With the continued growth of natural gas as a key ingredient in the nation’s fuel mix comes increased focus on operational excellence as federal and state regulators and lawmakers closely monitor utilities to ensure they are not just properly maintaining their vast networks, but also working pro-actively to ensure the public’s well-being.
In this special report, P&GJ interviews Marvin L. Sweetin, senior vice president, Utility Operations, of Atmos Energy Corporation, among the nation’s largest natural gas-only distributors which has one of the most aggressive pipe-replacement programs, and Kathryn Clay, Executive Director, American Gas Foundation, an affiliate of the American Gas Association. AGF provides an independent source of information on energy and environmental issues that affect public policy, in particular natural gas.
From their assessments of short- and long-term goals, a mood of determined optimism quickly becomes apparent.
Marvin L. Sweetin, senior vice president, utility operations, Atmos Energy Corporation
P&GJ: What do you consider the greatest challenge facing the LDC in the near-term?
Sweetin: We must balance the needs to continually update and improve our system for safety and reliability against the forces in today’s economy to control costs and keep customers’ rates low. In the nine states we serve, regulators have agreed that safety and reliability are pre-eminent, and they have generally allowed us to recover our investments on a timely basis with a fair return for our investors. Related to this balancing act are the need to find a sufficient number of qualified crews to install or maintain our lines and the need to manage their work.
P&GJ: Your company has announced a major replacement program involving cast iron, steel mains and vintage pipelines. When did this start and what is the ultimate goal?
Sweetin: We have been modernizing the pipelines in our system for many years. Our largest program, both in number of miles and cost, is our steel-service line replacement program in Texas. In Georgia, we have been replacing cast-iron and bare-steel lines for nearly a decade. In Mississippi, we just completed a 10-year cast-iron replacement program. In Tennessee, we are nearing the end of a decade-long bare-steel replacement program; in Kentucky, we are in the third year of a 15-year program. Going back even further to the 1980s, we completed similar replacement programs in Kansas and Missouri.
P&GJ: Where are you in terms of making significant improvements to existing infrastructure?
Sweetin: During our five fiscal years of 2007 to 2011, we invested more than $1.7 billion, or approximately 68% of our total capital expenditures, in safety and reliability improvements.
When our 2012 fiscal year ended Sept. 30, we completed the first year of a new five-year capital investment program to fortify and advance the safety of our system. For fiscal 2012, we invested nearly $723 million in projects for our regulated operations. By the start of our 2017 fiscal year, we expect to have invested between $3.7 billion and $3.8 billion under this current program.
For our regulated Texas intrastate transmission system, Atmos Pipeline–Texas, we continue to invest to increase capacity, to secure new long-term gas supplies and to enhance the safety and reliability of our service. In fiscal 2012, we spent $55 million of capital on new pipeline projects. We anticipate investing an additional $125-135 million in similar projects in coming years.
P&GJ: What is the largest project you will undertake in the replacement program?
Sweetin: One of Atmos Energy’s largest projects is replacing steel service lines in our Texas service areas with the latest polyethylene pipe technology. We recently passed the 100,000 mark in this program. In addition to many of our own employees, 350 contract crews from 15 contractors have been dedicated to this work for the past two years.
We identify these service line replacements using a risk-assessment model, which shows that most of the pipe repairs and replacements that the Mid-Tex Division makes are related to steel-service lines. So, this steel-service line replacement program is not only a highly efficient use of our capital, but also a significant enhancement to the safety and reliability of our distribution system.
P&GJ: Some state pipeline safety authorities have mandated that operators replace all or part of their cast-iron systems. Are you active in one of these areas?
Sweetin: We have proactively replaced the cast-iron pipe in all of our states of operation, no matter whether the state regulators mandated it. We have been well ahead of any requirements.
P&GJ: Other than a pipe-replacement program, can you elaborate on any plans your company might have regarding upgrades to other facilities (SCADA, peak-shaving, meters, etc.)?
Sweetin: Three of our other major capital improvement projects tie in closely with our pipeline projects.
• We began building an advanced metering infrastructure in 2007 to install wireless transmitters on our conventional gas meters. Wireless meter-reading improves billing accuracy and lowers O&M costs. It also can alert us to anomalous gas flow rates, helping us detect a potential leak. So far, we have installed 280,000 transmitters in Louisiana, Texas and Colorado. We intend to add about 90,000 more this fiscal year in 37 communities of Texas, Colorado, Mississippi and Tennessee.
• We are now testing a new enterprise-wide customer service system, or CSS, to handle all data about customer contacts, dispatch, service, consumption and billing. We began developing this CSS in 2010 and expect it to go into service in 2013. It replaces a number of older information technology systems. As a result, this advanced technology will help us offer better customer service and give us better information for assessment and planning.
• Last year, we replaced the SCADA system on our intrastate Atmos Pipeline–Texas transmission and storage assets. Like our new CSS, it marks a major technology upgrade, which adds to the margin of safety and reliability on our high-pressure assets.
P&GJ: LDCs had until Aug. 2, 2011 to write and implement a Distribution Integrity Management Program (DIMP). What impact has this had?
Sweetin: State audits of our DIMP have found a high degree of system integrity, regulatory compliance and attention to critical details. Our engineering, operations and compliance teams have committed themselves to managing an excellent program to meet the requirements in every state we serve.
P&GJ: Under federal Pipeline Safety Regulation 49 CFR 192.383, LDCs are required to install an excess flow valve on all new and renewed service lines that serve a single-family resident. Has this proven to be costly for the LDC?
Sweetin: Like replacing our cast-iron pipe, we decided early on to install excess flow valves system-wide well before the federal mandate. EFVs are normal operating expenditures required by legislation.
P&GJ: What proposed regulations or legislation couldt have a negative impact on the LDC?
Sweetin: AGA found that a significant percentage of the 45,000 miles of transmission pipe operated by LDCs is lacking verifiable pressure test records. I wouldn’t characterize the federal mandate to validate MAOP records of transmission lines as necessarily having a negative effect on LDCs. However, I would say it is significantly increasing operational, compliance and recordkeeping costs. It poses many challenges: select the right staff and train them, locate and identify historical records, review source documents, install document and quality controls, assure the accuracy of GIS records, grade the documents and check that MAOP is calculated correctly. What’s more, the LDCs have unique challenges to pressure test their in-service transmission lines that lack verifiable data. It’s a big job and a costly one. LDCs will need time to make these changes.
P&GJ: What was the response of your company to the April 2011 Pipeline Safety Action Plan announced by Secretary of Transportation Ray LaHood?
Sweetin: DOT Secretary LaHood’s plan is foremost a call to prevent tragic pipeline accidents. But, it’s also part of the Obama administration’s push to repair and modernize the country’s transportation infrastructure. LaHood said, if the industry would do a critical self-evaluation, he would pledge to remove bureaucratic red tape. The U.S. natural gas network is in much better condition than the electric grid. Yet, investing in new gas infrastructure makes a lot of sense to achieve safety, reliability, efficiency, environmental goals and new jobs. We can differ on some details of the DOT plan, but we cannot fault its overall wisdom.
Kathryn Clay, Executive Director, American Gas Foundation
P&GJ: What spending trends have you seen by LDCs to replace infrastructure serving existing gas customers?
Clay: Maintaining the safety and reliability of the nation’s natural gas pipeline system remains the number one priority for the American Gas Association (AGA) and its members. Natural gas utilities annually spend billions of dollars in normal maintenance, safety, and operating expenses, and they recover these costs from customers through the rates they charge. Utilities also invest billions annually in system repairs, renovations, and new construction, but these new investments often are deferred until the next utility rate case. In 2011, natural gas utilities invested nearly $6 billion in their distribution systems.
In 2007, when AGA completed its first national assessment of infrastructure cost recovery methods, 15 natural gas utilities in 11 states serving 8 million residential natural gas customers were using innovative rate structures that allowed them to modify tariffs and recover the costs of investments in utility replacement incurred between rate cases. Since that time, the use of these advanced regulatory mechanisms has tripled.
In July of this year, the American Gas Foundation released its report, Gas Distribution Infrastructure: Pipeline Replacement and Upgrades Cost Recovery Issues and Approaches.
This report provides a context for policy discussions surrounding cost recovery for these efforts and discusses how innovative cost-recovery mechanisms can serve the public interest in the short and the long run, including both operational and economic benefits. (The complete report is available for download at www.gasfoundation.org.)
In recent years, states have been encouraging natural gas companies to increase the investment levels necessary to maximize the safety and reliability of their systems. Since 2003, 10 states have implemented new statutes or generic utility regulations concerning cost recovery of replacement and repair of natural gas infrastructures, and more than half of state regulatory commissions now allow utilities to use expense trackers or accounting deferrals to recover costs of infrastructure investments in a timely manner.
These rate mechanisms reduce the costs associated with filing rate cases while reducing the regulatory lag associated with recovery of infrastructure investments. In addition, the mechanisms recognize that replacement investments will not lead to sales of additional volumes of natural gas that might otherwise have been expected to help recover the investments’ cost.
Several rate-design options are available for recovering expenses associated with replacing pipelines and other infrastructure that utilities incur after rates have been set. Trackers, surcharges, and rate-stabilization mechanisms recover costs in the time period in which they are incurred while deferral accounts delay the recovery of investments, and usually, carrying costs, until a future period.
These mechanisms provide greater transparency and accountability than do traditional ratemaking methods. Infrastructure cost-recovery mechanisms typically require that program funds be used exclusively for repair, replacement and improvements to pipelines and associated infrastructure, and that regulatory staff periodically audit program spending. Pre-program budget approval and after-the-fact prudency reviews are customary features of the regulatory approval process for these mechanisms.
P&G: Do you foresee legislation that will mandate modernization of existing gas distribution infrastructure?
Clay: In April 2011, Secretary of Transportation Ray LaHood released a call to action regarding repair and replacement activities for existing natural gas distribution infrastructure. Congress, the U.S. Department of Transportation, and state commissions are devoting greater attention to the need for additional investment in the infrastructure required to maintain and improve the safety and reliability of the distribution network.
To date, 27 states now allow utilities to recover the costs incurred between rate cases associated with replacing aging infrastructure, and 10 states have implemented legislation or state-wide regulatory programs to comprehensively address infrastructure issues. These programs now cover more than 30 million of the nation’s 65 million residential natural gas customers.
P&GJ: If not mandated, do you see any indication that LDCs are accelerating pipe-replacement programs?
Clay: As noted previously, 27 states now allow utilities to recover the costs incurred between rate cases associated with replacing aging infrastructure, and ten states have implemented legislation or state-wide regulatory programs to comprehensively address infrastructure issues. A number of examples of the approaches taken by different states are given below. These examples provide a sense of the variety of approaches that are being adopted across the nation.
Florida. Florida has adopted an innovative rate mechanism that will allow utilities to replace all high-risk cast-iron or bare-steel gas pipelines within 10 years rather than the 50-70 years anticipated under standard replacement programs. Florida utilities requested approval of accelerated replacement programs to respond to public concerns regarding aging infrastructure reliability and safety. This important investment will not only improve the safety and reliability of this critical infrastructure, but also provide an economic benefit to the state.
Virginia. In 2010, Virginia amended its state code to allow natural gas LDCs to recover infrastructure costs for programs that enhance LDC safety and reliability; do not increase revenues through connecting new customers; reduce (or potentially reduce) greenhouse gas emissions; are made after Jan. 1, 2010; and are currently not in the LDC’s rate base. These programs are referred to as SAVE programs.
LDCs must file a schedule of the proposed investments including a justification of prudency—with the Virginia State Corporation Commission, which must rule within 180 days. At the end of the rider’s annual period, the utility must reconcile actual with estimated costs. An updated cost of capital may be used in the calculation, but applied only to the incremental investment.
Georgia. In 1998, Atlanta Gas Light began a 15-year Pipeline Replacement Program (PRP) to replace more than 2,300 miles of bare steel and cast iron natural gas pipeline in Georgia. In the early years, the Georgia Public Service Commission annually reviewed the company’s infrastructure replacement expenses from the previous year and then approved a new surcharge amount. Halfway through the program, the commission agreed to a fixed dollar amount of expense to be recovered in rates over the remaining seven years of the program.
In 2009, Atlanta Gas Light significantly expanded the replacement program to include investments for infrastructure to serve new customers and expand service. The Strategic Infrastructure Development and Enhancement program merged with the company’s existing PRP and allows the company to invest $400 million over the next 10 years in infrastructure improvements.
Those improvements include upgrading the backbone of the utility’s distribution system and liquefied natural gas facilities to improve system reliability and create a platform to meet forecasted growth. The program was further expanded in 2010 and allows Atlanta Gas Light to invest up to $45 million to extend its pipeline facilities to serve customers without pipeline access. The new program will also allow Atlanta Gas Light to install pipelines to create new economic development corridors in order to help spur growth.
Indiana. In its most recent rate case in 2008, Vectren North (Indiana Gas) received approval to implement a tracking mechanism that allows the utility to defer expenses associated with investments in infrastructure replacement projects. Vectren defers the recovery of depreciation expense and property taxes and continues to utilize the allowance for funds used during construction (AFUDC) for four years from the date that each replacement was put in service.
The company is allowed to defer up to $20 million per year. All projects receiving the accounting treatment at the time the company files its next base rate case continue to receive that treatment until a base rate order is issued; projects that are included in rate base and initiated after a rate case is filed are also eligible for the deferral accounting and later recovery.
Kansas. In April 2006, the Kansas legislature passed the Gas Safety and Reliability Policy Act (K.S.A. 66-2201 through 66-2204) that approved the implementation of a gas system reliability surcharge for Kansas natural gas utilities. Utilities in the state may surcharge between 0.5% and 10% of revenues to recover new infrastructure replacement costs not already in rates. Rates are adjusted annually. The surcharge may continue for no more than five years after the last rate case and then a new case must be held if the surcharge is to be continued.
Massachusetts. Columbia Gas of Massachusetts (formerly Bay State Gas) received approval of its Targeted Infrastructure Reinvestment Factor (TIRF) as part of its last base rate case in October 2009. The TIRF allows for the recovery of the revenue requirement associated with bare steel capital additions for the previous calendar year, including: mains, services, service tie-ins, meters, meter installations, regulators, and industrial measuring and regulating equipment.
The revenue requirement reflects an offset of estimated O&M savings associated with the infrastructure replacement. The initial filing is made on May 1 each year with new rates going into effect each November. The TIRF tracking mechanism costs are recovered as a component of Columbia’s Local Distribution Adjustment Clause mechanism. There is a revenue recovery cap of 1% of total revenue (including gas costs). The replacement time period is expected to be 10-15 years.
Oregon. The NW Natural program is a tracker that recovers the cost of the acceleration of bare-steel pipe replacement, transmission pipeline integrity costs, and distribution pipeline integrity costs. The tracker adjusts rates to recover these costs for the most recent 12-month period Nov. 1 through Oct. 31, and the adjustments are made at the same time as the company’s annual purchased gas adjustment filing.
The company is required to allocate 70% of the cumulative investment of the bare- steel pipe replacement portion of the program costs to residential and commercial firm sales and transportation customers. The total program is capped at $12 million per year, with $8.7 million of that considered incremental and recoverable through the tracking mechanism.
The system integrity program is in effect through Oct. 31, 2014, and the bare-steel replacement tracker will remain in effect through Dec. 31, 2021.
Texas. Traditionally, rate requests in Texas have been more complex than other jurisdictions due to the authority sharing between the Railroad Commission of Texas and various municipalities. In 2004, RRC implemented Rule 7.7101 in response to legislation passed by the Texas Legislature allowing LDCs to file for “Interim Rate Adjustments.”
IRAs allow LDCs to recover costs associated with new infrastructure since the previous rate request without an evidentiary hearing. The LDC may provide streamlined filings; the RRC must act within 60 days. However, the utility must have filed a traditional rate request within the past two years.
The IRA is based on the findings of the LDC’s last comprehensive rate request which are applied to incremental investment. In addition, a new request must be filed on the fifth anniversary of the initial IRA request. Information from the previous request includes factors used to calculate ROI, depreciation expense, incremental federal income tax, and information on the allocation of the revenue requirements. The LDC must file an annual earnings monitor report after making an IRA request. If it demonstrates earnings in excess of 75 basis points over the authorized return, it must demonstrate that this is not unreasonable or in violation of the law.
Unlike many other mechanisms, the legislation requires that an IRA application allocate revenue in a manner consistent with the cost-of-service principles in the original request. The statute also requires that the revenue increase be recovered either in the fixed charge or the initial block of the tariff design, thus providing revenue stability.
P&GJ: What is needed so the LDC can recover costs associated with pipe-replacement programs on a timely basis?
Clay: Timely cost recovery of prudently incurred safety and reliability investments is of utmost importance to the financial stability of natural gas utilities. Because traditional ratemaking allows recovery of infrastructure investments only following approval in a rate case, there is often a multiyear delay before the recovery of such investments begins.
Investments that are recovered long after they are incurred cause the utility to bear carrying costs without the opportunity to recover these prudent expenditures. Credit agencies criticize companies with lag in the recovery of their costs and assign a lower credit rating to such utilities that ultimately translates into higher rates for customers. The only alternative is to file a rate case each year, which is a costly activity that also leads to higher rates for customers.
Under traditional cost of service-based ratemaking, the costs of natural gas utility infrastructure investments are recovered after the investment is in the ground and the regulator has approved the costs in a rate case. This system produces a significant lag between when the dollars are spent for infrastructure replacement and when the company begins to recover these expenditures in rates. In addition, while investments made to serve new customers or to deliver additional volumes of gas generate additional revenue, expenditures made to refurbish or to replace aging infrastructure do not produce incremental revenue.
This reality has led to the introduction of several new approaches to designing rates. The growing use of innovative rate structures is allowing utilities to recover the costs of infrastructure replacement without having to pursue rate cases.
P&GJ: What are some methods that should be considered to allow the LDC to recover costs associated with necessary safety, repair and replacement and operations and maintenance investments?
Clay: Several rate-design options are available for recovering expenses associated with replacing pipelines and other infrastructure that utilities incur after rates have been set.
Tracker – A rate tracker is an example of an adjustment clause, a regulatory mechanism that allows a utility’s rates to fluctuate in response to changes in operating costs or conditions, as they occur. Adjustment clauses have been in use since World War I when the electric industry introduced them due to significant increases in the price of coal.
Trackers may be automatic, actuated without the need for a formal rate hearing, or they may require additional regulatory review before they go into effect. Trackers allow the utility to adjust its tariff to facilitate the timely recovery of the capital costs, depreciation expense, and property taxes associated with the company’s infrastructure investment program.
Surcharge to Rates – The most frequently used cost-recovery method for infrastructure replacement cost programs is the surcharge to rates. A rate surcharge is a temporary adjustment to the customer bill that raises rates for a limited time by a fixed amount. Unlike the tracker, which allows the utility to recover ALL costs associated with infrastructure replacement, a surcharge limits the total amount of program cost recovery.
Deferral Account – Another option is the deferred accounting alternative. Using this approach, the utility treats infrastructure investment costs that are not included in the utility’s existing rates in a segregated manner, thereby establishing a special deferred account. Generally, state authorities require a determination that the costs have been incurred prudently and have been accounted for properly. Often, these costs are deferred until the next rate case, at which time the costs are then amortized, recovered in rates, and the account balances are reduced or eliminated.
In many cases, the assets in the deferral accounts accrue interest, and the interest is also amortized and recovered later in rates. The regulator may place limits on the amount or type of infrastructure costs that may be accrued, and on the time period over which the amortization may occur, and may require a showing of prudence in the incurring of specific costs.
Rate Stabilization – Rate stabilization is one of several rate designs that decouple the link between the volumes of gas consumed by a utility’s customers and the revenues and cost recovery of the utility. A rate stabilization tariff operates much like a tracking mechanism since changes in ALL costs, including infrastructure investments, are tracked and flowed through to customers. With rate stabilization, rates are adjusted annually for new infrastructure replacement costs as well as for costs for new construction. Utilities in seven states, serving 6 million customers, use this option to recover the incremental costs of new and replacement infrastructure investment.
P&GJ: What about regulatory or legislative changes that could be beneficial to the LDC?
Clay: As gas becomes an increasingly important component of the energy mix in the United States, safety and reliability continue to be a key focus. That has driven an ongoing effort toward proactively addressing infrastructure that needs replacement—and accelerating those improvements.
However, paying for these programs can present a significant challenge. Replacement work does not bring new customers to offset costs, and the traditional rate-request process—which may take years—often cannot keep up with accelerated improvement schedules. That process tends to be costly, administratively burdensome, and subjects utilities to regulatory lag for cost recovery. Gas companies facing the continuous replacement of pipeline could face a series of rate requests, potentially on an annual basis, for many years.
Innovative cost-recovery mechanisms can help LDCs overcome these challenges. The AGA and its member companies welcome the opportunity to work with public utility commissions and state legislatures to craft innovative approaches that facilitate accelerated infrastructure upgrades, to the benefit of all consumers.