MEC&F Expert Engineers : LOST AND UNACCOUNTED FOR NATURAL GAS AND COST RECOVERY

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 Issues Proposed Policy Statement Regarding Cost Recovery For Pipeline Modernization

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.