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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