeline is unable to provide firm service while modernizing its facilities pursuant to federal requirements.
Initial comments will be due 30 days after the proposed Policy Statement is published in the Federal Register, with reply comments due 20 days thereafter.




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CALCULATION OF GREENHOUSE GASES EMITTED FROM GAS COMPRESSOR STATIONS



CALCULATION OF Greenhouse Gases EMITTED FROM GAS COMPRESSOR STATIONS



Some gases in the atmosphere affect the Earth’s heat balance by absorbing infrared radiation.  These layers of gas in the atmosphere can prevent the escape of heat in much the same way as glass in a greenhouse.  Thus, global warming is often referred to as the “greenhouse effect.”  The gases most responsible for global warming are referred to as greenhouse gases (GHG).  It is becoming more widely accepted that continued increases in GHGs will contribute to global warming, although there is uncertainty concerning the magnitude and timing of the warming trend.  Combustion of fossil fuels during a gas project construction and operation will result in the emission of the following GHGs: carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O).  Emissions of GHGs are typically expressed in terms of CO2 equivalents  (CO2e),  where  the potential of  each gas to  increase heating in the  atmosphere is expressed as a multiple of the heating potential of CO2, or its global warming potential.

GHG emissions, expressed in terms of CO2e, typically must be estimated for both compressor station operation and construction.  The proposed Project is not subject to the newly revised PSD regulations applicable to GHGs.  Known as the “Tailoring Rule”, this regulation sets a higher major source threshold than other pollutants.  Typically, the estimated potential GHG emissions are less than the threshold amount.

Another new regulation which specifically targets GHGs is the Mandatory Reporting Rule, codified under 40 CFR Part 98.  As a natural gas transmission compressor station, the station may potentially be applicable to Subpart C (stationary combustion) and Subpart W (Oil and Natural Gas Systems) of the rule.  Subpart C covers fuel combustion in the compressor turbines (the two Solar Centaur 50 turbines) and the fuel gas heater.  All compressor stations (at least the new ones) include emergency generators.  The emergency generator is not included in the emission calculations, as it is used as an emergency unit.  Subpart W covers venting of the compressor turbines, venting of condensate storage tanks, station blowdown venting, and equipment leaks from piping components.  The rule requires monitoring and reporting if an applicable source emits greater than actual emissions of 25,000 metric tons of GHGs from certain source categories.




Construction Emissions

Construction of the Gas Compressor Station will result in temporary increases in emissions of some pollutants due to the use of construction equipment powered by diesel or gasoline engines.  Construction activities will also result in the temporary generation of fugitive dust due to disturbance of the surface and other dust generating actions.  Indirect emissions during the construction period will be associated with delivery vehicles and construction worker commuting.

The quantity of fugitive dust generated depends on the size of area disturbed and the intensity of construction activity and also on the silt and moisture content of the soil, the wind speed, and the speed, weight, and volume of vehicular traffic.  Fugitive dust emissions will be mitigated, as necessary, by spraying water to dampen the surfaces of dry work areas.  Worst-case fugitive particulate matter emissions for PM10 and PM2.5 were calculated based on EPA AP-42 recommended emission factors for heavy construction activities along with estimates of the extent and duration of active surface disturbance.  The use of the heavy construction emission factor from AP-42 is meant to be general in nature to cover a wide range of construction operations.  This may overestimate potential fugitive dust generated by the proposed construction project.  The estimated emissions are summarized in tables and supporting calculations are provided in the appendices.

Emissions of NOx, CO, PM10, PM2.5, SO2, VOCs and Greenhouse Gases (GHGs) from construction equipment engines used during Project construction have been estimated based on the anticipated types of non-road and on-road equipment and their levels of use.  Emission factors for diesel and gasoline on-road vehicles were obtained using EPA’s MOBILE6.2 model (SO2) and from New York State Department of Transportation  (NYSDOT)  tables  developed  using  MOBILE6.2  (NOX,  CO,  VOC,  PM10,  PM2.5).



Emission factors for diesel and gasoline non-road equipment engines were obtained using EPA’s NONROAD model documentation.  Emission factors using Tier 2 diesel engine standards have conservatively been assumed to apply to construction equipment engines during 2012 and do not reflect the anticipated phasing-in of more stringent emissions and fuel standards.  A Table typically presents these emission estimates by major construction activity for the entire construction period for all construction activities, respectively.  The assumptions, data, and emission factors used to estimate emissions from construction equipment engines and vehicles are provided in Appendices, along with more detailed listings of emissions estimates.