# U.S. DOT/PHMSA - Regulatory Impact Analysis **Citation:** 090000648242be17 **Type / status:** rulemaking / current **Agency:** Pipeline and Hazardous Materials Safety Administration **Effective:** Not stated **Published:** Not stated Pipeline and Hazardous Materials Safety Administration U.S. Department of Transportation Regulatory Impact Analysis Underground Natural Gas Storage Interim Final Rule December 7, 2016 Regulatory Impact Analysis: Underground Natural Gas Storage Executive Summary Federal government data show a total of 390 active underground natural gas storage fields in the United States as of 2015 (EIA, 2016e). The fields encompass an estimated 16,991 injection/withdrawal or pressure control/observation wells (AGA,... ## Document text <<>> Pipeline and Hazardous Materials Safety Administration U.S. Department of Transportation Regulatory Impact Analysis Underground Natural Gas Storage Interim Final Rule December 7, 2016 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Front Matter Prepared with support by Abt Associates Inc. 55 Wheeler Street, Cambridge, MA 02138 under Delivery Order #DTPH5616F00006 ii <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Table of Contents Table of Contents Executive Summary ................................................................................................................ 1 1 Introduction .................................................................................................................... 1-1 1.1 Purpose ................................................................................................................................ 1-1 1.2 Need for Action ................................................................................................................... 1-1 1.3 Report Organization ............................................................................................................ 1-2 2 Overview of the Natural Gas Storage Industry .......................................................... 2-1 2.1 Storage Fields ...................................................................................................................... 2-1 2.2 Number of Wells ................................................................................................................. 2-2 2.3 Operators ............................................................................................................................. 2-4 2.4 Regulation of Underground Natural Gas Storage Facilities ................................................ 2-5 3 Summary of IFR Requirements ................................................................................... 3-1 3.1 API Recommended Practices .............................................................................................. 3-1 3.2 Regulatory Alternatives Considered by PHMSA ................................................................ 3-3 4 Analysis Framework ...................................................................................................... 4-1 4.1 Analysis Baseline ................................................................................................................ 4-1 4.1.1 Federal and State Regulations ................................................................................. 4-1 4.1.2 Existing Industry Practices and Implementation ..................................................... 4-1 4.1.3 Baseline Scenarios ................................................................................................... 4-4 4.2 Other Analysis Elements ..................................................................................................... 4-4 4.2.1 Timeframe for the Analysis ..................................................................................... 4-5 4.2.2 Regulatory Alternatives ........................................................................................... 4-5 4.2.3 Discounting of Future Costs and Benefits ............................................................... 4-5 4.2.4 Industry Growth Rate .............................................................................................. 4-5 5 Costs ................................................................................................................................ 5-1 5.1 Costing Methodology .......................................................................................................... 5-1 5.1.1 Mechanical Integrity Testing Costs ......................................................................... 5-1 5.1.2 Costs of Addressing Integrity Issues Identified through Testing ............................. 5-2 5.1.3 Costs of Other RP Elements .................................................................................... 5-3 5.1.4 Reporting Costs ....................................................................................................... 5-4 5.2 Industry Compliance Costs ................................................................................................. 5-5 5.2.1 Full Industry Compliance Baseline.......................................................................... 5-5 5.2.2 Partial Industry Compliance Baseline ...................................................................... 5-5 5.2.3 Regulatory Compliance Only Baseline .................................................................... 5-8 5.3 Economic Impacts ............................................................................................................. 5-10 iii <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Table of Contents 6 Benefits ............................................................................................................................ 6-1 6.1 Natural Gas Releases from Underground Storage .............................................................. 6-1 6.1.1 Catastrophic Releases .............................................................................................. 6-1 6.1.2 Operational Releases ............................................................................................... 6-3 6.2 Benefits of the IFR .............................................................................................................. 6-3 7 Uncertainty and Limitations ......................................................................................... 7-1 7.1 Affected Facilities and Operators ........................................................................................ 7-1 7.2 Baseline Degree of Compliance .......................................................................................... 7-2 7.3 Mechanical Integrity Testing Costs .................................................................................... 7-2 7.4 Timing of Compliance Activities ........................................................................................ 7-3 7.5 Effectiveness of RPs to Prevent Future Incidents ............................................................... 7-3 8 Analyses Required under Applicable Statutes or Executive Orders ........................ 8-1 8.1 Executive Orders 12866 and 13563: Analysis of Costs and Benefits ................................. 8-1 8.2 Regulatory Flexibility Act (RFA) ....................................................................................... 8-2 8.2.1 Identifying Small Entities ........................................................................................ 8-2 8.2.2 Small Businesses Affected by the Final Rule .......................................................... 8-3 8.2.3 Impacts of the IFR on Small Entities ....................................................................... 8-4 8.3 Unfunded Mandates Reform Act (UMRA) Analysis .......................................................... 8-5 8.4 Executive Order 13132: Federalism .................................................................................... 8-5 8.5 Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use ................................................................................... 8-6 8.6 Paperwork Reduction Act of 1995 ...................................................................................... 8-7 9 References ....................................................................................................................... 9-1 Appendix A – Summary of API Recommended Practices .................................................. 1 Appendix B – Operator-level Costs ....................................................................................... 1 iv <<>> Regulatory Impact Analysis: Underground Natural Gas Storage List of Exhibits List of Exhibits Exhibit 2-1: Underground Natural Gas Storage by State in 2015. ............................................................. 2-2 Exhibit 2-2: Top 10 Underground Natural Gas Storage Facility Operators by Working Capacity in 2015; in Alphabetical Order. ............................................................................................... 2-4 Exhibit 2-3: Summary of State Mechanical Integrity Requirements for Natural Gas Storage .................. 2-6 Exhibit 4-1: Operators with Existing Commitments to Conducting Integrity Testing .............................. 4-4 Exhibit 5-1: Well Testing Costs by Depth Category (CD). ........................................................................ 5-1 Exhibit 5-2: Recordkeeping and Reporting Costs (2015$) ........................................................................ 5-5 Exhibit 5-3: Annualized Compliance Costs Relative to the Full Industry Compliance Baseline Scenario (2015$) ................................................................................................................. 5-5 Exhibit 5-4: Incremental Integrity Testing Costs Relative to the Partial Industry Compliance Baseline Scenario, by State. ................................................................................................ 5-6 Exhibit 5-5: Annualized Integrity Testing Costs Relative to the Partial Industry Compliance Baseline Scenario (Million 2015$)1 .................................................................................... 5-7 Exhibit 5-6: Annualized Compliance Costs Relative to the Partial Industry Compliance Baseline Scenario (Million 2015$)1 ................................................................................................... 5-7 Exhibit 5-7: Incremental Integrity Testing Costs Relative to the Regulatory Compliance Only Baseline Scenario, by State. ................................................................................................ 5-8 Exhibit 5-8: Annualized Integrity Testing Costs Relative to the Regulatory Compliance Only Baseline Scenario (Million 2015$)1 .................................................................................... 5-9 Exhibit 5-9: Annualized Compliance Costs Relative to the Regulatory Compliance Only Baseline Scenario (Million 2015$)1 ................................................................................................. 5-10 Exhibit 6-1: Social Cost of Methane1,2 ....................................................................................................... 6-5 Exhibit 6-2: Climate Change-related Impacts of Methane Emissions from Natural Gas Storage Wells ................................................................................................................................... 6-5 Exhibit 8-1: Small Business Size Standards: Subsector 486 – Pipeline Transportation ............................ 8-3 Exhibit 8-2: Size of Natural Gas Underground Storage Operating Entities Affected by the IFR ............. 8-4 Exhibit 8-3: Summary of Economic Impact Screening Analysis .............................................................. 8-5 v <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Executive Summary Executive Summary The Pipeline and Hazardous Materials Safety Administration (PHMSA) is promulgating an interim final rule (IFR) that revises the Pipeline Safety Regulations applicable to underground natural gas storage facilities. The IFR incorporates by reference American Petroleum Institute (API) Recommended Practices (RP): API RP 1170, “Design and Operation of Solution-mined Salt Caverns used for Natural Gas Storage” (July 2015), and API RP 1171, “Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs” (September 2015). The RPs provide consensus safety measures for design, construction, maintenance, risk-management, and integrity-management procedures for natural gas storage. By adopting the API RPs by references, the IFR takes an urgent first step to establishing uniform safety standards across the United States and addressing the Congressional mandate contained in the PIPES Act of 2016 for PHMSA to promulgate minimum safety standards for underground natural gas storage facilities. Natural gas storage facility operators and industry trade groups have highlighted their existing commitment to implementing the API RPs. While intrastate storage facilities in certain states with existing regulations are currently required to implement certain safety measures such as assessing the integrity of their wells, for other facilities compliance with the API RPs is currently voluntary. 1 The IFR will set regulatory requirements for operators to assess the operational safety of their underground natural gas storage facilities and document the implementation of identified safety solutions. To the extent that some operators may not have implemented the practices contained in the API RPs in the absence of regulation, the IFR would impose incremental costs on the industry. Based on a review of existing practices, PHMSA estimates that incremental costs will mostly result from the requirement to test the mechanical integrity of natural gas storage wells and to submit documentation to PHMSA. This report details PHMSA’s analysis of the costs and benefits of the IFR. This regulatory analysis meets PHMSA’s statutory requirement for risk analysis for new rules as required by 49 USC 60102. It also provides information to support the review of the costs and benefits of the regulation in accordance with Executive Orders 12866 and 13563.2 1 On February 5, 2016, PHMSA issued Advisory Bulletin ADB–2016–02 (81 FR 6334). The advisory bulletin recommended that operators of underground natural gas storage facilities review their operating, maintenance, and emergency response activities to ensure that the integrity of underground natural gas storage facilities is properly maintained. This bulletin informed operators about recommended practices and urged operators to take all necessary actions to prevent and mitigate breach of integrity, leaks, or failures at their underground natural gas storage facilities and to ensure the safety of the public and operating personnel and to protect the environment. 2 Executive Order 13563 (Improving Regulation and Regulatory Review; January 18, 2011), reaffirms the principles enunciated in Executive Order 12866 (Regulatory Planning and Review; September 30, 1993) by stating that “to the extent permitted by law, each agency must, among other things: (1) propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor its regulations to impose the least burden on society, consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations; (3) select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity); (4) to the extent feasible, specify performance objectives, rather than specifying the behavior or manner of compliance that regulated entities must adopt; and (5) identify and assess available alternatives to direct regulation, including providing economic incentives to encourage the desired behavior, such as user fees or marketable permits, or providing information upon which choices can be made by the public. ES-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Executive Summary Federal government data show a total of 390 active underground natural gas storage fields in the United States as of 2015 (EIA, 2016e). The fields encompass an estimated 16,991 injection/withdrawal or pressure control/observation wells (AGA, 2014). Approximately 60 percent of the aggregate storage capacity is associated with the interstate transportation of natural gas (FERC, 2016), with the remaining 40 percent involved in intrastate transportation.3 This regulatory analysis considers impacts relative to a baseline that includes the practices currently implemented by operators to comply with state regulations where applicable, operator integrity management programs, and industry commitments, including by Interstate Natural Gas Association of America (INGAA) members to implement API RP 1170 and 1171 within the next decade (INGAA, 2016). INGAA members operate approximately half of active natural gas storage fields (210 fields out of the total 390 fields) and 70 percent of wells. Exhibit ES-1 summarizes the estimated annualized costs of the IFR relative to three baseline scenarios that reflect the assumed level of implementation of the API RPs in the absence of a federal regulation. The first scenario is full compliance in the baseline (full compliance); the second scenario is baseline compliance by operators of facilities covered by state regulations or that have made commitments to implement the RPs individually or through their trade association (partial compliance); the third scenario is only wells in intrastate facilities subject to state regulations would be tested in the baseline (regulatory compliance only). The cost impacts of the IFR range from increased reporting burden only for the full compliance baseline to the costs of conducting mechanical integrity tests on zero, 2,408 and 13,862 active wells, respectively, for the full compliance, partial compliance, and regulatory compliance only baselines. These estimates reflect PHMSA’s assumptions regarding the timing of mechanical integrity tests over a 10-year phase-in period and 10-year interval between tests. Section 5 of this report details the analysis. As described in Section 5, the analysis focuses specifically on costs to comply with the requirements to conduct mechanical integrity tests. This focus is reasonable given the potential significance and magnitude of costs to underground natural gas storage facility operators, but it is important to note that operators must also comply with all other applicable measures described in the API RPs. For this analysis, PHMSA determined that the costs for these other measures will be small because operators already implement the measures in the baseline or compliance will require only de minimis changes in existing practices. PHMSA seeks comment and data on which of these baseline scenarios best characterizes the current compliance in the industry. 3 The 192 interstate fields account for the 60 percent of working gas capacity (2,884 billion cubic feet) and 65 percent of the wells (11,065 wells), whereas 198 intrastate fields account for 40 percent of the working gas capacity (1,872 billion cubic feet) and 35 percent of the wells (5,926 wells). ES-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Executive Summary Exhibit ES-1: Incremental Annualized Costs of the FR (Million 20155)' Full Compliance Incremental Costs Relative to API RPs Implementation Baseline Baseline Partial Compliance Regulatory Compliance Cost Component 3% 7% 3% Baseline 7% 3% Only Baseline Discount 7% Rate Discount Rate Discount Discount Rate Rate Discount Rate Discount Rate Mechanical integrity testing? $0.0 $0.0 $27.2 $31.7 $170.6 $193.6 Other RP elements $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 Reporting <$0.1 <$0.1 <$0.1 <$0.1 <$0.1 <$0.1 TOTAL' <$0.1 <$0.1 $27.2 $31.7 $170.6 TRange reflects the assumed baseline level of compliance with API RPs in absence of regulatory requirements. $193.6 2 Based on 10-year phase-in of integrity tests and a 10-year interval between tests. See Section 4 for details. Based on information provided by the industry, PHMSA assesses the most likely baseline conditions as lying between full compliance and partial compliance. This means that the estimated annual costs of the rule range from $0.1 million (under the full compliance baseline) to $27.2 million (under the partial compliance baseline) using a 3 percent discount rate. Estimated annual costs are $0.1 million (under the full compliance baseline) to $31.7 million (under the partial compliance baseline) using a 7 percent discount rate. PHMSA judges the regulatory compliance only baseline as highly unlikely given information provided by the major trade association representing underground natural gas storage facility operators regarding baseline implementation of API RPs. Accordingly, the estimated costs under that scenario represent a less likely outcome from an incremental cost perspective. As such, PHMSA determined that the final rule is not economically significant under Executive Orders 12866 and 13563 because the estimated annual impact is less than $100 million. The FR rule will provide benefits by setting uniform and enforceable PHMSA minimum safety standards for all natural gas storage facilities across the United States. The standards are designed to enable natural gas storage facility operators to detect and address well integrity issues and thereby prevent accidental releases of natural gas and the resulting damages and environmental impacts. PHMSA does not have data to quantify the change in risk due to required integrity tests and other measures provided by the API RPs, and the resulting benefits. As noted in Section 6 of this report, however, past accidents involving natural gas storage facilities have resulted in significant damages, evacuations, injuries, fatalities, and environmental impacts. Sempra Energy, the parent company of Southern California Gas Company (SoCalGas) which operates the Aliso Canyon facility, has estimated the private financial costs of the Aliso Canyon incident at $763 million (Sempra Energy, 2016).4, 5 These costs do not include additional costs to society resulting from the release, such as 4 Of the $763 million, Sempra Energy notes "approximately 70% is for the temporary relocation program (including cleaning costs and certain labor costs) and approximately 20% is for efforts to control the well, stop the leak, stop or reduce emissions, and value of lost gas, the costs to mitigate the actual natural gas released and other costs. Cost estimate excludes any potential the estimated cost of the root cause investigation. The remaining amount includes legal costs incurred to defend litigation, the damage awards, restitution and any civil, administrative or criminal fines and other penalties that may be imposed, as well as any estimate what amounts, if any, will be incurred for such matter." (Sempra Energy, 2016) additional costs to clean homes and future legal costs necessary to defend litigation, among other potential costs, as we cannot 5 Private financial costs include a mix of remediation, repair, ex gratia payments to persons and public agencies affected by the incident, anticipated or actual penalties, as well as litigation costs and settlements. Firms vary in the extent of their public ES-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Executive Summary an estimated $55.3 million to $344.2 million in climate-related impacts from the approximately 5.7 BCF of gas released into the atmosphere, which PHMSA estimated based on the social cost of methane (see Section 6.2 for details). As part of the regulatory impact analysis for this final rule, PHMSA also evaluated the impacts of the rule with respect to various administrative requirements. PHMSA determined that the rule:  Would not have “a significant impact on a substantial number of small entities” (no SISNOSE) under the Regulatory Flexibility Act (RFA). Section 8.2 details the analysis of small entity impacts.  Does not impose enforceable duties on State, local, or tribal governments or on the private sector of $151 million in any one year and therefore does not have implications under Section 202 of the Unfunded Mandates Reform Act (UMRA) of 1995.  Does not have federalism implications because it does not impose substantial direct compliance costs on State or local governments.  Will increase the cost of transporting natural gas only slightly and by much less than the 1 percent threshold suggestive of potential significant adverse impacts on energy supply, distribution, or use. Therefore no Statement of Energy Effects is needed under Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.  Will change the information collection requirements associated with certain natural gas storage facilities. PHMSA estimated changes in reporting and recordkeeping burden and is submitting a revised Information Collection Request (ICR) to the Office of Management and Budget (OMB) for approval under the Paperwork Reduction Act. disclosure of the details of costs incurred. In this case, it is unclear from Sempra’s disclosure whether the reported costs include estimates of business losses from the unavailability of the Aliso Canyon facility. ES-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 1. Introduction 1 Introduction This report provides the estimated costs and benefits of the Interim Final Rule (IFR) to incorporate consensus standards for underground natural gas storage facilities. PHMSA is promulgating the IFR to address critical safety gaps and protect the public and the environment from natural gas releases from underground storage facilities. The analyses described in this report fulfill the requirements of Executive Orders 12866 and 13563 to prepare an assessment of the benefits and costs of the rule as well as reasonably feasible alternatives. They also meet PHMSA’s statutory requirement for risk analysis for new rules (49 USC 60102 et. seq.). 1.1 Purpose In this IFR, PHMSA is adopting two American Petroleum Institute (API) Recommended Practices (RP):6 API RP 1170, “Design and Operation of Solution-mined Salt Caverns used for Natural Gas Storage” (July 2015), and API RP 1171, “Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs” (September 2015) (API, 2015a; API, 2015b). The RPs describe a range of measures that operators of underground natural gas storage facilities should implement to ensure the safety of their operations, including construction, maintenance, risk- management, and integrity-management procedures. The IFR makes these provisions mandatory unless operators provide justification in their program or procedural manuals as to why compliance with a provision of the RP is not practicable and necessary for the safety of a particular facility. PHMSA is issuing this IFR as an urgent first step7 in reducing the likelihood of incidents such as the 2015 Aliso Canyon natural gas leak in the future. Rapid incorporation of API RP 1170 and 1171 into PHMSA’s regulations will require operators to assess the operational safety of their underground natural gas storage facilities and document the implementation of identified safety solutions. After this IFR incorporating API RP 1170 and 1171 becomes effective, PHMSA and its state partners will monitor and enforce operators’ implementation of the requirements. After issuance of this IFR, as a second phase, PHMSA will further investigate the need for additional regulatory requirements for underground natural gas storage incidental to transportation. PHMSA intends to hold a public meeting, and may pursue an additional rulemaking to address remaining safety concerns. 1.2 Need for Action Following the accident at Aliso Canyon in 2015, the U.S. Congress recognized the need and urgency to address safety gaps at underground natural gas facilities in enacting the PIPES Act of 2016 (Public 6 PHMSA participated, along with the Federal Energy Regulatory Commission (FERC), several state regulatory agencies, and numerous industry representatives, in the development of the two API RPs. 7 These measures complement Advisory Bulletin ADB–2016–02 PHMSA issued on February 5, 2016 (81 FR 6334). The advisory bulletin recommended that operators of underground natural gas storage facilities review their operating, maintenance, and emergency response activities to ensure that the integrity of underground natural gas storage facilities is properly maintained. This bulletin informed operators about recommended practices and urged operators to take all necessary actions to prevent and mitigate breach of integrity, leaks, or failures at their underground natural gas storage facilities to ensure the safety of the public and operating personnel and to protect the environment. 1-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 1. Introduction Law 114-183). 8 The PIPES Act requires PHMSA, not later than 2 years after the date of enactment of the PIPES Act of 2016 and in consultation with the heads of other relevant Federal agencies, to issue minimum safety standards for underground natural gas storage facilities. In issuing minimum safety standards for underground storage facilities, PHMSA must: “(1) consider consensus standards for the operation, environmental protection, and integrity management of underground natural gas storage facilities; (2) consider the economic impacts of the regulations on individual gas customers; (3) ensure that the regulations do not have a significant economic impact on end users; and (4) consider the recommendations of the Aliso Canyon natural gas leak task force established under section 31 of the PIPES Act of 2016.” Lapses in operation and maintenance at underground natural gas storage facilities can and has resulted in accidents. Industry standards and recommended practices such as API RP 1170 and RP 1171 describe measures that industry representatives have agreed on as representing good operating practices. Although these recommended practices may be widely followed and implemented, they are not enforceable regulations until incorporated into 49 CFR Part 192 by the IFR. In the absence of regulations mandating the implementation of safety measures for the operation of underground natural gas storage facilities, including the discovery and repair of hazardous conditions, operators may not always implement those safety measures, thereby increasing the potential harm to the public and environment. The absence of explicit regulatory requirements also limits PHMSA’s ability to pursue enforcement against operators that fail to implement safe practices. 1.3 Report Organization The remainder of this report is organized as follow:  Section 2 provides an overview of the natural gas storage industry and the facilities and operators expected to be subject to the IFR requirements, described in Section 3.  Section 4 describes the analysis framework, including the baseline which reflects the practices currently implemented by facility operators or expected to be implemented by the time the IFR would be effective, absent the regulatory action.  Sections 5 and 6 discuss the incremental costs and benefits, respectively, expected to arise from implementation of the IFR relative to the baseline described in Section 4.  Section 7 discusses uncertainties and limitations of the analysis and indicates the direction of any known bias.  Section 8 provides information on analyses and evaluations that fulfill requirements in other Statutes and Executive Orders to evaluate the costs, benefits, or economic impacts of new regulations. Additional sections and appendices provide cited references and supporting data. 8 Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, signed into law on June 22, 2016. 1-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile 2 Overview of the Natural Gas Storage Industry Underground storage of natural gas offers important benefits to the U.S. energy supply infrastructure, notably the ability to manage seasonal variations in natural gas demand and to provide a buffer for changing production levels. Significant growth in domestic natural gas production from shale gas in the last decade has prompted renewed interest and investment in storage capacity. Between 1995 and 2014, total natural gas storage capacity increased by nearly 16 percent to a total of 9,233 BCF (EIA, 2016b). The Energy Information Administration (EIA) reports that 3,600 BCF of natural gas was injected into underground storage facilities in 2015 (EIA, 2016a) – a volume of natural gas valued at over $15 billion.9 For comparison, total natural gas consumption in the United States in 2015 was 27,473 BCF (EIA, 2016d). There are three primary types of natural gas storage facilities (fields) in the United States (EIA, 2015):  Depleted oil and gas reservoirs are the most common type of storage, representing approximately 81 percent of the total working gas capacity and 77 percent of the total design capacity in the United States. As the name implies, these facilities are reservoirs that were previously used to produce oil and/or gas and have been converted for storage by repurposing the production wells and aboveground equipment to inject and withdraw gas as needed to build up storage or meet demand.  Salt caverns (salt dome) are geological formations that have been leached or mined out of their salt deposits. These facilities represent about 11 percent of the total working gas capacity and 8 percent of the total design capacity.  Aquifers are natural water-bearing formations that have been converted to store gas. They represent the remaining 9 percent of the total working gas capacity and 15 percent of the total design capacity. 2.1 Storage Fields PHMSA estimates that there were 390 active natural gas storage fields10 in the United States in 2015, distributed across 31 states (EIA, 2016e; Federal Energy Regulatory Commission (FERC), 2016; and PHMSA, 2016b). These fields had an aggregate storage capacity11 of 9,155 billion cubic feet (BCF) and a working capacity12 of 4,756 BCF (EIA, 2016e). Facilities used for interstate commerce 9 Value is based on the citygate price of natural gas of $4.25 per thousand cubic foot in 2015. Citygate refers to a point or measuring station at which a distributing gas utility receives gas from a natural gas pipeline company or transmission system (EIA, 2015). 10 PHMSA used EIA-191 for 2015 as primary data to determine the number of active fields. The definition of a field is based on the number of records for which EIA indicates the status as “Active” (EIA, 2016e). Note that other available data (FERC, 2016; PHMSA, 2016b) may subdivide or group fields, resulting in different counts of natural gas storage facilities. 11 Total natural gas storage capacity is the maximum volume of natural gas that can be stored in an underground storage facility in accordance with its design, which comprises the physical characteristics of the reservoir, installed equipment, and operating procedures particular to the site (EIA, 2015). 12 Working gas is the volume of gas in the reservoir above the level of base gas. Working gas is available to the marketplace (EIA, 2015). 2-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile represented approximately 60 percent of the working capacity while intrastate facilities represented the remaining 40 percent. Exhibit 2-1 summarizes the data by state. For this analysis, a natural gas storage facility is equivalent to a unique gas field record in EIA-191 data (EIA, 2016e). Exhibit 2-1: Underground Natural Gas Storage by State in 2015. State Number of Active Fields1 Design Capacity (BCF)3 Working Capacity (BCF)3 Interstate2 Intrastate2 Total Interstate2 Intrastate2 Total Alaska 5 0.0 83.6 83.6 0.0 67.9 67.9 Alabama 2 0.0 43.6 43.6 0.0 33.2 33.2 Arkansas 2 0.0 21.9 21.9 0.0 12.2 12.2 California 14 0.0 601.8 601.8 0.0 375.5 375.5 Colorado 10 100.8 29.4 130.2 52.1 11.7 63.8 Illinois 27 135.9 851.4 987.3 46.5 255.6 302.1 Indiana 20 12.2 99.1 111.3 5.0 28.4 33.4 Iowa 4 288.2 0.0 288.2 90.3 0.0 90.3 Kansas 16 271.8 10.5 282.3 116.7 5.9 122.6 Kentucky 22 168.2 52.1 220.3 79.3 28.3 107.6 Louisiana 17 669.5 55.0 724.4 406.5 39.2 445.7 Maryland 1 64.0 0.0 64.0 18.3 0.0 18.3 Michigan Minnesota 44 435.7 644.9 1,080.6 282.5 403.2 685.7 1 0.0 7.0 7.0 0.0 2.0 2.0 Mississippi 12 287.8 44.0 331.8 169.2 32.2 201.4 Missouri 1 0.0 13.8 13.8 0.0 6.0 6.0 Montana 4 287.2 89.0 376.2 164.4 33.1 197.5 Nebraska 1 34.9 0.0 34.9 14.8 0.0 14.8 New Mexico 2 68.6 20.5 89.1 44.0 15.7 59.7 New York 26 229.3 11.3 240.6 122.5 3.5 126.0 Ohio 22 402.9 171.8 574.8 167.5 63.3 230.7 Oklahoma 12 196.8 179.2 376.0 104.7 87.7 192.4 Oregon 7 0.0 29.6 29.6 0.0 15.9 15.9 Pennsylvania 47 737.6 28.5 766.1 411.8 15.5 427.3 Texas 32 326.3 515.9 842.2 210.0 322.6 532.6 Utah 3 124.5 0.0 124.5 54.9 0.0 54.9 Virginia 2 0.0 9.5 9.5 0.0 5.4 5.4 Washington 1 46.9 0.0 46.9 24.6 0.0 24.6 West Virginia 26 488.6 8.7 497.3 229.9 3.3 233.1 Wyoming 7 131.0 24.1 155.0 68.2 4.9 73.2 U.S. Total 390 5,508.5 3,646.3 9,154.8 2,883.7 1,872.0 4,755.7 1. Number of fields based on Form EIA-191 through 2015 (EIA, 2016e). 2. Interstate fields identified from the FERC (2016) list of jurisdictional fields and PHMSA (2016b) data. All other fields are intrastate fields. 3. Capacity data based on EIA (2016e). 2.2 Number of Wells The American Gas Association (AGA) publishes a report periodically on the natural gas storage fields in the lower-48 states and Canada (AGA, 2014). The report provides field-level data on total 2-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile number of injection/withdrawal wells, the number of horizontal injection/withdrawal wells, and the number of pressure control/observation wells. PHMSA used the AGA data to determine the number of wells in each active field potentially subject to the regulation. The AGA report also provides the minimum and maximum depth to the formation, among other information about the geological characteristics of each field. PHMSA used this information to classify the wells in three depth categories: 3,500 feet or less; 3,501 feet to 7,000 feet; and greater than 7,000 feet. Specifically, PHMSA matched the fields identified in the EIA data described in Section 2.1 to the corresponding information in the AGA report for each field and transferred data on the number of injection/withdrawal wells, the number of horizontal injection/withdrawal wells, and the number of pressure control/observation wells. The AGA report does not include data for fields in Alaska. PHMSA estimated the number of wells in these fields based on their storage capacity and the ratio of wells to total storage capacity for active fields in the lower-48 states (0.51 well per BCF of storage capacity). PHMSA further assumed that wells in Alaska are 3,500 feet or less in depth, as this is the most common depth category for fields in the lower-48 states. Fields reported in the AGA survey but not in EIA data were left out of the analysis. In some cases, AGA provides information for combined fields (e.g., Fink and Kennedy together) that are listed separately in the EIA data (Fink and Kennedy as two fields). In that case, PHMSA assigned the wells to one of the EIA listed fields. Based on these data, PHMSA estimated that there are a total of 16,991 injection/withdrawal wells and pressure control/observation wells within the 390 active fields.13 PHMSA seeks comment, supported by data, on this estimate of the number of wells. Many of these wells are decades old. For example, the well involved in the October 2015 Aliso Canyon accident (see Section 6.1) was drilled in 1953 and was repurposed for natural gas storage in 1972. This age is not exceptional: according to AGA data, approximately 60 percent of active injection, withdrawal, pressure control or observation wells are located in storage fields that were activated before 1960 (AGA, 2014). Although AGA does not provide data on the age of individual wells, it is reasonable to expect that many wells are developed by the time a storage facility starts operating. The Interagency Task Force on Natural Gas Storage Safety (2016) highlights growing concerns regarding the age of the natural gas storage infrastructure as it affects risk. Wells reflect material, technology, and design factors applicable at the time they were constructed and many may not meet design criteria for new wells. Over time, corrosion, other environmental processes, and mechanical stresses from injection and withdrawal of natural gas can weaken well integrity. Wells in depleted oil fields may have been designed for lower pressure than the stress they are now subject to. Further many of these wells were not designed with redundant barriers to gas migration and present riskier, single points of failure. 13 PHMSA notes that this number is slightly lower than estimates provided in some other sources. For example, in its letter to PHMSA, INGAA (2016) stated that “there are approximately 17,500 active and observation storage wells in these fields.” 2-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile 2.3 Operators Entities that operate natural gas storage include interstate and intrastate pipeline companies, local distribution companies (LDCs) and independent storage providers. These entities are classified into North American Industry Classification System (NAICS) code 486210: Pipeline Transportation of Natural Gas. The most recent Economic Census shows total revenue for this sector of $23 billion in 2012, with 125 firms and 2,118 establishments (U.S. Census, 2012). Following the NAICS definition of the sector, these figures include revenue and entities involved in the storage of natural gas in either underground, aboveground, or LNG facilities, or in natural gas transmission. As further discussed in Section 8.2, the Small Business Administration (SBA) defines entities in this sector as small if they have annual receipts of $27.5 million or less (SBA, 2016). As described by EIA (2015), the owners or operators of storage facilities do not necessarily own the natural gas held in storage. In fact, most working gas held in storage facilities is held under lease with shippers, LDCs, or end users who own the gas. The type of entity that owns or operates the facility determines to some extent how that facility's storage capacity is utilized. For example, interstate pipeline companies rely heavily on underground storage to balance load and manage system supply on their long-haul transmission lines. FERC regulations allow interstate pipeline companies to reserve some portion of their storage capacity for this purpose, but the bulk of their storage capacity is leased to other industry participants under open access rules. Intrastate pipeline companies also use storage capacity and inventories for similar purposes, in addition to serving customers. Based on the field-level data described above, 124 companies operate the 390 active fields. Exhibit 2-2 lists the top 10 operators in terms of total working capacity in 2015. These operators accounted for approximately half of the total working capacity, total design capacity, and number of wells. Exhibit 2-2: Top 10 Underground Natural Gas Storage Facility Operators by Working Capacity in 2015; in Alphabetical Order. Operator Number of Active Fields Total Working Capacity (MCF) Total Design Capacity (MCF) Number of Wells ANR Pipeline Company1 14 191.2 317.0 932 Columbia Gas Transmission LLC 32 282.5 677.7 3,362 Consumers Energy Company 14 148.3 303.2 981 Dominion Transmission INC 15 417.6 754.4 1,431 Michigan Consolidated Gas Company 5 230.0 306.4 102 Natural Gas Pipeline Co. of America 8 288.0 602.1 691 Northern Illinois Gas Company 8 149.7 466.3 516 Pacific Gas and Electric Company 3 102.2 173.0 116 Southern California Gas Company 4 135.3 266.9 196 Williston Basin Interstate Pipeline 2 192.8 350.4 203 Top 10 Operators’ Share of U.S. Total 27% 45% 46% 50% Sources: Form EIA-191 through 2015 (EIA, 2016e); AGA (2014). 1 Does not include storage fields operated by affiliated companies and subsidiaries. 2-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile As discussed further in Section 8.2, natural gas storage facility operators include four entities that meet SBA’s definition of a small business, including one small municipal government. 2.4 Regulation of Underground Natural Gas Storage Facilities FERC has jurisdiction over storage facilities engaged in interstate commerce of natural gas; these facilities represent approximately 60 percent of the total storage capacity and total working capacity in the United States (see Exhibit 2-1). With the implementation of FERC Order 636 in 1994, interstate pipeline companies have been required to operate their storage facilities on a nondiscriminatory or open-access basis14 (EIA, 2015). FERC reviews rates for storage and storage- related services under the authority of § 4(f) of the Natural Gas Act of 1938, but does not set safety requirements for fields under its jurisdiction. The U.S. Environmental Protection Agency (EPA) oversees Section 112(r) of the Clean Air Act which aims to “prevent the accidental release [of extremely hazardous substances] and to minimize the consequences of any such release” from stationary sources. 42 U.S.C. § 7412(r)(1). Section 112(r)(7) also authorizes EPA to publish regulations that impose accident prevention and emergency response requirements on stationary sources that hold more than a threshold quantity of certain regulated substances in a process. EPA’s “Risk Management Plan” regulations are codified at 40 CFR 68. However, these regulations specifically exempt facilities that are subject to oversight or regulation under 49 CFR parts 192, 193, or 195, or a state natural gas or hazardous liquid program for which the state has in effect a certification to DOT under 49 U.S.C. section 60105. Facilities engaged in intrastate commerce may be regulated by the oil and gas commission, environmental protection department, or other government agency of the state where they are located. As of May 2016, PHMSA found that of the 16 states with intrastate underground natural gas storage facilities (out of the total of 30 states with storage facilities), ten states had promulgated or proposed regulations requiring operators to implement preventive measures such as mechanical integrity testing to prevent the accidental release of natural gas from storage facilities. Exhibit 2-3 summarizes the requirements applicable to intrastate facilities in the ten states, focusing specifically on requirements pertaining to mechanical integrity assessments and tests. As shown in the table, existing or proposed regulations in nine states require well mechanical integrity tests every 10 years or more frequently.15 While PHMSA has jurisdiction over interstate and intrastate fields, it currently does not have safety requirements under 49 CFR Part 192 covering the wells and wellbore tubing and casing. The absence of federal safety regulations over interstate facilities and of state regulation over much of the intrastate facilities leaves over three quarters of natural gas storage capacity as currently unregulated, based on working gas capacity. The gap also means that an estimated 13,682 wells out of the total 16,991 active storage wells (81 percent of wells) are currently unregulated. 14 Open access means that the working gas storage capacity (beyond what may be reserved by the pipeline/operator to maintain system integrity and for load balancing) at each site must be made available to third parties (i.e., shippers or customers) on a first- come, first-served basis at nondiscriminatory rates (EIA, 2015). 15 The tenth state, Michigan, exempts natural gas storage wells from the periodic testing requirements applicable to other types of injection wells. 2-5 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile Exhibit 2-3: Summary of State Mechanical Integrity Requirements for Natural Gas Storage State Regulation Summary of Requirements1 Alabama Alabama Gold Book, 400-5-7-.01  Test for internal mechanical integrity prior to storing gas using approved method and demonstrate internal mechanical integrity at least every five years thereafter.  Conduct tests for fluid movement along the annular space outside the wellbore when deemed necessary by the state. California Chapter 4: Development, Regulation, and Conservation of Oil and Gas Resources; Subchapter 1: Onshore Well Regulations (California Department of Conservation, 2016b)  Mechanical integrity tests of all storage wells on a 5-year interval.  Daily inspections of gas wellheads, using gas leak detection technology.  On-going measurement of annular gas pressure or annular gas flow within wells.  Regular testing of all safety valves – surface and subsurface.  Establish minimum and maximum pressure limits for each gas storage facility.  Comprehensive risk management plans that evaluate risks at the facility including corrosion of pipe and equipment. Illinois Illinois Administrative Code: Title 62, Part 240. Subpart R: Requirements in Underground Gas Storage Fields and for gas Storage and Observation Wells  Permit application and review process.  Internal mechanical integrity performed prior to initial injection for newly permitted Class II UIC well, following certain changes, and at least once every 5 years. Indiana Indiana Administrative Code. Article 16: Oil and Gas  One of the following methods must be used to evaluate mechanical integrity of the casing, tubing or packer: (1) After an initial pressure test, monthly monitoring of annulus pressure (at a positive value) by the owner or operator to be reported to the division no less frequently than quarterly. (2) Pressure testing with liquid. Where pressure testing is performed, the casing-tubing annulus above the packer must be filled with fluid and tested, with no more than a three percent pressure differential over a thirty-minute period, not less than once every five years under the supervision of a division representative at a pressure of no less than 300 pounds per square inch.  One of the following methods must be used to evaluate mechanical integrity to prevent migration of fluids: (1) The results of a temperature or noise log. (2) Records demonstrating the presence of cement adequate to prevent the migration of fluids in the well bore. (3) A radioactive tracer survey.  The division director may authorize an alternative test only where the test reliably demonstrates the mechanical integrity of a well.  In conducting and evaluating a test authorized by this section, the owner or operator and the director shall apply methods and standards generally accepted in the petroleum industry. When reporting the results of a mechanical integrity test to the director, an owner or operator shall include a description of any test and method used. When evaluating a mechanical integrity test, the division director shall review monitoring and other test data submitted since the previous evaluation. 2-6 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile Exhibit 2-3: Summary of State Mechanical Integrity Requirements for Natural Gas Storage State Regulation Summary of Requirements1 Kansas Kansas Department of Health and Environment K.A.R. 28-45a-14  Hydraulic pressure test for each underground natural gas storage well or storage cavern every five years.  Integrity tests (a) After each workover; (b) before injecting working gas into any existing underground natural gas storage well; and (c) before plugging the well.  Integrity test must be conducted at the maximum allowable operating pressure.  Casing evaluation for each underground natural gas storage well using magnetic flux, ultrasonic imaging or alternative substantially equivalent evaluation method  Casing evaluation (a) every 10 years; (b) before the injection of working gas in an existing underground natural gas storage well; and (b) after any workover in which the injection string is pulled, if present. Kentucky Oil and Gas Regulations. 805 KAR 1:110. Underground injection control  Demonstrate mechanical integrity of new and existing Class II injection wells.  Submit a plan to demonstrate mechanical integrity with the application for permit to inject.  Use one of the following methods to evaluate the absence of significant leaks: (a) Following an initial pressure test, monitoring of the tubing and casing annulus pressure with sufficient frequency to be representative, as determined by the division, while maintaining an annulus pressure different from atmospheric pressure measured at the surface; (b) A pressure test performed with liquid or gas; or (c) Records of monitoring demonstrating the absence of significant changes in the relationship between injection pressure and injection flow rate for Class II enhanced recovery wells.  Use one of the following methods to confirm the absence of fluid movement: (a) The results of a temperature log or noise log, cement bond log; (b) Cementing records demonstrating the presence of adequate cement to prevent a migration; or (c) other methods approved by the administrator.  Perform mechanical integrity test on the annulus of the tubing and casing. A minimum pressure of 300 psi shall be applied to the annulus of the tubing and casing. The well is considered to have mechanical integrity if, at the end of 30 minutes, there is no more than a plus or minus of 3 percent change of the test pressure on the gauge.  A division field inspector must witness and approve a mechanical integrity test.  The division may require higher test pressures to be used when the anticipated injection pressure will be high.  The test results shall be filed on the Certificate of Mechanical Integrity, Form ED-22.  The owner or operator of a Class II well shall schedule at 5-year intervals or less, mechanical integrity test.  The owner or operator shall certify the test results to the division in writing within fifteen days of completion of the test.  The owner or operator shall not perform mechanical integrity test of a Class II well without giving written notice to the division within fifteen calendar days prior to the proposed test date.  The division shall then notify the owner or operator of the earliest possible date available to test the well. 2-7 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile Exhibit 2-3: Summary of State Mechanical Integrity Requirements for Natural Gas Storage State Regulation Summary of Requirements1 Michigan Michigan DEQ. Office of Oil, Gas, and Minerals. Part 615, Chapter 324  Before injecting fluid into a newly drilled well or previously existing well newly converted to an injection well to be utilized for gas storage, a permittee of an injection well shall provide for a test of the mechanical integrity of the casing, by a qualified person, utilizing either a pressure test at a bottom hole pressure of not less than the maximum expected operating pressure of the gas storage field or an equivalent test approved by the supervisor.  Regulations exempt injection wells utilized from gas storage from requirements to develop a plan to conduct 5-year mechanical integrity tests of casing (§§ 324.201 and 324.805). Mississippi Title 53: Oil, Gas and Other Minerals. Rule 64: Underground Storage Wells of Liquefied Compressed Gases, Crude Oils, Refined Hydrocarbons, Compressed Air and Natural Gases in Reservoirs Dissolved in Salt Beds  Design (including casing program), permitting, operating and reporting requirements.  Cavern mechanical integrity test at least every five years.  For injection wells, use one of the following methods must be used to evaluate the absence of significant leaks: 1) pressure test with liquid; 2) Monitoring of annulus pressure. Pennsylvania Pennsylvania’s Oil and Gas Act (Act 223) Tile 58. Chapter 11. Oil and Gas Act  Case and cement gas storage wells to ensure no gas can leak from them.  Conduct monthly inspections of all gas storage wells and all wells used for observation.  Annually inspect the gas storage reservoir and storage protective area to make sure no gas is leaking or other hazardous condition exists.  Implement gas storage well monitoring and integrity testing programs once every five years.  Not exceed pressures that may cause the gas to begin leaking.  Notify DEP within 24 hours of making emergency repairs to gas storage wells and submit a written explanation of the emergency and what action was taken within five days.  Keep records of well inspection results and pressure data, integrity testing data, and inspections of abandoned and plugged wells.  Notify DEP 15 days before the gas storage well is plugged to prevent migration of gas or other fluids within or outside of the well. Texas Texas Administrative Code. Title 16, Part 1, Chapter 3, Rule §3.96 Underground Storage of Gas in Productive or Depleted Reservoirs  Safety training. Prepare and implement a plan to train and test each employee at each gas storage project on operational safety and emergency response procedures to the extent applicable to the employee's duties and responsibilities.  Wellhead pressure. The wellhead pressure of each gas storage well shall be continuously recorded, continuously monitored electronically, or controlled by a preset high-low pressure sensor switch.  Pressure reporting. Information regarding wellhead pressures for each gas storage well shall be reported annually to the commission on the prescribed form.  Integrity testing: ‒ (1) Prior to commencing operations. Before beginning gas injection operations, the operator shall pressure test the long string casing, or the tubing-casing annulus if the well is equipped with tubing set in a packer. Gas storage wells in which injection occurs through casing shall be tested at the maximum authorized injection pressure. Gas storage wells in which injection occurs through tubing and packer shall be tested at no less than 500 psig. ‒ (2) Subsequent tests. Each gas storage well shall be pressure tested in the manner provided in paragraph (1) of this subsection at least once every five years to determine if there are leaks in the 2-8 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 2. Industry Profile Exhibit 2-3: Summary of State Mechanical Integrity Requirements for Natural Gas Storage State Regulation Summary of Requirements1 casing, tubing, or packer. The commission, or its designee, may prescribe a schedule and mail notification to operators to allow for orderly and timely compliance with this requirement. ‒ (3) Alternatives to testing. As an alternative to the testing required in paragraph (2) of this subsection, the tubing-casing annulus pressure may be monitored and monitoring results described in the annual monitoring report required by subsection (n) of this section, provided that there is no indication of problems with the well. The commission, or its designee, may also grant an exception for other viable alternative tests or surveys. ‒ (4) District office notification. The operator shall notify the appropriate district office at least 48 hours prior to conducting the test required in paragraphs (1) or (2) of this subsection. Testing shall not commence before the end of the 48-hour period unless authorized by the district office. ‒ (5) Test records. A complete record of all tests shall be filed in duplicate with the district office within 30 days after the testing. ‒ (6) Gas withdrawal wells exempt. Gas storage wells that shall be used only for gas withdrawal are excluded from the requirements of this subsection. 1 This table provides only a summary of selected requirements. Refer to the full text of each regulation for details. 2-9 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 3. Regulatory Requirements 3 Summary of IFR Requirements In this IFR, PHMSA is adopting two API RPs: API RP 1170, “Design and Operation of Solution- mined Salt Caverns used for Natural Gas Storage,” and API RP 1171, “Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs.” The RPs describe a range of measures that operators of underground natural gas storage facilities should implement to ensure the safety of their operations, including construction, maintenance, risk-management, and integrity-management procedures. The IFR makes these provisions mandatory unless operators provide justification in their program or procedural manuals as to why compliance with a provision of the RP is not practicable and necessary for the safety of a particular facility. 3.1 API Recommended Practices The API RPs apply to both newly constructed and existing underground natural gas storage facilities. For newly constructed facilities the API RPs have sections that address the storage integrity, design, and construction of “new” underground natural gas storage facilities including the following reservoir or cavern and well aspects: siting, integrity, geological characterization, and containment of the reservoir or cavern; the design, well casing, wellhead, cementing, and environmental, safety, and health aspects of the well; and the testing, commissioning, monitoring, and recordkeeping of the well. Regarding the operations and maintenance activities for both new and existing wells, the API RPs have requirements for the following activities: threat identification, risk assessments, preventive and mitigative measures, and periodic review and reassessment; integrity demonstration, verification, monitoring, and gas inventory assessment practices; site security and emergency preparedness and response; and operational procedures, training, and records. Tables in Appendix A summarize the scope of RP 1170 and RP 1171 and highlight operator actions associated with selected recommended practices. Notably, RP 1171 provides guidance on well mechanical integrity evaluation of reservoirs and salt caverns. Well mechanical integrity tests, whether by pressure tests or usage of well logs that detect corrosion (similar to a pipeline smart pig), are critical to an operator’s ability to monitor well integrity and to determine whether the maximum well operating pressure can be sustained in light of corrosion or other anomalous defects or non-conservative well casing design. API RP 1170 and 1171 set general performance objectives but do not specify a mechanical integrity test procedure or testing intervals. API RP 1170 and 1171 require operators to evaluate the integrity of each well through the review of well design, completion, wellhead and downhole inspections, well pressure monitoring and testing, and gas sampling. API RP 1171 gives a minimum test pressure of new and modified well casings. API RP 1171 states that an operator should monitor for tubular (casing and tubing) corrosion and evaluate corrosion impact on well integrity and operating pressure, but does not define an inspection interval. API RP 1170 states that an operator shall have an integrity monitoring program that includes identification of components to be monitored, monitoring methods, cavern volume and inventory verification, analysis of data from inspections and reporting, and periodic review of the program for effectiveness with no defined inspection interval. Sections 6 and 9 of API RP 1171 include a method for a mechanical integrity test for a new well or modified casing. 3-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 3. Regulatory Requirements In this instance, operators are required to test 1.1 times the maximum allowable operating pressure for 30-minutes and verify that the pressure drop does not exceed 10 percent of initial pressure. By adopting the API RPs, PHMSA is making the practices contained therein (i.e., practices that the RPs say “shall” be implemented or that the operator “may consider”) mandatory for all natural gas operators, unless an operator provides justification in its program or procedural manual as to why compliance with a recommended practice for a particular well or facility is not practicable and not necessary for safety. This would involve a documented, technical review that is signed by technical reviewer and senior company management. PHMSA or its state partner would review such justifications during compliance inspections and utilize our range of enforcement tools as necessary to ensure variances are not utilized inappropriately. In addition, PHMSA is able to issue bulletins or otherwise notify operators advising them of variances that have frequently been deemed objectionable and should be avoided under most circumstances. This approach has worked well in pipeline regulation involving incorporation by reference After the IFR becomes effective, PHMSA and its state partners will monitor and enforce operators’ implementation of the requirements. This will include reviewing the integrity test interval established by the operator and the methodology for establishing the interval for a particular well to ensure that it is supported by sound technical analysis. The IFR also specifies new reporting requirements for underground storage facilities by adding requirements for an annual report under 49 CFR §191.17, incident reports for unintentional releases of natural gas under §191.15, and safety-related conditions reports under §191.23. Additionally, operators not currently registered with PHMSA will need to obtain an operator identification number under §191.22. The IFR specifies timelines for facilities to comply with the API RPs, relative to the effective date of the rule. Thus, the IFR requires that facilities meet “the operations, maintenance, integrity demonstration and verification, monitoring, threat and hazard identification, assessment, remediation, site security, emergency response and preparedness, and recordkeeping requirements and recommendations” of API RPs 1170 and 1171 no later than 12 months from the effective date of the rule. This 12-month deadline includes establishment of a testing program to assess the mechanical integrity of the wells and other components of the storage system. The compliance schedule does not require integrity tests to be completed before the 12-month deadline, however. PHMSA expects that wells will be tested over the next several years (5 to 10 years) according to risk-based priorities. Section 8.5 in API RP 1171 describes the six principal components to the risk assessment process: a) identification of potential threats and hazards to a storage facility; b) evaluation of likelihood of events and consequences related to the events; c) determination of risk ranking to develop preventive and mitigating measures to monitor and/or reduce risk; d) documentation of risk evaluation and decision basis for preventive and mitigative (P&M) measures; e) provision for data feedback and validation; and f) regular, periodic risk assessment reviews to update information and evaluate risk management effectiveness. PHMSA determined that, of the sets of actions described in the API RPs, the requirement to conduct mechanical integrity testing of storage wells has the greatest potential to impose incremental costs on facility operators. Site design and planning, risk assessment, pressure monitoring, instrument calibration and other measures described in the API RPs are steps that operators already take to 3-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 3. Regulatory Requirements ensure the reliable and safe supply of natural gas. PHMSA based its determination on a review of ongoing O&M and capital expenditures and existing risk assessment programs described in testimonies to public utilities commissions to support rate recovery requests (e.g., SoCalGas, 2014; Xcel Energy, 2015). 3.2 Regulatory Alternatives Considered by PHMSA PHMSA considered one primary alternative to adopting the API RPs: Promulgating more stringent testing requirements than provided in the API RPs. 16 Because of the Congressional mandate described in Section 1.2, PHMSA cannot consider a “no action alternative” because it would be both inconsistent with Congress’ direction and would not address the current risk to safety, public health or the environment. Therefore, due to PHMSA’s limited discretion due to Congress’ mandate, PHMSA has eliminated the no-action alternative from consideration. PHMSA considered promulgating more stringent requirements for underground storage facilities to further enhance operators’ ability to detect and address integrity issues that could cause a release. The API RPs provide general performance goals for ensuring the integrity of the storage infrastructure but leave specific criteria to the discretion of the operator, based on a risk assessment. Based on information regarding Aliso Canyon and other major well incidents, as well as studies by the industry, service providers, federal regulators, state governments, and academia that address the risk and integrity issues of wells, PHMSA considered setting explicit criteria in a rulemaking that would build and further expand on the principles laid out in RPs 1170 and 1171. For example, PHMSA considered setting specific criteria for (1) determining the maximum allowable operating pressure (MAOP) of the reservoir and (2) testing wells. PHMSA also considered requiring safety valves. Going beyond existing consensus standards, however, would require a more extensive development and review process involving technical studies that would take years to complete. The Aliso Canyon incident highlighted the urgency of closing regulatory gaps. Although PHMSA’s statutory authorization extends to the regulation of underground natural gas storage, the lack of applicable federal downhole regulations currently leaves the agency with no effective means of regulating the safety of interstate underground natural gas storage facilities generally. Proposing major infrastructure requirements subject to extensive technical studies and notice and comment proceedings prior to issuing this IFR would leave the public and the industry without any national minimum safety standards for underground natural gas storage incidental to transportation for years. It would also leave PHMSA without any inspection or enforcement authority for underground natural gas storage facilities during the rulemaking process. PHMSA also considered an alternative that would not mandate compliance with nonmandatory RPs (absent an operator making the justification under new § 192.12(a)(6)). However, PHMSA rejected this alternative because it cannot enforce voluntary provisions. Having an unenforceable “regulation” is meaningless and would not be a regulation at all -- it would be no more than guidance 16 PHMSA determined that a second alternative, which would have incorporated the API RPs by reference but without making the practices mandatory, was impracticable as it would limit PHMSA’s ability to enforce the safety standards. 3-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 3. Regulatory Requirements and would not satisfy the mandate that Congress gave to PHMSA in section 12 of the PIPES Act. In PHMSA’s experience, one of the key reasons why enforceability is important is that it ensures a level playing field for industry. While many operators are committed to safety and would conscientiously follow voluntary RPs, some other companies may be tempted to cut corners, thereby putting operators who invest in safety at a competitive disadvantage. The absence of mandatory requirements applicable to all industry participants reduces regulatory certainty and can result in a race to the bottom. Clear, enforceable regulatory requirements provide the public and operators confidence that all operators are following the same minimum rules. PHMSA seeks public comments on the advantages and disadvantages of this alternative. Because the existing emergency situation necessitates immediate regulatory action, PHMSA opted against this alternative at this time. As a second phase after issuance of this IFR, PHMSA will further investigate the need for more detailed regulatory requirements for underground natural gas storage incidental to transportation and may pursue an additional rulemaking to address remaining safety concerns. This second phase would also benefit greatly from field observation and experience gained in implementing the IFR. 3-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 4. Analysis Baseline 4 Analysis Framework 4.1 Analysis Baseline The baseline for the regulatory analysis represents PHMSA’s best assessment of conditions absent the regulatory action. In the case of this IFR, the analytical baseline accounts for the practices implemented by storage facility operators under existing federal and state regulations, various industry standards and recommended practices, and ongoing initiatives. 4.1.1 Federal and State Regulations As detailed in Section 2, PHMSA has safety authority over the underground storage facilities used in natural gas pipeline transportation. However, the existing safety regulations in 49 CFR Part 192 do not apply to the downhole underground storage reservoir for natural gas. Accordingly, there is no regulatory requirement for the performance of mechanical integrity tests for wells in interstate fields. On February 5, 2016, PHMSA issued Advisory Bulletin ADB–2016–02 (81 FR 6334). The advisory bulletin recommended that operators of underground natural gas storage facilities review their operating, maintenance, and emergency response activities to ensure that the integrity of underground natural gas storage facilities is properly maintained. This bulletin informed operators about recommended practices and urged operators to take all necessary actions to prevent and mitigate breach of integrity, leaks, or failures at their underground natural gas storage facilities and to ensure the safety of the public and operating personnel and to protect the environment. The bulletin is not a regulation, however, and PHMSA cannot compel operators to implement the RPs or enforce compliance. A number of states have promulgated or proposed their own safety regulations for intrastate natural gas storage facilities, including underground storage wells, and inspect and enforce these regulations. See Section 2.4 for details. State requirements for integrity testing are part of the baseline for this analysis and therefore operators of the wells located in intrastate fields within states that have requirements functionally equivalent to the API RPs will not incur incremental costs as a result of the IFR. One exception is Michigan, which as summarized in Exhibit 2-3, does not require mechanical integrity tests for natural gas storage wells; accordingly, PHMSA assumed that operators of intrastate facilities in Michigan may incur incremental costs under the IFR.17 Note that promulgation of the IFR will not preempt exiting state regulations if the state regulations are stricter than federal regulations (e.g., state regulations require integrity testing on a specified, more frequent basis than the API RPs PHMSA is incorporating in this IFR). 4.1.2 Existing Industry Practices and Implementation Since the publication of API RPs in July 2015 and following the Aliso Canyon incident in October 2015, the natural gas storage and transportation industry has highlighted its commitment to ensuring 17 As summarized in Exhibit 2-3, Michigan exempts natural gas storage wells from 5-year mechanical integrity tests applicable to other types of injection wells. 4-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 4. Analysis Baseline the safe storage of natural gas. The industry has made implementation of API RPs 1170 and 1171 an explicit part of this commitment. Overall, the natural gas pipeline industry has been supportive of the need to promulgate consistent federal standards based on the API RPs. On January 20, 2016, INGAA, a trade association representing the majority of interstate natural gas pipeline companies in the United States and a participant in the development of API RP 1170 and 1171, petitioned PHMSA to incorporate both standards by reference into 49 CFR Part 192. That petition, along with a February 11, 2016 letter from INGAA, urged PHMSA to adopt API RP 1170 and 1171 as quickly as possible to put into place a set of consensus standards for operators of underground storage facilities to follow in assessing their facilities and establishing procedures to ensure safety. On May 9, 2016 in response to PHMSA questions about existing implementation of the API RPs, INGAA described the following actions regarding implementation of RP 1171 by natural gas storage facility operators (INGAA, 2016):18  Storage operators are actively conducting a gap analyses to assess their individual integrity management practices compared to the requirements of RP 1171. In the interim, operators will enhance their current programs as they work toward alignment with the RP. Examples of current integrity activities undertaken by operators are monitoring for the presence of annular gas and monitoring the injection and withdrawal flow rates and pressures at each storage reservoir.  Operator personnel visit a well site multiple times annually and observe the wellhead assembly and wellsite conditions each time. Pursuant to the RP, operators will conduct a standardized inspection and documentation of their findings. All active storage wells will be inspected within one year.  Existing surface and subsurface shut-off valves systems will be tested at least annually per the manufacturer’s recommendations and the operator’s procedures.  Operators will conduct a risk assessment and investigate enhancing their existing integrity management plans and procedures consistent with the requirements of the RP. INGAA estimated that this initial program development will be completed within 15 months.  Operators will evaluate the threats and hazards impacting storage wells and reservoirs utilizing Table 1 (Section 8) in RP 1171 as supplemented based on site-specific conditions. Operators will also assess the potential interaction of threats and hazards and perform periodic reevaluations of these threats and hazards in order to account for changes in the likelihood or consequence of the event potential. INGAA indicated that this task will be 50 percent complete within two years and 100 percent complete within three years.  Operators will develop and implement appropriate preventative and mitigative (P&M) measures utilizing Table 2 (Section 8) in RP 1171, as supplemented, to reduce the risk to storage facilities. This will include routine condition monitoring activities and training personnel in these procedures. Complete implementation of the P&M measures will be contingent upon the successful and timely completion of the prior step, evaluating threats and hazards. Completion of this step may take up to three years. 18 INGAA noted that a similar timeline for incorporating RP-1170 is under development and is expected to be fairly consistent with that for RP-1171. 4-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 4. Analysis Baseline  Monitoring for tubular corrosion and evaluating the impact on well integrity and operating pressure will be conducted using risk assessment. This will include an evaluation of tubular integrity and identification of defects caused by corrosion or other chemical or mechanical damage, corrosion potential of wellbore fluids and solids, annular and packer fluid corrosion potential, and corrosion potential of current flow associated with cathodic protection systems. INGAA indicated that this step will be completed for each active storage well within five years.  Operators will evaluate the mechanical integrity of every active storage well using the plans and procedures developed under the RP. Approximately 50 percent of the active wells will be evaluated within two years and the remainder will be completed within five years. INGAA expects some of the activities to run concurrently and others sequentially, and the time required to finish all of the activities will be approximately seven to eight years. PHMSA’s review of active storage facilities indicates that companies INGAA identified as members on its website operate over half of the facilities, 61 percent of working gas capacity, and 86 percent of the wells.19 Statements made by INGAA on behalf of its member companies suggest that a significant fraction of active storage facility operators have already started incorporating the RPs in their operations and would continue to do so even without a regulation. If so, the costs of the integrity testing and other measures contained in the RPs are part of the baseline for this action. In addition, several facility operators have made separate public statements regarding their program for maintaining integrity of their storage facilities. PHMSA is aware of commitments made publicly by Southern California Gas Company (SoCal), Public Service Company of Colorado, and Pacific Gas and Electric Company (PG&E) to test all their natural gas storage wells to verify their integrity (SoCalGas (2014); Xcel Energy (2015); PG&E (2016)). In reviewing company websites to determine the size of business entities for the Regulatory Flexibility Analysis (see Section 8.2), PHMSA also found descriptions of integrity assessment programs for Honeoye Storage and Puget Sound Energy’s Jackson Prairie Gas Storage that include elements similar to those in the API RPs.20 The costs incurred by these operators under these existing programs and commitments are also part of the baseline for this action and not attributable to the IFR. Exhibit 4-1 lists the companies and the number of fields and wells they operate. PHMSA did not conduct an exhaustive search of all facility operators to determine whether they had existing programs or had made explicit, public commitments to assess the integrity of their wells. 19 INGAA members are listed at http://www.ingaa.org/25/INGAAMembers.aspx (accessed June 10, 2016). PHMSA based its review on the parent owner of each operator as described in Section 8.2. 20 For example, the corporate website for Honeoye Storage describes the company’s program as follows (emphasis added): “Well Logging: To maintain and monitor the condition of gas well piping, we conduct an annual casing inspection logging program. The majority of the well is below the surface and cannot be visually inspected without the use of sophisticated measuring devices. Electronic tools are lowered to the bottom of the well bore, a distance that averages 2,800 feet below the ground surface, and a computerized record is generated that summarizes the condition of the well pipe from the bottom of the well to the ground surface. This requires HSC to contract with companies that operate specialized trucks equipped with masts, pressure controls, and instruments utilized to record the data obtained from the “down hole” tools.” (Honeoye Storage, 2015) Puget Sound Energy reported that it will comply with the latest PHMSA natural gas storage advisory bulletin (ABD-2016-02) dated 2/5/2016 and API RP-1171 (Puget Sound Energy, 2016) 4-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 4. Analysis Baseline Exhibit 4-1: Operators with Existing Commitments to Conducting Integrity Testing Company Name Number of Fields Number of Wells HONEOYE STORAGE CORPORATION 1 38 PACIFIC GAS AND ELECTRIC COMPANY 3 116 PUBLIC SERVICE COMPANY OF COLORADO 3 46 PUGET SOUND ENERGY 1 103 SOUTHERN CALIFORNIA GAS COMPANY 4 196 Total 12 499 Sources: SoCalGas (2014); P&&E (2016); Xcel Energy (2015); Honeoye Storage (2016); Puget Sound Energy (2016); Number of fields from EIA (2016e); Number of wells from AGA (2014). 4.1.3 Baseline Scenarios For this analysis, PHMSA evaluated the impacts of the regulation relative to three distinct baselines that differ in terms of the level of implementation with the RP measures in the absence of the regulation:  Full compliance: For this first scenario, PHMSA assumed that the entire industry would be implementing the RPs in the absence of this rule. The costs associated with the measures described in the RPs are therefore not attributable to the regulation. Incremental costs consist only of those (minimal) costs associated with notifications or reporting to PHMSA, as such reports would not be needed absent the regulatory requirement to provide information to the government.  Partial industry compliance: For this second scenario, PHMSA assumed that only those operators who are INGAA members or have stated publicly that they are implementing the RPs would implement the measures in the absence of this rule and that the regulation could therefore impose an incremental costs on all other operators of interstate facilities or of intrastate facilities in states without regulatory requirements. PHMSA considers this baseline to represent a lower bound level of implementation in the absence of the regulation, as suggested by the response from INGAA (2016) regarding current and planned activities, and the incremental costs therefore may overstate the impacts of the IFR.  Regulatory compliance only: For this last scenario, PHMSA assumed that only those operators of intrastate facilities subject to existing state regulations would implement safety measures contained in the RP. PHMSA judges this baseline as highly unlikely and the incremental costs represent an upper bound of the costs that are attributable to the IFR. For each of the baselines, DOT expects that all operators would comply with all nonmandatory provisions in the RPs in the absence of the IFR except as justified in accordance with § 192.12(a)(6). Given the potential that not all operators would implement the RPs or would do so within the timeframe PHMSA specified in the IFR, PHMSA evaluated the costs, economic impacts, and benefits of the IFR relative to the three baselines. The following sections detail this analysis. 4.2 Other Analysis Elements In addition to the baseline described above, the analysis of the costs and benefits of this IFR embeds other common elements discussed below. 4-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 4. Analysis Baseline 4.2.1 Timeframe for the Analysis The relevant timeframe for the analysis of the costs and benefits of the IFR is determined in part by the expected implementation schedule and the life (i.e., periodicity) of compliance technologies or procedures. Thus, PHMSA estimated the compliance costs accounting for when operators would be expected to conduct the integrity tests on their wells and the interval between successive tests. Similarly, PHMSA accounted for the benefits based on the timing of the compliance measures and the expected duration of the resulting benefits. As discussed in Section 5.1, PHMSA analyzed the costs and benefits of the IFR over a 20-year period starting in 2016 and ending in 2035. This period reflects assumptions for the primary analysis of a 10-year phase-in for completing mechanical integrity tests on all active wells and 10-year interval between successive mechanical integrity tests. PHMSA also analyzed an alternative scenario that assumes a shorter 5-year interval between integrity tests. PHMSA annualized the costs over the period of analysis using discount rates of 3 percent and 7 percent. 4.2.2 Regulatory Alternatives As discussed in Section 3.2, PHMSA considered and rejected one alternative to this IFR (promulgating more stringent testing requirements than provided in the API RPs). Because the alternative was not viable, PHMSA did not analyze its costs and benefits quantitatively. 4.2.3 Discounting of Future Costs and Benefits The analytic framework includes two basic temporal components, which are used consistently throughout the analysis of social benefits and social costs:  Use of constant prices. This analysis applies a year 2015 constant price level to all future costs and benefits.  Discount rate and year. This analysis estimates the annualized value of future costs and benefits using two discount rates: 3 percent and 7 percent. This is consistent with guidance provided by the Office of Management and Budget (OMB) in Circular A-4, which recommends that 3 percent be used when a regulation affects private consumption and 7 percent be used in evaluating a regulation that will mainly displace or alter the use of capital in the private sector (OMB, 2003). The same discount rates are used for both benefits and costs. All future cost and benefit values are discounted back to 2016. 4.2.4 Industry Growth Rate For this analysis, PHMSA assumed that the number of storage fields, active wells, and operators would remain the same during the period of analysis. PHMSA made this assumption due to the difficulty of projecting changes in the number of underground storage facilities and wells over time. Historical data show a 16 percent increase in underground storage capacity between 1995 and 2014 (EIA, 2016b). If this growth trend were to continue and additional wells were constructed and subject to mechanical integrity test, then assuming that the number of wells would remain constant would understate the costs of the IFR. 4-5 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs 5 Costs The most significant potential cost associated with the IFR consists of the cost of conducting mechanical integrity tests on the 16,991 wells in active natural gas storage fields.21 As discussed in Section 4.1.3, information provided to PHMSA by industry representatives suggests that storage facility operators already conduct mechanical integrity tests or will be conducting these tests in accordance with the industry’s commitment to promote implementation of the API RPs. If so, then there would be no incremental cost attributable to the IFR for these tests. PHMSA understands that API RPs are not regulations and thus there is no enforcement mechanism. As such, implementation may be incomplete in the absence of regulatory requirements, in which case the IFR would result in incremental costs and benefits, relative to the baseline. As discussed in Section 4.1.3, PHMSA evaluated baseline compliance scenarios that consider the incremental costs to operators not currently subject to equivalent state requirements (under the regulatory compliance only baseline) and also to operators not members of INGAA and without an integrity management program for testing wells in the baseline (under the partial compliance baseline). Other costs for the IFR are related to new PHMSA reporting requirements that go beyond the recordkeeping required to implement the API RPs. PHMSA reporting requirements represent incremental costs independent of the baseline level of API RP implementation, and as a result apply to both the partial and full compliance baseline scenarios. 5.1 Costing Methodology 5.1.1 Mechanical Integrity Testing Costs PHMSA expects that mechanical integrity testing costs will depend on the number of wells tested and the depth of the wells. Exhibit 5-1 shows PHMSA estimates of mechanical integrity testing costs, based on input from industry regarding the cost of setting up and running the mechanical integrity tests for wells of varying depths. The values in Exhibit 5-1 represent the costs of conducting a mechanical integrity test on an average individual well within a given depth range, including both equipment and labor. Actual costs may vary depending on the location, well characteristics and other factors. PHMSA assumes that logging costs include analysis of the results to determine any follow up actions, such as the recommended timing for the next inspection. Exhibit 5-1: Well Testing Costs by Depth Category (CD). Cost Item 0-3,500 ft 3,501-7,000 ft >7,000 ft Logging costs (noise, temp, bond, casing integrity, caliper, pressure test) $60,000 $90,000 $130,000 Workover rig costs $50,000 $100,000 $200,000 Total $110,000 $190,000 $330,000 Source: Estimate provided to PHMSA by an industry representative. 21 As discussed in Section 3.1, PHMSA assumes that operators already conduct other actions described in the API RPs as part of their existing safety procedures. 5-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs PHMSA confirmed that the costs in Exhibit 5-1 are reasonable by comparing them with estimates cited in other sources. For example, in a 2014 regulatory filing, SoCalGas provide cost estimates of $390,000 (in 2013 dollars) per well for a weeklong testing process, including pressure and corrosion tests (SoCalGas, 2014).22 The higher costs cited by SoCalGas are expected due to the higher price levels in California and the depth of wells needing to be tested; of the four active storage fields operated by SoCalGas, two are approximately 10,000 feet deep and the other two are nearly 7,000 feet deep. PHMSA seeks comment and any available data on these estimates of the costs of mechanical integrity testing for wells of various depths and in different areas of the country. The second factor influencing costs is the number of wells to be tested in any given location. Because some of the testing costs are associated with mobilizing personnel and equipment, PHMSA expects that operators with multiple wells in the same area will realize economies of scale relative to the unit costs for testing individual wells presented in Exhibit 5-1. Specifically, for this analysis, PHMSA assumed that operators may save 10 percent, relative to the unit costs, when conducting tests on more than 10 wells within the same field. PHMSA expects operators of fields with a large number of wells to inspect a portion of their wells each year, whereas operators of smaller fields may conduct all inspections in a single effort. For comparison, there are more than 10 wells at all 4 fields discussed by SoCalGas in the 2014 regulatory filing (104 at Aliso Canyon; 29 at Honor Rancho; 21 at La Goleta; and 42 at Playa del Rey). PHMSA calculated the testing cost for each active field CF by multiplying the number of wells by the cost corresponding to the field’s maximum depth to the formation, and applying a 10 percent reduction to those fields with more than 10 wells (Equation 1). 𝑪𝑭 = 𝑵𝑭 × 𝑪𝑫 × 𝑭𝑵 (Equation 1) where NF is the number of wells in field F CD is the cost per well for a formation depth D based on Exhibit 5-1 FN is an adjustment factor based on the number of wells N (FN = 1.0 if N  10; FN = 0.9 if N >10) PHMSA summed field-level costs over all fields operated by a given company to derive the operator- level costs summarized in Appendix B, and over all fields within a state or over the industry to calculate costs presented in this section. As discussed above, PHMSA zeroed-out the costs for operators who are listed as INGAA members or that have existing programs or for intrastate fields in states with existing requirements as these costs are already reflected in the baseline. 5.1.2 Costs of Addressing Integrity Issues Identified through Testing Integrity tests may reveal issues in the casing or other well components requiring repairs or other corrective actions. The API RPs describe the types of repairs that operators would need to perform to ensure the continued safe operation of the storage facility, including replacing the tubing, 22 SoCalGas had proposed conducting well logs for corrosion and pressure tests for integrity in their rate case (SoCalGas, 2014). This testing is similar to the testing requirements of this rule. 5-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs recementing, or plugging the well. These are corrective actions that would need to be performed at some point to continue safe operation, and the knowledge gained through the integrity test merely changes the timing of the repair which may avert more severe and costly repairs that would result from leaks or minor issues that escalated to more costly ones due to a lack of preventative maintenance. Further, the RPs give discretion to the operator on prioritizing repairs based on risk, so that operators are able to plan for, and schedule, those repairs based on the information gained from the inspections and tests rather than do repairs reactively when a leak occurs. However, operators may accelerate repairs of conditions they discover during the inspections as compared to when those repairs would have otherwise occurred. The savings from avoiding leaks and having the ability to schedule capital expenditures based on risk could offset cost implications from potentially having to conduct repairs sooner than currently done in the baseline. There is considerable uncertainty involved in predicting when repairs would have been discovered and addressed without the integrity test results and how this timing changes when implementing the RPs. PHMSA anticipates that there is a significant difference in costs of preventive maintenance as compared to measures that may need to be taken to control an ongoing release. In a 2014 rate case to the California Public Utilities Commission, SoCalGas described the advantage of a SIMP program including mechanical integrity testing of wells at Aliso Canyon as follows: “By establishing the additional and more robust SIMP inspections, and creating baseline assessments of well conditions, the severity and extent of reactive maintenance may be reduced in the future, and the time necessary to respond to indications of breaches in reservoir integrity and safety should be greatly improved.” (SoCalGas, 2014; p. 21) Xcel Energy made similar arguments in their request to the Colorado Public Utilities Commission to make changes to the existing maintenance program to include testing the integrity of the gas wells associated with Xcel’s storage fields, noting that “failure to maintain any component required to run the field can result in significant reliability concerns and potentially significant subsequent O&M costs.” (Excel Energy, 2015; p. 66). PHMSA requests comment on the size of savings from avoiding leaks and the ability to schedule capital expenditures based on risk, and the cost of repairs. 5.1.3 Costs of Other RP Elements While PHMSA expects the most significant costs resulting from implementation of the API RPs to be those related to mechanical integrity testing, operators may also incur costs to implement the other RPs elements summarized in Exhibits A-1 and A-2 (in Appendix A). For example, RP 1171 recommends that operators evaluate the threats and hazards affecting their storage wells and reservoirs, assess the risk, and use this information to prioritize management actions. According to RP 1171, the operators should update their assessment at a pre-defined frequency. The RP also recommends that operators monitor well and related facilities and average reservoir pressure versus inventory, to allow for the discovery and correction of any unexpected conditions. Records developed in accordance with the RPs must be maintained for the life of the facility. The RPs provide flexibility in how these other elements are implemented. PHMSA expects that operators already conduct assessment, monitoring, planning, and recordkeeping activities as part of normal business operations and may simply need to incorporate the existing procedures into their program. Accordingly, PHMSA estimated the incremental burden and costs of these other RP elements to be zero for this analysis. This assumption applies to all three baseline scenarios. There 5-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs may be operators that do not conduct assessment, monitoring, planning, and recordkeeping to the extent recommended in RP 1170 and 1171, and there will be additional costs for those operators as a result of this IFR. PHMSA requests comment on the extent to which any operators may need to supplement assessment, monitoring, planning, or recordkeeping in order to comply with this IFR. 5.1.4 Reporting Costs PHMSA estimated that all 124 operators with active natural gas storage facilities will need to submit an annual report to PHMSA and maintain records. In addition, a subset of operators may need to submit safety-related condition reports or incident reports to PHMSA on an as needed basis. Operators that do not currently report to PHMSA will need to register and request an operator identifier (OPID). Operators may also update their registration as needed to reflect certain changes such as changes in ownership. For this analysis, PHMSA estimated the incremental burden associated with registration and notification, recordkeeping, annual reports, safety related conditions reports, and incident reports. The preamble to the IFR describes the annual reporting and recordkeeping burden. PHMSA estimated the costs of recordkeeping and reporting requirements assuming that a compliance officer would perform the necessary activities. A review of existing operators shows that 100 of the total 124 operators of active underground storage facilities have other operations that already require submittal of information to PHMSA. PHMSA assumed that 24 operators may have to submit a new registration and that 25 operators may need to revise their registration each year. PHMSA estimated a burden of one hour each for registrations or notifications. All 124 operators will need to maintain records and submit an annual report. Because assessment, monitoring, planning, and recordkeeping activities are already conducted as part of normal business operations and may simply need to be modified and formalized to comply with the RPs, PHMSA estimated that the IFR will increase the recordkeeping burden by one hour per operator per year. PHMSA assumed that the annual report by natural gas storage facilities will require an average of 8 hours, including the time to review instructions, gather data, and complete and review the form. Because these operators are already subject to various reporting requirements to FERC, Public Utilities Commissions, and other authorities, and because the information requested by PHMSA should already be available, PHMSA expects that any additional set up costs for the first report will be minimal. PHMSA assumed that, on average, four operators (3 percent) may need to submit incident reports and the same number may need to submit safety-related condition reports annually, with respective burdens of 10 hours and 6 hours. The IFR will make measures described in the API RPs mandatory. Operators who deviate from the API RPs will need to include a justification in their program or procedural manuals as to why compliance with a provision of the recommended practice is not practicable and not necessary for the safety of a particular facility. This justification must be technically reviewed and documented by a subject matter expert to ensure there will be no adverse impact on design, construction, operations, maintenance, integrity, emergency preparedness and response, and overall safety and must be dated and approved by a senior executive officer, vice president or higher with responsibility of the 5-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs underground natural gas storage facility. PHMSA assumed that 12 operators (10 percent of operators) per year would incur incremental cost to compile and maintain records justifying API RP deviations, with each justification taking 8 hours to document. Exhibit 5-2 summarizes the estimated recordkeeping and reporting costs. Exhibit 5-2: Recordkeeping and Reporting Costs (2015$) Hours Total Annualized Annualized Reporting Activity of Filers umber per Cost per Cost (3% Cost (7% Report Report Costs? Discount Rate) Discount One-time registration Rate) 24 1 $61 $1,467 $96 $129 Notifications 25 1 $61 $1,528 $1,528 $1,528 Recordkeeping 124 1 $61 $7,578 $7,578 $7,578 Annual report 124 8 $489 $60,621 $60,621 $60,621 Safety-related conditions report 4 6 $367 Incident report $1,467 $1,467 $1,467 4 10 $611 $2,444 $2,444 $2,444 Recordkeeping for deviations 12 8 $489 $5,867 $5,867 $5,867 Total $79,600 $79,633 "Source: PHMSA professional judgment (see Table 3-96 in PHMSA, 2016a) 2 Assumes hourly rate of $61.11 based on wage for compliance officers from Bureau of Labor Statistics ($40.74/hour; see BLS (2016)) multiplied by 1.5. 3 Calculated as [number of filers] × [cost per report] ^ Cost per year calculated by annualizing the one-time registration costs over the 20-year analysis period using 3 percent and 7 percent discount rates. 5.2 Industry Compliance Costs 5.2.1 Full Industry Compliance Baseline Under the first baseline scenario where the industry is already in full compliance with the RPs, incremental costs attributable to the regulation for mechanical integrity testing and other procedures are zero. PHMSA estimated the costs associated with reporting requirements at approximately $79,600 per year (using a 7 percent discount rate), as detailed in Section 5.1.4 above. Exhibit 5-3: Annualized Compliance Costs Relative to the Full Industry Compliance Baseline Scenario (2015$) Cost Component 3% Discount Rate 7% Discount Rate Mechanical integrity testing $0 $0 Other RP elements $0 $0 Reporting' $79,600 See Exhibit 5-2 for details Total $79,600 $79,633 $79,633 5.2.2 Partial Industry Compliance Baseline To estimate incremental costs relative to the partial compliance baseline scenario, PHMSA first determined the number of wells incrementally tested. PHMSA adjusted the number of wells by subtracting (1) all wells at intrastate facilities in states with existing standards; (2) wells at facilities operated by operators with existing integrity testing commitments (see Section 4.1.2; and (3) wells at facilities operated by companies that are members of INGAA (see Section 4.1.2). Under these 5-5 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs assumptions, 2,408 wells will be subject to testing under the regulation (referred as "applicable wells" below), out of the total of 16,991 active wells in the United States. PHSMA multiplied the number of applicable wells at each field by the cost corresponding to the field depth to the formation summarized in Exhibit 5-1. Exhibit 5-4 shows the estimated compliance costs by state, before accounting for a phase-in of the tests (i.e., assuming immediate implementation). Appendix B presents estimated compliance costs by operator. Exhibit 5-4: Incremental Integrity Testing Costs Relative to the Partial Industry Compliance Baseline Scenario, by State. State Count of Applicable Wells' Incremental Integrity (Million 2015$) Testing Costs Total Annualized Integrit (Million 2015$/Year) Testing Costs Alaska 165 $16.5 $2.2 Alabama $0.0 $0.0 Arkansas $1.4 $0.2 California $0.0 $0.0 Colorado $1.9 $0.3 Indiana Illinois $0.0 $0.0 $0.0 $0.0 lowa $19.8 $2.6 Kansas $23.6 $3.1 Kentucky $0.0 $0.0 Louisiana Maryland $23.4 $3.1 $0.0 $0.0 Michigan $101.4 Minnesota $13.5 $6.5 $0.9 Mississippi $4.8 $0.6 Missouri $8.0 $1.1 Montana $27.1 $3.6 Nebraska New Mexico $0.0 $0.0 5 $1.7 $0.2 New York $9.6 $1.3 Ohio $6.9 $0.9 Oklahoma $5.1 $0.7 Oregon $4.5 $0.6 Pennsylvania 3 $0.6 $0.1 Texas $2.8 $0.4 Utah $0.0 $0.0 Virginia $000 $0.0 Washington $0.0 $0.0 West Virginia 21 $3.7 $0.5 Wyoming 22 $2.3 $0.3 Count of applicable wells excludes fields operated by companies that are members of INGAA, operators with existing integrity management programs, and intrastate fields in states with existing requirements. See Sections 4.1.1 and 4.1.2 for details. the assumed 10-year phase-in period. 2 Represents the total costs of conducting mechanical integrity tests, before accounting for the timing of the tests over 3 Costs annualized using a 7 percent discount rate over 10 years (assuming tests conducted every 10 years). 5-6 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs For the primary analysis, PHMSA assumed that each well will be tested every 10 years. The costs of implementing the integrity requirements in the RPs are approximately $30.9 million when annualized over 10 years using a 3 percent discount and $36.1 million when annualized using a 7 percent discount. PHMSA assumed immediate implementation of the requirements. However, as discussed in Section 4.2.1, PHMSA assumes that facility operators will test their active wells according to a schedule that reflects assessment of the relative risk across their operations. For the primary analysis, PHMSA assumed a 10-year phase-in period with the first 10" of the wells tested in Year 1, the second 10# in Year 2, etc. so that all wells will have been tested once by Year 10. This schedule means that wells tested in 2016 would be tested again in 2026, wells tested in 2017 would be tested again in 2027, and so on. As discussed in Section 3, API RPs do not specify an interval for testing and although ten years may be reasonable, some operators may need to test more or less frequently based on site-specific risk factors (e.g., age of the wells, operating pressures, casing conditions). To evaluate the effects of different testing intervals on annualized costs, PHMSA also conducted an alternative analysis assuming that operators would tests their well every five years. Exhibit 5-5 summarizes the annualized costs for 10-year testing interval and an alternative 5-year interval and assuming a 10-year phase-in period for implementing the mechanical integrity testing program. As shown below, the estimated annualized costs of the requirements to test wells every ten years are $27.2 million using 3 percent discount rate and $31.7 million using a 7 percent discount rate, when phasing-in the requirements over ten years and applying the partial industry compliance baseline (a 12 percent reduction as compared to immediate implementation). The estimated annualized costs of testing wells every five years are $50.6 million and $54.5 million, using 3 percent and 7 percent discount rates respectively (a 6 percent reduction). As noted previously, these costs are for the scenario of only partial industry compliance with mechanical integrity tests in the absence of federal regulatory requirements. Baseline Scenario (Million 2015$) Exhibit 5-5: Annualized Integrity Testing Costs Relative to the Partial Industry Compliance Phase-in Period Testing Interval 3% Discount Rate 7% Discount Rate Immediate Implementation 10 Years $30.9 $36.1 5 Years $57.6 $61.9 Phase-in over 10 Years 10 Years $27.2 $31.7 Reflects 10-year implementation phase-in of integrity tests over the period of 2016 through 2025 and costs 5 Years $54.4 annualized over 10 years or 5 years, depending on the scenario. Exhibit 5-6 summarizes total annualized compliance costs for this scenario, based on a 10-year phase-in and 10-year interval for mechanical integrity testing. Scenario (Million 2015$)1 Exhibit 5-6: Annualized Compliance Costs Relative to the Partial Industry Compliance Baseline Cost Component 3% Discount Rate 7% Discount Rate Mechanical integrity testing' $27.2 $31.7 Other RP elements $0 $0 5-7 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs Scenario (Million 2015$)' Exhibit 5-6: Annualized Compliance Costs Relative to the Partial Industry Compliance Baseline 3% Discount Rate 7% Discount Rate Based on 10-year phase-in of integrity tests and a 10-year interval between tests. See Exhibit 5-5 for details. 5.2.3 Regulatory Compliance Only Baseline PHMSA used a similar approach to estimate the incremental costs relative to the worst-case baseline scenario in which only operators of intrastate facilities located in states with existing regulations implement the RP measures. The only difference is the number of applicable wells. In this scenario, PHMSA subtracted from the total number of active wells only the wells at intrastate facilities in the nine states with existing standards (see Section 4.1.1). Under these assumptions, there would be 13,682 applicable wells, out of the total of 16,991 active wells in the United States. PHMSA used the same approach as for the partial industry compliance baseline to estimate the testing costs. Exhibit 5-7 shows the estimated compliance costs by state, before accounting for a phase-in of the tests (i.e., the costs in Exhibit 5-7 assume immediate implementation). Appendix B presents estimated compliance costs by operator. Exhibit 5-7: Incremental Integrity Testing Costs Relative to the Regulatory Compliance Only Baseline Scenario, by State. State Count of Applicable Wells' Incremental Integrity (Million 2015$) Testing Costs Total Annualized Integrity (Million 2015$/Year) Testing Costs Alaska 165 $16.5 $2.2 Alabama Arkansas 13 $0.0 $0.0 $1.4 $0.2 California Colorado $0.0 $0.0 254 $45.7 $6.1 Illinois 224 $22.2 $3.0 Indiana 160 $15.8 $2.1 lowa 432 $42.8 $5.7 Kansas 761 $93.7 $12.5 Kentucky 337 $33.4 $4.4 Louisiana 379 $85.6 $11.4 Maryland Michigan 2,152 84 $24.9 $3.3 $240.5 $32.0 Minnesota 66 $6.5 $0.9 Mississippi 132 $19.4 $2.6 Missouri 81 $8.0 $1.1 Montana 263 $27.1 $3.6 Nebraska 51 $8.7 $1.2 New Mexico 25 $5.1 $0.7 New York 952 $112.8 $15.0 Ohio 3,304 $406.6 $54.1 Oklahoma 329 $44.5 $5.9 Oregon 43 $4.5 $0.6 5-8 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs Exhibit 5-7: Incremental Integrity Testing Costs Relative to the Regulatory Compliance Only Baseline Scenario, by State. State Count of Applicable Wells' Incremental Integrity Testing Costs Total Annualized Integrity (Million 2015$) (Million 2015$/Year) Testing Costs Pennsylvania 1,670 $213.7 $28.4 Texas 115 $19.7 $2.6 Utah 63 $9.5 $1.3 Virginia 43 $7.4 $1.0 Washington 103 $10.2 $1.4 West Virginia 1,444 $175.6 $23.4 Wyoming 37 $3.8 $0.5 U.S. Total 13,682 $1,705.5 $226.9 Count of applicable wells excludes intrastate fields in states with existing requirements. See Sections 4.1.1 for " Represents the total costs of conducting mechanical integrity tests, before accounting for the timing of the tests over details. the assumed 10-year phase-in period 3 Costs annualized using a 7 percent discount rate over 10 years (assuming tests conducted every 10 years. For the primary analysis, PHMSA assumed that each well will be tested every 10 years. The costs of implementing the integrity requirements in the RPs are approximately $194.1 million when annualized over 10 years using a 3 percent discount and $226.9 million when annualized using a 7 percent discount. This is based on an assumed immediate implementation of the requirements. Exhibit 5-8 summarizes the annualized costs for 10-year testing interval and an alternative 5-year interval and assuming a 10-year phase-in period for implementing the mechanical integrity testing program. As shown below, the estimated annualized costs of the requirements to test wells every ten years are $170.6 million using 3 percent discount rate and $193.6 million using a 7 percent discount rate, when phasing-in the requirements over ten years. The estimated annualized costs of testing wells every five years are $319.7 million and $333.8 million, using 3 percent and 7 percent discount rates respectively. Baseline Scenario (Million 2015$)' Exhibit 5-8: Annualized Integrity Testing Costs Relative to the Regulatory Compliance Only Phase-in Period Testing Interval 3% Discount Rate 7% Discount Rate Immediate Implementation 10 Years $194.1 $226.9 5 Years $361.6 $388.7 Phase-in over 10 Years 10 Years $170.6 $193.6 5 Years $319.7 $333.8 Reflects 10-year implementation phase-in of integrity tests over the period of 2016 through 2025 and cost nnualized over 10 years or 5 years, depending on the scenari Exhibit 5-9 summarizes total annualized compliance costs for this scenario, based on a 10-year phase-in and 10-year interval for mechanical integrity testing. 5-9 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs Scenario (Million 2015$)' Exhibit 5-9: Annualized Compliance Costs Relative to the Regulatory Compliance Only Baseline Cost Component 3% Discount Rate Mechanical integrity testing' $170.6 7% Discount Rate $193.6 Other RP elements $0.0 $0.0 Reporting <$0.1 Total $170.6 <$0.1 $193.6 "Based on 10-year phase-in of integrity tests and a 10-year interval between tests. See Exhibit 5-5 for details. 5.3 Economic Impacts Mechanical integrity tests may represent a material share of storage facility operators' operation and maintenance (O&M) expenditures and revenue. For example, one of the ten operators listed in Exhibit 2-2, ANR Pipeline Company, reported in a FERC filing in 2015 revenue from storage activities specifically of $121.8 million. Based on the 14 fields and 932 active wells operated by ANR Pipeline Company, PHMSA estimated annualized testing costs of $14.9 million dollars,?3 or 12 percent of the reported revenue from these activities. As another example, PHMSA estimated annualized testing costs for SoCalGas' 196 wells at approximately $6.7 million. Although these costs are not attributable to the IFR given regulations proposed by the state of California and SoCalGas' commitment to conducting the tests, they nonetheless represent approximately a quarter of the total O&M costs the company reported in a 2014 regulatory filing requesting a rate adjustment to cover the additional expenditures on its integrity management program (SoCalGas, 2014). Under FERC regulation, operators of natural gas storage facilities may be able to pass through their compliance costs to their customers through increased rates for their storage services. Under cost-of- service ratemaking, rates are designed based on an operator's cost of providing service including an opportunity for the operator to earn a reasonable return on its investment. Based on natural gas storage throughput in 2015 of 3,639 BCF (amount of gas injected), the total incremental integrity testing costs under the partial industry compliance scenario of $31.7 million (10-year phase in and annualized over 10 years at 7 percent; see Exhibit 5-6) represent an increase of approximately $0.01 per thousand cubic feet. This is less than 0.1 percent of the average price paid by residential customers in the United States in 2015, assuming that all incremental storage costs are passed through to end-use customers. Such an increase would cost the average residential customer $0.66 per year, or $0.06 per month, based on an annual average residential consumption rate of 76 thousand cubic feet per year (EIA, 2016d).2 Under the assumption that only wells subject to state regulations are tested in the baseline, the incremental costs of the IFR ($193.6 million annually) translate into an increase of approximately $0.053 per thousand cubic feet, or $0.34 per month for an average residential customer. Increase in rates paid by other types of natural gas consumer can be expected to be similarly small. PHMSA notes that these figures may overstate impacts on average consumers, 23 Integrity testing costs are assumed to be $110,000 or $190,000 per well, based on the depth of the formation at each facility annualized over 10 years using a discount rate of 7 percent. operated by ANR Pipeline Company, and including economies of scale savings for fields with more than 10 wells. Costs are 24 PHMSA calculated the annual average consumption rate by dividing the total volume of natural gas delivered to residential customers in 2014 (5.1 BCF), by the number of customers (67.2 million) 5-10 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 5. Costs however, since incremental storage costs affect only a fraction of the total gas consumed.25 Expressed on the basis of total gas consumed in the United States in 2015 (27,474 BCF), the incremental costs under the partial compliance scenario amount to approximately $0.001 per thousand cubic feet, or less than $0.01 per month for the average residential customer. These costs are unlikely to have a significant impact on the natural gas transmission and storage industry, on the demand for natural gas, or on natural gas consumers. 25 According to EIA, operators injected 3,639 BCF of gas into underground storage in 2015. In that same year, total natural gas consumption was 27,474 BCF (EIA, 2016a; 2016d) 5-11 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 6. Benefits 6 Benefits PHMSA expects the benefits of the IFR in general, and of the mechanical integrity testing requirements in particular, to include the potential prevention of catastrophic natural gas releases due to the failure of storage wells– and associated impacts on human health, property, and the environment – or of fugitive and vented emissions ancillary to the operation of storage facilities. This section discusses these benefits qualitatively. 6.1 Natural Gas Releases from Underground Storage 6.1.1 Catastrophic Releases On October 23, 2015, SoCalGas’ Aliso Canyon Well SS25 developed a natural gas leak near an area known as Porter Ranch in Los Angeles, California. Although investigations have not yet been completed, the leak is believed to have originated from the subsurface (downhole) well casing. What is already known, however, is that integrity assessment and monitoring were inadequate. As documented by the Interagency Task Force on Natural Gas Storage Safety (2016), at Aliso Canyon, “logging of SS-25 was performed only as a means to detect the presence of leaks. Since 1979, there are no records of logs performed for the purpose of valuating the condition of the casing that could be used to assess the risk of a leak. For example, no logs were located that could indicate metal loss in the production casing, which is the primary barrier to the surrounding environment.” Over the 112-day event, the accident released approximately 5.7 BCF of natural gas into the atmosphere, containing up to 109,000 metric tons26 of methane, a potent greenhouse gas, as well as panoply of other pollutants (California Air Resources Board (CARB), 2016a; County of Los Angeles Public Health, 2016). Over 5,790 households had to be relocated due to the natural gas odorant (mercaptans), according to the Aliso Canyon Incident Command briefing report issued on February 1, 2016, although some sources place the number of related households at approximately 8,000. 27 Additional reports identify other potential health effects that lasted even after the well was sealed. A report by the Los Angeles County of Public Health suggests that the continued health symptoms may be due to contaminants in indoor air and dust (Los Angeles County Public Health, 2016). As of November 2, 2016, Sempra Energy, the parent company of SoCalGas, reported costs of $763 million to control the release, monitor air emissions, relocate residents, and cover its legal and other expenses (Sempra, 2016). 28 These costs are those incurred by Sempra and do not include additional costs to society as a result of the release. 26 CARB estimates that the incident resulted in a total emission of 99,650 ± 9,300 metric tons of methane (CARB, 2016a) and seeks mitigation of 109,000 metric tons. 27 For example, see KPCC news report on August 4, 2016, “Cost estimate of Aliso Canyon gas leak hits $717 million”. http://www.scpr.org/news/2016/08/04/63268/cost-estimate-of-aliso-canyon-gas-leak-hits-717-mi/ 28 Of the $763 million, Sempra Energy notes “approximately 70% is for the temporary relocation program (including cleaning costs and certain labor costs) and approximately 20% is for efforts to control the well, stop the leak, stop or reduce emissions, and the estimated cost of the root cause investigation. The remaining amount includes legal costs incurred to defend litigation, the value of lost gas, the costs to mitigate the actual natural gas released and other costs. Cost estimate excludes any potential damage awards, restitution and any civil, administrative or criminal fines and other penalties that may be imposed, as well as any 6-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 6. Benefits Several other catastrophic incidents involving natural gas underground storage facilities have occurred in the past 15 years (Hopper, 2004; British Geological Survey, 2008; Kansas Geological Survey, 2004):29  On August 19, 2004, the Market Hub Partners Moss Bluff storage facility located in Liberty County, Texas, had a well control incident and natural gas fire at Cavern #1. According to newspaper reports at the time, the incident sent a plume of burning gas “hundreds of feet into the air” (Bardwell and Horswell, 2004) and forced the evacuations of residents within a three-mile radius (OGJ, 2004). Over a period of 6.5 days, the incident released and burned approximately 6 BCF of gas. Estimates of the number of people evacuated vary between dozens and hundreds. Hopper (2004) estimated the value of the product lost at $36 million and property damage at $20 million. Investigators attributed the incident to initial separation and breach of a 8-5/8-inch well string inside the cavern.  A casing failure at the Magnolia Salt Cavern facility in December 2003 caused the release of approximately 0.35 BCF of natural gas, forced the shutdown of the facility and the evacuation of area residents (approximately 30 people). Geologists determined that the eruptions had sprung from an underground gas storage field seven miles away and migrated into injection wells. Investigator attributed the incident to casing failure, specifically to a crack in the casing of a well near the top of a cavern.  On January 17 and 18, 2001, the Yaggy underground natural gas storage field operated by Kansas Gas Service had a wellbore failure, which led to a series of gas explosions in Hutchinson, Kansas. The gas leaked from the storage field well production casing and migrated approximately nine miles underground to the Hutchinson, Kansas area. An explosion in downtown Hutchinson destroyed two businesses, damaged 26 others, and caused two fatalities. Approximately 250 people were evacuated. Approximately 143 million cubic feet of natural gas leaked from the storage field. Flares took over a month to burn off the escaped gas.30 Investigators attributed the incident to a hole in the well casing. Although PHMA could not find response costs for this incident, other costs incurred by the responsible party included payment of $1.7 million to the two businesses destroyed by the explosions, $5 million in court-awarded damages to residential plaintiffs for impacts on housing prices due to “stigma” effects of the release, and a $180,000 fine assessed by the Kansas Department of Health and Environment. Although infrequent, catastrophic natural gas release incidents can cause significant damages due to the quantities of natural gas involved, proximity to populations, and other factors. Note that in recent accidents, natural gas migrated underground for miles before erupting in locations distant from the source of the leak. The difficulty of identifying the actual dimensions of elevated risk zones argues in favor of making an additional effort to identify possible sources and prevent leaks in the first place. additional costs to clean homes and future legal costs necessary to defend litigation, among other potential costs, as we cannot estimate what amounts, if any, will be incurred for such matter.” (Sempra Energy, 2016). 29 There have also been additional accidents involving underground storage facilities storing other products such as liquefied petroleum gas (LPG). 30 Flares are commonly used as a means of disposing of waste gas, when it is safer to burn the gas than to simply vent it to the atmosphere. 6-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 6. Benefits The benefits of preventing accidental natural gas releases include avoided property damages, injuries and fatalities, resident relocation, adverse human health effects, and emissions of methane (CH4), the main constituent of natural gas and a potent greenhouse gas. 6.1.2 Operational Releases Operational releases of natural gas from storage facilities include fugitive emissions (70 percent) and vented natural gas (30 percent). Equipment leak is the principal source of fugitive emissions (U.S. EPA, 2008). The leaks may be caused by mechanical and thermal stresses in piping, valves, compressor seals, flanges, fittings, and other components. They may also arise due to improperly plugged and abandoned wells (and to a lesser extent from the geologic formation due to over- pressurizing). Venting is associated with various equipment or operations (e.g., compressor startup/shutdown), condensate storage tank vents, equipment depressurization. The annual Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHG Inventory) provides estimates of fugitive natural gas methane emissions from transmission and storage segments of the natural gas industry (EPA, 2016a; 2016b). In the GHG Inventory, wells at approximately 400 underground storage facilities released approximately 15.7 kt CH4 in 2014, or 114.5 standard cubic feet per day per well. 31 For comparison, total methane emissions from natural gas transmission and storage were 1,282 kt CH4 in 2014. A 2015 study of sources of methane emissions from transmission and storage by the Joint Institute for Strategic Energy Analysis (JISEA) highlighted approaches for reducing operational releases that include periodic leak detection and repairs and improvements in the construction and operation of the wells and reservoirs. The implementation of mechanical integrity tests and other measures contained in the API RPs referenced in the IFR represent steps in reducing these emissions. 6.2 Benefits of the IFR As described in Section 6.1, casing defects and failures caused the releases at the Magnolia Salt Cavern and Yaggy Field, and preliminary reports point to casing failure as the cause of the Aliso Canyon incident as well. Mechanical integrity tests and other measures mandated by the IFR are expected to reduce the likelihood of such well failures in the future by detecting conditions that precede the failures. PHMSA did not find data to estimate quantitatively the reduction in risk that will result from conducting mechanical integrity tests on storage wells but notes that the tests are used to establish existing conditions and to monitor development of corrosion or other conditions (e.g., mechanical defects or damages) that could lead to a release or other consequences. However, PHMSA requests any information from the public that could be used to estimate such risk reduction. Corrosion poses a serious threat to maintaining natural gas containment. Without proactive tests, serious integrity conditions may be discovered and addressed only after containment has already been compromised and the casing is leaking. SoCalGas (2014) noted an increase in the number of safety and integrity conditions discovered during well repair work, including casing or tubing leaks. Ultrasonic surveys SoCalGas conducted between 2008 and 2013 as part of well repair work revealed internal or external casing corrosion or mechanical damage in 15 wells (SoCalGas, 2014; p. PEB-9). 31 Storage well CH4 emissions from Table A-147 in U.S. EPA (2016b). 1 kt = 1 kilotonne = 1 Gg. 6-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 6. Benefits These are the types of conditions that led to the failures described in in Section 6.1 and which mechanical integrity tests are designed to detect. By requiring natural gas storage facility operators to implement measures to detect and address well integrity issues preventively, implementation of the IFR may help reduce overall storage operating costs, particularly when accounting for the much greater costs of reactive measures. In fact, SoCalGas explicitly mentions the greater cost of reactive measures taken after a leak has occurred as justification for its proposed storage integrity management program (SIMP), noting that “without the SIMP, SoCalGas will continue to operate in a reactive mode (with the potential for even higher costs to ratepayers) to address sudden failure of old equipment. In addition, SoCalGas and customers could experience major failures and service interruptions from potential hazards that currently remain undetected.” (SoCalGas, 2014) This greater cost is apparent when considering the response to the Aliso Canyon incident, which required drilling relief wells to intercept and seal the leaking well. SoCalGas reported capital costs for well control, leak stoppage and relief wells of $53.4 million through February 2016 (not counting other costs such as those associated with residents relocation, air emissions monitoring, public relations, etc.; SoCalGas, 2016b). SoCalGas ultimately succeeded in stopping the leak by plugging the failed well. Although a detailed breakdown and assessment of the costs of response actions is not available, the magnitude of these costs may be driven in part by the emergency conditions under which these actions had to be taken, as they are significantly higher than the capital costs for maintaining, replacing, and plugging wells under normal operating conditions. For example, in its O&M forecast to the California Public Utilities Commission, SoCalGas had estimated the cost of replacing well tubing at $575,000 per well, making repairs for leaking wellheads at $450,000 per well, drilling replacement wells at $5 million to $6 million per well, and plugging wells at $600,000 per well (in 2013 dollars; SoCalGas, 2014). Beyond lower operating costs, other benefits of preventing natural gas releases include those associated with avoided loss of product, property damage, injuries and fatalities, emissions of methane, adverse health effects, and others. Descriptions of the catastrophic incidents in Section 6.1.1 provide a tally of the costs incurred by natural gas operators (as reported in public records), but represent an incomplete accounting of the social costs of natural gas releases resulting from storage well failures. For example, missing from the tally are long-term damages resulting from the methane emissions. Methane is a potent greenhouse gas (GHG) with a climate forcing effect that is 28-36 times greater than that of carbon dioxide over a 100-year period (Intergovernmental Panel on Climate Change (IPCC), 2013). The Interagency Working Group on the Social Cost of Greenhouse Gases (IWGSCGG) estimated the global social costs of climate damages associated with an incremental ton of methane emissions by year for different discount rates (IWGSCGG, 2016). Using the values published by IWGSCGG (see Exhibit 6-1), PHMSA estimated the social costs of the climate-related impacts of the Aliso Canyon incident at $122.9 million dollars, based on the release of up to 109,000 6-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 6. Benefits metric tons of methane and the average SC-CH4 at a 3 percent discount rate. Social cost estimates range from $55.3 to $344.2 million, depending on the discount rate. Using the same approach, the climate change impacts from operational releases from fugitive and venting emissions (15,700 metric tons per year; see Section 6.1.2) are estimated at approximately $1.8 million as of 2015 at a 3 percent discount rate, with a range of $0.8 to $5.0 million. Exhibit 6-2 summarizes the value of estimated impacts of methane emissions at various discount rates. If an inspection allows an operator to correct and reduce fugitive emissions, then the benefits of the inspection would be realized for several years since these emissions are ongoing. Exhibit 6-1: Social Cost of Methane?? 20075 per Metric T8% CH. 2015$ per Metric Ton CHA Average percentile Average Average percentile 3% 95th $3,158 $3,609 $4,173 $4,737 $5,526 $6,203 $6,879 'Source: Values from Table 1 in IWGSCGG (2016). Social Cost of Methane (SC-CH4), 2010 - 2050 $7,556 2 PHMSA restated costs to 2015 dollars using the GDP deflator (GDP 2015/GDP 2007 = 1.1278) Exhibit 6-2: Climate Change-related Impacts of Methane Emissions from Natural Gas Storage Wells Release Source Basis Methane Value of Damages (Million 20155) (Metric Tons) Quantity 5% Average 3% Average 2.5% 3% 95'' Aliso Canyon incident One-time 109,000 $55.3 $122.9 Average percentile $172.1 $344.2 Fugitive emissions Annual 15,700 $0.8 $1.8 $2.5 $5.0 "Calculated as the quantity (in metric tons) times the SC-CH4 values for 2015 in Exhibit 6-1. In summary, to the degree that the IF promotes implementation of safer practices by making them mandatory and enforceable, then the FR has the potential to provide the benefits described in this section by acting on information obtainable through inspections to reduce the probability of catastrophic or operational natural gas releases or their magnitude 33 PHMSA seeks comment and data on how these expected benefits might be quantified. 32 discount rate, emissions occurring in 2015). Costs were restated from 2012 dollars to 2015 dollars using the GDP deflator Based on emissions of 109,000 metric tons of methane and a cost of $1,128 per metric ton (average SC-CH4 at a 3% ($1,100 × 1.04335) 33 If storage facility operators currently conduct mechanical integrity tests and implement other measures contained in the API reflected in the baseline and are not attributable to the IFR RPs or will do so without being compelled by regulations, then the associated prevention benefits (and the costs) are already 6-5 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 6. Benefits The IFR also provides hard-to-quantify benefits from increasing certainty by specifying mandatory minimum safety standards that all operators must meet. 6-6 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 7. Uncertainty and Limitations 7 Uncertainty and Limitations The sections below discuss main areas of uncertainty and limitations of the analysis. 7.1 Affected Facilities and Operators As discussed in Section 2, PHMSA identified a total of 390 active fields operated by 124 companies. PHMSA identified a total of 16,991 active wells at these fields. Data on the number of wells were obtained primarily from a survey published by AGA (2014) that reflects fields in operation in 2013/2014. The AGA report lists additional fields, however, that are not contained in the EIA data set. Conversely, the EIA data include fields not contained in the AGA report. Fields in Alaska were omitted entirely from the AGA report and PHMSA estimated the number of wells that may be present in those fields based on the ratio of the number of well and storage capacity in Lower-48 fields. The actual number of wells in Alaska may be higher or lower than that estimated by PHMSA. PHMSA did not estimate the number of wells in other fields reported in EIA but omitted from the AGA report (26 fields of the 390 total fields reported by EIA). Omission of these wells may understate costs. Overall, PHMSA expects the uncertainty on the exact number of fields and wells to have a small effect on the estimated costs since PHMSA estimates are generally close to those available from other sources, including industry estimates. Thus, as of June 1, 2016, AGA estimated at 397 the number of active fields in the Lower-48 states, as compared to PHMSA’s estimate of 385. AGA estimated at 16,900 the number of wells in those fields, as compared to PHMSA’s 16,826 (AGA, Personal Communication) 34, a difference of only about 0.4 percent. PHMSA used a static snapshot of storage fields and wells in estimating the incremental costs of the IFR. As discussed in Section 4.2.4, however, historical data show a 16 percent increase in underground storage capacity between 1995 and 2014 (EIA, 2016b). If this growth trend were to continue and additional wells were constructed and subject to mechanical integrity test, then assuming that the number of wells remains constant understates the costs of the IFR. PHMSA doesn’t have data on changes in the number of wells over time and notes that the existing relationship between gas working capacity and the number of wells is not linear. Nonetheless, if we assume that storage capacity will continue to increase at the same rate as the last two decades (16 percent over 20 years, or 0.75 percent per year) and further assume that the number of wells will increase in proportion to the storage capacity, then annualized testing costs may be $32.8 million as compared to $31.7 million for the static scenario (see Exhibit 5-5; 7 percent discount rate and 10-year phase-in and testing interval). Note that this alternate calculation overstates the cost of the IFR since it assumes that new wells will be inspected as they become active whereas operators may not test wells until years later according to their risk-based integrity management program. 34 Email from Cristina Sames of AGA to Alan Mayberry of PHMSA dated June 1, 2016. 7-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 7. Uncertainty and Limitations 7.2 Baseline Degree of Compliance PHMSA’s analysis of the costs and benefits of the RFI depends on assumptions about the actions storage facility operators will take to implement the API RPs. The most significant area of uncertainty is the degree to which operators of underground natural gas storage facilities would be implementing the API RPs in the absence of regulatory requirements. As discussed in Section 4.1.2, industry representatives stated the commitment by natural gas storage operators to implement the API RPs in full, described existing compliance with some elements of the RPs, and outlined the schedule for implementing the remaining substantive measures in the RPs. Specifically, input from INGAA (2016) describes that operators have already been implementing many of the practices contained in the API RPs and are already assessing their existing risk management plans and other measures to verify adherence to the API RPs. For example, INGAA notes that “operators have individually developed and maintained well and reservoir integrity management programs” but that the standards now provide a way for operators to “align their integrity programs and measure continual integrity management improvements.” INGAA provides other examples of current activities undertaken by operators, including monitoring for the presence of annular gas and monitoring the injection and withdrawal flow rates and pressures at each storage reservoir; annual or more frequent visits and observation of the well assembly and conditions; and annual testing of existing surface and subsurface shut-off valve systems per manufacturer’s recommendations and operator procedures (INGAA, 2016).INGAA members have started conducting the tests needed to meet the schedule outlined by INGAA which set out to evaluate 50 percent of their active wells within two years and the remainder within five years, and to complete all of the activities in approximately seven to eight years. INGAA member companies operate 86 percent of all active wells in the United States. Because of the uncertainty regarding the level of implementation of the API RPs in the absence of a rule, PHMSA conducted its analysis relative to three baselines (see Section 4.1.3): a baseline that assumes industry-wide implementation of the RP, an alternative baseline with implementation limited to certain operators or types of fields, and a worst-case baseline (from the perspective of IFR incremental costs) that assumes that only operators of intrastate facilities in states with regulatory requirements would implement the RP absent federal regulations. PHMSA expects actual baseline conditions to lie between full compliance, with annualized costs attributable to the IFR being less than $0.1 million, and partial compliance, with annualized costs of $31.7 million (7 percent discount rate and 10-year phase-in and testing interval). The benefits of the IFR also depend on the baseline level of implementation. If storage facility operators currently conduct mechanical integrity tests and implement other measures contained in the API RPs or will do so without being compelled by regulations, then the associated prevention benefits (see Section 6.2) are already reflected in the baseline and are not attributable to the IFR. 7.3 Mechanical Integrity Testing Costs The analysis uses average costs of conducting mechanical integrity tests on wells within three depth ranges. As discussed in Section 5.1.1, actual costs may vary depending on the location, well characteristics and other factors. For example, the inspection may run into unforeseen difficulties during test preparation or performance, which may increase the cost of conducting the tests. 7-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 7. Uncertainty and Limitations PHMSA assumed that testing costs include analysis of the results to determine follow up actions, such as the timing of subsequent inspections. PHMSA assumed that testing costs would be less in cases where a field has more than 10 wells. Removing this assumption increases the annualized testing costs to $34.9 million (7 percent discount rate and 10-year phase-in and testing interval) as compared to $31.7 million (Exhibit 5-4). PHMSA used the maximum depth of each field formation, based on data from AGA (2014). This assumption provides an upper bound for testing costs within a field. If wells are shallower than assumed by PHMSA, the IFR costs will be lower. For example, using the midpoint of the formation depth range as the basis for testing cost shows 18 active fields that correspond to a less expensive testing cost category and total annualized costs of $31.6 million, as compared to $31.7 million using the maximum formation depth (Exhibit 5-4). 7.4 Timing of Compliance Activities The analysis assumes that implementation will be phased-in over 10 years, but starting immediately (in 2016). This immediate start overstates costs slightly relative to implementation starting at a future date to be specified 12 months from the effective date of the rule. For the analysis, PHMSA assumed a uniform interval of 10 years (or alternative interval of 5 years) between successive integrity tests on a well. PHMSA analyzed the two intervals as illustrative of the potential programs operators may develop. In practice, however, the interval between successive tests will be determined based on a field-specific (and perhaps well-specific) assessment of the risk as described in the API RPs. If this risk-based interval is less than 5 years then the annualized costs would be greater than estimated by PHMSA for the most stringent alternative scenario analyzed. 7.5 Effectiveness of RPs to Prevent Future Incidents As discussed in Section 6.2, benefits of the IFR are difficult to quantify. Incidents involving the catastrophic release of natural gas from underground storage facilities are very infrequent. The contribution of integrity tests to preventing or reducing the impacts of a release is unknown. The risk of an accident may change over time as use of the fields increase and wells and other surface equipment age. 7-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 8. Other Analyses 8 Analyses Required under Applicable Statutes or Executive Orders PHMSA must conduct analyses of the costs, benefits, and economic impacts of the regulation to fulfill requirements of various statutes and Executive Orders. As discussed in Section 4.1.2, information received from industry representatives indicate that storage facility operators already implement the API RPs or have committed to do so even in the absence of the IFR. This section discusses the IFR in the context of each of the Statutory or Executive Orders requirements relative to the partial compliance and full compliance baseline scenarios. 8.1 Executive Orders 12866 and 13563: Analysis of Costs and Benefits Under Executive Order 12866 (58 FR 51735, October 4, 1993), PHMSA must determine whether the regulatory action is “significant” and therefore subject to review by the Office of Management and Budget (OMB) and other requirements of the Executive Order. The order defines a “significant regulatory action” as one that is likely to result in a regulation that may:  Have an annual effect on the economy of $100 million or more, or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or Tribal governments or communities; or  Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; or  Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or  Raise novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles set forth in the Executive Order. Executive Order 13563 (76 FR 3821, January 21, 2011) supplements Executive Order 12866 by outlining the President’s regulatory strategy to support continued economic growth and job creation, while protecting the safety, health and rights of all Americans. Executive Order 13563 requires considering costs, reducing burdens on businesses and consumers, expanding opportunities for public involvement, designing flexible approaches, ensuring that sound science forms the basis of decisions, and retrospectively reviewing existing regulations. Pursuant to the terms of Executive Order 12866, PHMSA determined that the regulation is not an “economically significant regulatory action” because, under the most reasonable baselines in which a significant fraction of the industry is already implementing the required provisions, it is unlikely to have an annual effect on the economy of $100 million or more. Although the annualized compliance costs relative to the regulatory compliance only baseline are greater than $100 million ($170.6 million at a 3 percent discount and $193.6 million at a 7 percent discount), PHMSA notes that information provided by the industry suggests that using this baseline would greatly overstate the impacts of the IFR. 8-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 8. Other Analyses Although PHMSA determined that the IFR is not economically significant, the Agency nonetheless submitted this action for review by the Office of Management and Budget (OMB) under Executive Orders 12866 and 13563. The docket for this action documents changes made in response to OMB suggestions or recommendations. 8.2 Regulatory Flexibility Act (RFA) The Regulatory Flexibility Act (RFA) of 1980, as amended by the Small Business Regulatory Enforcement Fairness Act (SBREFA) of 1996, requires Federal agencies to consider the impact of their rules on small entities, analyze alternatives that minimize those impacts, and make their analyses available for public comments. The Act is concerned with three types of small entities: small businesses, small nonprofits, and small government jurisdictions. The RFA describes the regulatory flexibility analyses and procedures that Federal agencies must complete unless they certify that the rule, if promulgated, would not have a significant economic impact on a substantial number of small entities. A statement of factual basis must support this certification, e.g., through addressing the number of small entities affected by the proposed action, calculating expected cost impacts on these entities, and evaluating economic impacts. PHMSA prepared a RFA screening analysis of this IFR, which is summarized below. Based on this analysis, PHMSA determined that the IFR will not have “a significant impact on a substantial number of small entities” (No SISNOSE). 8.2.1 Identifying Small Entities The RFA incorporates and uses the definition of "small business" found in the Small Business Act (5 U.S.C. section 601(3)). The Small Business Act authorizes the Small Business Administration (SBA) to define "small business" by issuing regulations. SBA periodically reviews and reissues these definitions. SBA (2016) has established size standards for various types of economic activities, or industries, under the North American Industry Classification System (NAICS). These size standards generally define small businesses based on the number of employees or annual receipts. For example, Exhibit 8-1 shows the SBA size standards for pipeline transportation (NAICS 486). Underground storage of natural gas is covered under NAICS 486210: Pipeline Transportation of Natural Gas. 35 Note that the SBA definition of a small business applies to a firm's parent company and all affiliates as a single entity. The business size is determined based on the primary economic sector of the parent company, which is not necessarily pipeline transportation of natural gas. 35 486 PIPELINE TRANSPORTATION: Industries in the Pipeline Transportation subsector use transmission pipelines to transport products, such as crude oil, natural gas, refined petroleum products, and slurry. Industries are identified based on the products transported (i.e., pipeline transportation of crude oil, natural gas, refined petroleum products, and other products). The Pipeline Transportation of Natural Gas industry includes the storage of natural gas because the storage is usually done by the pipeline establishment and because a pipeline is inherently a network in which all the nodes are interdependent. (U.S. Census, 2012) 8-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 8. Other Analyses Exhibit 8-1: Small Business Size Standards: Subsector 486 – Pipeline Transportation NAICS Code Description Standard 486110 Pipeline Transportation of Crude Oil 1,500 employees 486210 Pipeline Transportation of Natural Gas $27.5 million 486910 Pipeline Transportation of Refined Petroleum Products 1,500 employees 486990 All Other Pipeline Transportation $37.5 million Source: SBA (2016) NAICS = North American Industrial Classification System SBA = Small Business Administration The RFA defines "small governmental jurisdiction" as the government of a city, county, town, township, village, school district, or special district with a population of less than 50,000 (5 U.S.C. section 601(5)). For the purposes of the RFA, states and tribal governments are not considered small governments. The RFA defines "small organization" as any "not-for-profit enterprise which is independently owned and operated and is not dominant in its field". 36 PHMSA did not identify small organizations affected by the final rule. 8.2.2 Small Businesses Affected by the Final Rule To identify small businesses, PHMSA used operator data from EIA (2016e) and related the data to existing information available to PHMSA for natural gas pipeline operators that submitted 2014 Annual Reports. PHMSA had already combined the 2014 Annual Reports filers with data provided by Dun & Bradstreet (D&B) that included determination of small business classification.37 Note that the D&B classification may be based on a different primary industrial classification than pipeline transportation of natural gas in cases where the parent entity’s primary business is in another economic sector. PHMSA conducted selective additional review of other data sources to complement, confirm or update the D&B size classification. PHMSA determined the size category for 48 of the 124 operators of underground storage facilities for which PHMSA did not have a size determination from D&B. PHMSA determined the size for these operators based on data from other publically available sources (company websites, Security and Exchange Commission (SEC) filings, Manta.com, etc.). PHMSA also used data from these other sources to verify, and as needed update, the parent entity information and the size determination derived from D&B data. Thus, of the four small business entities identified by PHMSA, two businesses were identified based on revenue below the $27.5 million threshold defined by SBA for NAICS 486210 (Egyptian Gas 36 5 U.S.C. section 601(4) 37 The D&B data set corresponds to the operators who filed annual reports for the calendar year 2014 and which PHMSA analyzed in its Preliminary Regulatory Impact Assessment for the Notice of Proposed Rulemaking - Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines (PHMSA, 2016a). PHMSA compared this list to the 124 operators of active natural gas underground storage facilities identified by EIA. 8-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 8. Other Analyses Storage Corporation and Honeoye Storage Corporation), one had no revenue data38 and was assumed to be small (Cherokee Wells LLC), and the last entity was determined to be small based on population (City of Elizabethtown). Exhibit 8-2 summarizes the number of entities in each size category. Note that some operators are owned by the same domestic parent entity and therefore there are fewer than 124 unique parent entities represented in the data. Exhibit 8-2: Size of Natural Gas Underground Storage Operating Entities Affected by the IFR Size Category Number Small1 4 Large 120 Total 124 1. Based on information from Dun & Bradstreet, supplemented by PHMSA. 8.2.3 Impacts of the IFR on Small Entities PHMSA estimated that four small entities will have to comply with IFR requirements: three private entities and one small municipal government entity (City of Elizabethtown, KY). For this screening analysis, PHMSA looked at the impacts from both the partial compliance and full compliance baseline scenarios. As discussed in Section 5.2, under the scenario where storage facility operators already implement the API RPs in the baseline, the only compliance costs attributable to the IFR are those associated with reporting requirements. These costs, which are detailed in Section 5.1.4, are approximately $79,600 per year across all 124 operators (using a 7 percent discount rate). Under the alternative scenario wherein a small fraction of operators would not implement the API RPs without being compelled by the IFR, compliance costs attributable to the regulation also include the costs of conducting mechanical integrity tests, detailed in Section 5.1.1. If the analysis suggests minimal impacts under the second, partial industry compliance baseline scenario, then PHMSA may conclude no SISNOSE irrespective of uncertainty about the baseline level of compliance with API RPs by small entities. PHMSA used a sales test to estimate the economic impact of the compliance costs for small storage facility operators. This test consists of dividing total annual compliance costs by annual receipts. If this ratio is high for many small entities then the agency may not be able to certify that the rule will not have a significant economic impact on a substantial number of small entities. If a rule does have a Significant Impact on a Substantial Number of Small Entities (SISNOSE) then under the RFA, PHMSA would have to prepare a Final Regulatory Flexibility Analysis. PHMSA uses cost to revenue ratios of 1 percent and 3 percent of revenue. PHMSA then evaluated the absolute number and the percent of entities in each impact category, and by type of ownership. The Agency assumed that entities incurring costs below 1 percent of revenue are unlikely to face significant economic impacts, while entities with costs of at least 1 percent of revenue have a higher chance of facing significant 38 PHMSA could not find sales data for five operators from D&B or other publically available sources. For four of these operators, further research revealed a subsidiary relationship to a large company. PHMSA assumed that the remaining operator is small. 8-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 8. Other Analyses economic impacts, and entities incurring costs of at least 3 percent of revenue have a still higher probability of significant economic impacts. For revenue data, PHMSA primarily relied on firm level data obtained from D&B for 2015 and on data obtained from other sources for the most recent year available. PHMSA adjusted revenue to 2015 dollars. PHMSA calculated annual compliance costs per operator as described in Section 5. Exhibit 8-3 summarizes the results of the screening analysis. None of the small businesses affected by the regulation are expected to have costs exceeding 1 percent of sales under any of the three baseline scenarios PHMSA analyzed. This is because all four small businesses operate intrastate fields in states (Illinois, Kansas, and New York) that already have regulatory requirements in the baseline. Accordingly, incremental costs for these businesses arise only from the requirement to submit an Annual Report and incident or safety-related conditions reports as needed. The total costs, if all three types of report are needed in the same year, are approximately $1,500. Although entity revenue data are not available for two of the entities, PHMSA expects that the costs are de minimis relative to revenue for all four small businesses. These results support a determination that the IFR will not have “a significant impact on a substantial number of small entities” (No SISNOSE). Exhibit 8-3: Summary of Economic Impact Screening Analysis Partial Industry Compliance Baseline Category Full Industry Compliance Baseline Total small entities affected 4 4 Number (%) small entities for which compliance costs may exceed 1% of sales 0 (0%) 0 (0%) Number (%) small entities for which compliance costs may exceed 3% of sales 0 (0%) 0 (0%) 8.3 Unfunded Mandates Reform Act (UMRA) Analysis Title II of the Unfunded Mandates Reform Act (UMRA) of 1995, Pub. L. 104-4, requires that Federal agencies assess the effects of their regulatory actions on State, local, and Tribal governments and the private sector. Under UMRA section 202, PHMSA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that might result in expenditures by State, local, and Tribal governments, in the aggregate, or by the private sector, of $100 million (adjusted annually for inflation) or more in any one year (i.e., $151 million in 2015 dollars). Based on the cost estimates detailed in Section 5, PHMSA estimated the compliance costs to be below the threshold set in UMRA. 8.4 Executive Order 13132: Federalism Executive Order 13132 (64 FR 43255, August 10, 1999) requires PHMSA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” Policies that have federalism implications are defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.” 8-5 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 8. Other Analyses Under section 6 of Executive Order 13132, PHMSA may not issue a regulation that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments or unless PHMSA consults with State and local officials early in the process of developing the regulation. PHMSA also may not issue a regulation that has federalism implications and that preempts State law, unless the Agency consults with State and local officials early in the process of developing the regulation. PHMSA has concluded that this action will not have federalism implications, because it does not impose substantial direct compliance costs on State or local governments. PHMSA identified one local government entity (City of Elizabethtown) that operates an active field affected by the IFR but this intrastate field is located in a state with existing regulatory requirements (Kansas) and therefore incremental costs due to the IFR consist of only very small (non-substantial) reporting costs. 8.5 Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use Executive Order 13211 requires Agencies to prepare a Statement of Energy Effects when undertaking certain agency actions. Such Statements of Energy Effects shall describe the effects of certain regulatory actions on energy supply, distribution, or use, notably: (i) any adverse effects on energy supply, distribution, or use (including a shortfall in supply, price increases, and increased use of foreign supplies) should the proposal be implemented, and (ii) reasonable alternatives to the action with adverse energy effects and the expected effects of such alternatives on energy supply, distribution, and use. The OMB implementation memorandum for Executive Order 13211 outlines specific criteria for assessing whether a regulation constitutes a “significant energy action” and would have a “significant adverse effect on the supply, distribution or use of energy.” 39 Those criteria include: 1. Reductions in crude oil supply in excess of 10,000 barrels per day; 2. Reductions in fuel production in excess of 4,000 barrels per day; 3. Reductions in coal production in excess of 5 million tons per year; 4. Reductions in natural gas production in excess of 25 million mcf per year; 5. Reductions in electricity production in excess of 1 billion kilowatt-hours per year, or in excess of 500 megawatts of installed capacity; 6. Increases in the cost of energy production in excess of 1 percent; 7. Increases in the cost of energy distribution in excess of 1 percent; 8. Significant increases in dependence on foreign supplies of energy; or 9. Having other similar adverse outcomes, particularly unintended ones. Of the potential significant adverse effects on the supply, distribution, or use of energy (listed above), only the seventh is relevant to the IFR. Though the IFR could increase the cost of transporting natural 39 Executive Order 13211 was issued May 18, 2002. The Office of Management and Budget later released an Implementation Guidance memorandum on July 13, 2002. 8-6 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 8. Other Analyses gas, the cost increase is expected to less than the 1 percent threshold suggestive of potential impacts on energy supply, distribution, or use. As detailed in Section 5.2.3, the compliance costs under the partial compliance scenario amount to approximately $0.009 per thousand cubic feet, which is less than 0.1 percent of natural gas rates paid by residential consumers. For the worst-case regulatory compliance only baseline scenario, the incremental costs translate in approximately $0.053 per thousand cubic feet, which is approximately 0.4 percent of the residential rates. According to AGA (2015), the cost of the gas itself accounts for approximately 41 percent of the revenue received by a distribution company, meaning that the remaining 59 percent covers fixed and variable costs of transporting and distributing natural gas to consumers. Based on this share, PHMSA determined that the impacts on transportation and distribution costs are below the 1 percent threshold. This is true for all scenarios PHMSA analyzed. The compliance costs for the partial compliance scenario represent approximately 0.14 percent of transportation and distribution costs, whereas compliance costs for the worst-case regulatory compliance only baseline scenario represent 0.87 percent of transportation and distribution costs. 8.6 Paperwork Reduction Act of 1995 The Paperwork Reduction Act of 1995 (PRA) (superseding the PRA of 1980) is implemented by the Office of Management and Budget (OMB) and requires that agencies submit a supporting statement to OMB for any information collection that solicits the same data from more than nine parties. The PRA seeks to ensure that Federal agencies balance their need to collect information with the paperwork burden imposed on the public by the collection. The definition of “information collection” includes activities required by regulations, such as permit development, monitoring, record keeping, and reporting. The term “burden” refers to the “time, effort, or financial resources” the public expends to provide information to or for a Federal agency, or to otherwise fulfill statutory or regulatory requirements. PRA paperwork burden is measured in terms of annual time and financial resources the public devotes to meet one-time and recurring information requests (44 U.S.C. 3502(2); 5 C.F.R. 1320.3(b)). Information collection activities may include:  reviewing instructions;  using technology to collect, process, and disclose information;  adjusting existing practices to comply with requirements;  searching data sources;  completing and reviewing the response; and  transmitting or disclosing information. Agencies must provide information to OMB on the parties affected, the annual reporting burden, the annualized cost of responding to the information collection, and whether the request significantly impacts a substantial number of small entities. An agency may not conduct or sponsor, and a person is not required to respond to, an information collection unless it displays a currently valid OMB control number. 8-7 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 8. Other Analyses OMB has previously approved the information collection requirements contained in the existing pipeline safety regulations under the provisions of the Paperwork Reduction Act. The IFR modifies the information collection requirements for operators of natural gas storage facilities. PHMSA estimated changes in reporting and recordkeeping burden in Section 5.1.4 and is submitting a revised Information Collection Request (ICR) to OMB for approval. 8-8 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 9. References 9 References American Gas Association (AGA). 2014. Survey of Underground Storage of Natural Gas in the United States and Canada: 2013/2014. American Gas Association (AGA). 2015. Natural Gas Utility Rate Structure: The Customer Charge Component – 2015 Update. EA 2015-03. May 28, 2015. American Petroleum Institute (API). 201a. API Recommended Practice 1170: Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage. First Edition, July 2015. American Petroleum Institute (API). 201b. API Recommended Practice 1171: Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs. First Edition, September 2015. Bardwell, S.K. and C. Horswell. 2004. Valve Failure Sends Flames into Sky at Moss Bluff Storage Facility. Houston Chronicle. August 20. British Geological Survey. 2008. An appraisal of underground gas storage technologies and incidents, for the development of risk assessment methodology. Research Report RR605. Bureau of Labor Statistics (BLS). (2016). “May 2015 National Industry-Specific Occupational Employment and Wage Estimates: NAICS 211100.” Available at http://www.bls.gov/oes/current/naics4_211100.htm#11-0000; Accessed November 29, 2016. California Air Resources Board (CARB). 2016a. Determination of Total Methane Emissions from the Aliso Canyon Natural Gas Leak Incident. October 21, 2016.Available at https://www.arb.ca.gov/research/aliso_canyon/aliso_canyon_methane_emissions- arb_final.pdf. California Air Resources Board (CARB). 2016b. Aliso Canyon Methane Leak Climate Impacts Mitigation Program. March 31, 2016. California Department of Conservation. 2016a. Oil, Gas and Geothermal Idle Well Program. Web page. Available at http://www.conservation.ca.gov/dog/idle_well California Department of Conservation. 2016b. State Announces Comprehensive Natural Gas Storage and Inspection Mandates. Press Release. NR#2016-3. February 5, 2016. Available at http://www.conservation.ca.gov/index/Documents/2016-0 Emergency regulations for natural gas storage wells go into effect.pdf County of Los Angeles Public Health. Aliso Canyon Gas Leak Public Health Assessment: Environmental Conditions and Health Concerns in Proximity to Aliso Canyon Following Permanent Closure of Well SS-25. May 13, 2016. Energy Information Administration (EIA). 2015. The Basics of Underground Natural Gas Storage. November 16, 2015. Available at http://www.eia.gov/naturalgas/storage/basics/ (Accessed May 18, 2016) Energy Information Administration (EIA). 2016a. U.S. Underground Natural Gas Storage – All Operators, Released April 29, 2016. Available at http://www.eia.gov/dnav/ng/ng_stor_sum_dcu_nus_a.htm. 9-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 9. References Energy Information Administration (EIA). 2016b. Natural Gas Underground Storage Capacity (Summary), Released April 29, 2016. Available at http://www.eia.gov/dnav/ng/ng_stor_cap_a_epg0_sac_mmcf_a.htm. Energy Information Administration (EIA). 2016c. Number of Natural Gas Residential Consumers, Released April 29, 2016. Available at http://www.eia.gov/dnav/ng/ng_cons_num_a_epg0_vn3_count_a.htm. Energy Information Administration (EIA). 2016d. U.S. Natural Gas Consumption by End Use, Released April 29, 2016. Available at http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm. Energy Information Administration (EIA). 2016e. Natural Gas Annual Respondent Query System (EIA-191 Data through 2015), Release Date March 2016. Available at http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP7 Energy Information Administration (EIA). 2016f. Trends in U.S. Oil and Natural Gas Upstream Costs. March 2016. Available at https://www.eia.gov/analysis/studies/drilling/pdf/upstream.pdf. Federal Energy Regulatory Commission (FERC). 2016. Jurisdictional Storage Fields in the United States. Available at https://www.ferc.gov/industries/gas/indus-act/storage/sortable.xlsx; accessed March 28, 2016. Honeoye Storage Corporation. 2015. Honeoye Storage Corporation 2015 Newsletter. Available at http://www.honeoyestoragecorp.com/newsletter.htm; Accessed June 3, 2016 Hopper, J.M. 2004. Gas Storage and Single-point Failure. Natural Gas. Interagency Working Group on the Social Cost of Greenhouse Gases (IWGSCGG). 2016. Addendum to Technical Support Document on Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866: Application of the Methodology to Estimate the Social Cost of Methane and the Cost of Nitrous Oxide. August 2016. Available at https://www.whitehouse.gov/sites/default/files/omb/inforeg/august_2016_sc_ch4_sc_n2o_ad dendum_final_8_26_16.pdf Intergovernmental Panel on Climate Change (IPCC). 2013 Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. [Stocker, T.F., D. Qin, G.-K., Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 1535 pp. Interagency Task Force on Natural Gas Storage Safety. 2016. Ensuring Safe and Reliable Underground Natural Gas Storage. October 2016. Available at http://energy.gov/sites/prod/files/2016/10/f33/Ensuring Safe and Reliable Underground Natural Gas Storage – Final Report.pdf; Accessed November 23, 2016. Interstate Natural Gas Association of America (INGAA). 2016. Response to PHMSA Questions. Personal Communication from Terry D. Boss (INGAA) to John Gale (PHMSA). May 9, 2016. 9-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 9. References Joint Institute for Strategic Energy Analysis (JISEA). 2015. Estimating U.S. Methane Emissions from the Natural Gas Supply Chain: Approaches, Uncertainties, Current Estimates, and Future Studies. Technical Report NREL/TP-6A50-62820. August 2015 Joyce S. and J. Wirfs-Brock. The Rising Cost of Cleaning up After Oil and Gas. Inside Energy. October 1, 2015. Available at http://insideenergy.org/2015/10/01/the-rising-cost-of-cleaning- up-after-oil-and-gas/ Kansas Geological Survey. 2004. Natural Gas Explosions in Hutchison, Kansas: Geologic Factors. August 20, 2004. Available at http://www.kgs.ku.edu/Hydro/Hutch/GSA_Watney_updated082004.pdf OGJ. 2004. Second Moss Bluff Explosion Accesses 6 BCF of Gas in Cavern, Feeds Larger Fire. August 20, 2004. Pacific Gas and Electric Company (PG&E). 2016. PG&E Safely Operates its Natural Gas Storage Facilities. Currents. February 5, 2016. Available at http://www.pgecurrents.com/2016/02/05/pge-safely-operates-its-natural-gas-storage- facilities/. Accessed May 15, 2016. Pipeline and Hazardous Safety Administration (PHMSA). 2016a. Preliminary Regulatory Impact Assessment. Notice of Proposed Rulemaking - Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines. March 2016 Pipeline and Hazardous Safety Administration (PHMSA). 2016b. Unit Component Gas Storage Fields Report. Data as of April 5, 2016. Puget Sound Energy. 2016. Jackson Prairie Gas Storage. Presentation to Washington State Utilities & Transportation Commission Citizens Committee on Pipeline Safety. March 22, 2016. Available at http://www.utc.wa.gov/publicSafety/Documents/PSE%20Presentation%20on%20Jackson%2 0Prairie%20Operation.pdf. Accessed June 10, 2016. U.S. Census. 2012. Industry Statistics Portal. 2012 NAICS: 486 – Pipeline Transportation. Available at https://www.census.gov/econ/isp/sampler.php?naicscode=486&naicslevel=3#. Accessed June 1, 2016. U.S. Environmental Protection Agency (U.S. EPA). 2008. Methane to Markets: Reducing Methane Emissions from Underground Natural Gas Storage Operations. Gazprom – EPA Technical Seminar on Methane Emission Mitigation. 28 – 30 October, 2008 U.S. Environmental Protection Agency (U.S. EPA). 2014a. Inventory of U.S. GHG Emissions and Sinks: 1990-2012. EPA 430-R-14-003. Washington, D.C. U.S. Environmental Protection Agency (U.S. EPA). 2014b. 2011-2012-2013 GHGRP Industrial Profiles: Petroleum and Natural Gas Systems. Washington, D.C. U.S. Environmental Protection Agency (U.S. EPA). 2015. Regulatory Impact Analysis of the Proposed Emission Standards for New and Modified Sources in the Oil and Natural Gas Sector. EPA-452/R-15-002, August 2015. 9-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage 9. References U.S. Environmental Protection Agency (U.S. EPA). 2016a. U.S. Greenhouse Gas Inventory Report: 1990-2014. U.S. Environmental Protection Agency (U.S. EPA). 2016b. Annex 3: Methodological Descriptions for Additional Source or Sink Categories. Section 3.1: Methodology for Estimating Emissions of CH4, N2O, and Indirect Greenhouse Gases from Stationary Combustion. Available at https://www.epa.gov/sites/production/files/2016-04/documents/us-ghg- inventory-2016-annex-3-additional-source-or-sink-categories-part-a.pdf; Accessed November 23, 2016. U.S. Office of Management and Budget (OMB). 2003. Circular A-4. September 17, 2003. Available at https://www.whitehouse.gov/sites/default/files/omb/assets/regulatory_matters_pdf/a-4.pdf U.S. Office of Management and Budget (OMB). Not dated. Regulatory Impact Analysis: A Primer. Available at https://www.whitehouse.gov/sites/default/files/omb/inforeg/regpol/circular-a- 4_regulatory-impact-analysis-a-primer.pdf Sempra Energy. 2016. Third Quarter 2016 Earnings Results. Presentation. November 2, 2016. Available at http://files.shareholder.com/downloads/SRE/3288685950x0x915033/F78630C4- 7E59-423E-955D-D21499D8AB52/Q3-16_Presentation.pdf; Accessed November 23, 2016 Small Business Administration (SBA). 2016. Table of Small Business Size Standards Matched to North American Industry Classification System Codes. Effective February 26, 2016. Available at https://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf. Southern California Gas Company (SoCalGas). 2014. Direct Testimony of Phillip E. Baker before the Public Utilities Commission of the State of California. November 2014. Southern California Gas Company (SoCalGas). 2016a. Supplemental Updated Response. June 15, 2016. Southern California Gas Company (SoCalGas). 2016b. Well SS25 & Relief Wells. Preliminary and non-GAAP as of February 29, 2016. Texas Railroad Commission. 2016. Plugging Cost Estimates: FY 2015. Updated March 10, 2016. Available at http://www.rrc.state.tx.us/oil-gas/compliance-enforcement/hb2259hb3134- inactive-well-requirements/cost-calculation/ Xcel Energy Services Inc. (Xcel Energy). 2015. Direct Testimony and Attachments of Kimberly S. Locker on Behalf of Public Service Company of Coloraro. March 3, 2015. Zimmerle, Daniel J., Laurie L. Williams, Timothy L. Vaughn, Casey Quinn, R. Subramanian, Gerald P. Duggan, Bryan Willson, Jean D. Opsomer, Anthony J. Marchese, David M. Martinez, and Allen L. Robinson. 2015. Methane Emissions from the Natural Gas Transmission and Storage System in the United States. Environ. Sci. Technol. 2015, 49, 9374−9383. 9-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix A. Summary of API RPs Appendix A – Summary of API Recommended Practices The tables below summarize the scope of API RP 1170 and API RP 1171 and provide examples of measures and associated operator actions. Note that this is a condensed summary of the RP and the reader should refer to the respective documents for details on the measures. 1 Exhibit A-1: Summary of RP 1170 Measures with Associated Operator Actions. Title: Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage Scope overview: This recommended practice (RP) provides the functional recommendations for salt cavern facilities used for natural gas storage service and covers facility geomechanical assessments, cavern well design and drilling, solution mining techniques and operations, including monitoring and maintenance practices. This RP includes the cavern well system (wellhead, wellbore, and cavern) from the emergency shutdown (ESD) valve down to the cavern and facilities having significant impact to safety and integrity of the cavern system. RP Section Scope or Facility Components Selected Measures and Operator Actions 5. Geological and Geomechanical Evaluation  Site selection criteria  Geologic site characterization  Geomechanical site characterization  Assessment of cavern stability and geomechanical performance  Select and assess the site to ensure that the salt deposit is suitable for cavern development. RP describes steps in the assessment process and tests that should be done to verify site suitability. 6. Well Design  Hole section design  Casing design (conductor casing, surface casing, intermediate casing, production casing)  Wellhead design  Design the storage well system to ensure confinement of the stored gas to the cavern system. The RP describes design considerations and the design, operational, and maintenance procedures that should be included to ensure integrity 7. Drilling  Rig and equipment  BOP system  Drilling guidelines  Logging  Cementing  Completion  Select drilling equipment and logging procedures to achieve the desired well design and ensure safety. The RP describes the type of equipment needed and selection considerations 8. Cavern Solution Mining  Cavern solution mining design  Cavern development phases  Equipment  Instrumentation, control, and shut down  Workover during solution mining  Workover to configure for gas storage service  Debrining the cavern  Existing cavern conversions  Cavern rewatering  Cavern enlargement  Design and develop the cavern to store gas. The RP discusses the design considerations, equipment and instrumentations needed, monitoring during development phase, and workover procedures. A-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix A. Summary of API RPs 1 Exhibit A-1: Summary of RP 1170 Measures with Associated Operator Actions. Title: Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage Scope overview: This recommended practice (RP) provides the functional recommendations for salt cavern facilities used for natural gas storage service and covers facility geomechanical assessments, cavern well design and drilling, solution mining techniques and operations, including monitoring and maintenance practices. This RP includes the cavern well system (wellhead, wellbore, and cavern) from the emergency shutdown (ESD) valve down to the cavern and facilities having significant impact to safety and integrity of the cavern system. RP Section Scope or Facility Components Selected Measures and Operator Actions 9. Gas Storage Operations  Minimum and maximum operating limits  Equipment  Instrumentation, control, and shut down  Inspection and testing  Workovers  Site security and safety  Operating administration  Equip and monitor the cavern to ensure safe operation and detect upset conditions, including by installing SCADA systems, alarms, ESD system, overpressure protection system, and fire and gas detection.  Test and calibrate equipment and safety devices at least annually.  Have O&M procedures to allow the safe operation and necessary maintenance of the wellhead and cavern to ensure integrity. The RP lists some of the procedures that should be in place.  Maintain records of system development and O&M at least until the facility is decommissioned. 10. Cavern Integrity Monitoring  Integrity monitoring program  Monitor the cavern to ensure functional integrity. The RP describes various integrity monitoring methods applicable to the cavern system, wellbore, cavern, and wellhead 11. Cavern Abandonment  Abandonment design  Removal of stored gas  Wellbore integrity test  Removal of downhole equipment  Production casing inspection  Sonar survey  Long-term monitoring   Stabilize the cavern and maintain hydraulic integrity 1 This table provides only a summary of selected measures. Refer to the full text of the API RP for details on the measures. 1 Exhibit A-2: Summary of RP 1171 Measures with Associated Operator Actions. Title: Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs Scope Overview: This recommended practice (RP) applies to natural gas storage in depleted oil and gas reservoirs and aquifer reservoirs, and focuses on storage well, reservoir, and fluid management for functional integrity in design, construction, operation, monitoring, maintenance, and documentation practices. This RP applies to both existing and newly constructed facilities. However, Sections 5 and 7 apply exclusively to new facilities and facilities undergoing expansion, and Section 6 applies to new well construction and remediation of a new or existing well. RP Section Scope or Facility Components Selected Measures and Operator Actions 5. Functional Integrity in Design of Reservoir  Geological reservoir characterization  Engineering reservoir characterization  Containment assurance of reservoir design  Environmental, safety, and health considerations in design  Assess and design new natural gas storage capacity development in hydrocarbon production reservoirs and aquifer reservoirs, and increased maximum pressure and/or total capacity in existing natural gas storage reservoirs. RP provides guidance on considerations and steps.  Maintain accurate and comprehensive records of natural gas storage design activities for the life of the facility. RP lists records needing to be maintained as applicable and available. A-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix A. Summary of API RPs 1 Exhibit A-2: Summary of RP 1171 Measures with Associated Operator Actions. Title: Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs Scope Overview: This recommended practice (RP) applies to natural gas storage in depleted oil and gas reservoirs and aquifer reservoirs, and focuses on storage well, reservoir, and fluid management for functional integrity in design, construction, operation, monitoring, maintenance, and documentation practices. This RP applies to both existing and newly constructed facilities. However, Sections 5 and 7 apply exclusively to new facilities and facilities undergoing expansion, and Section 6 applies to new well construction and remediation of a new or existing well. RP Section Scope or Facility Components Selected Measures and Operator Actions 6. Functional Integrity in Design of Storage Wells  Wellhead equipment and valves  Well casing  Casing cementing practices  Completion and stimulation  Well remediation  Well closure (plugging and Abandonment)  Environmental, safety and health  Testing and commissioning  Monitoring of construction activities  Ensure functional integrity in the design, construction, and completion of new natural gas storage wells, the remediation and reconditioning of existing wells, and abandonment of wells within a natural gas storage facility. RP provides consideration and measures to provide this assurance 7. Functional Integrity of the Natural Gas Storage Reservoir and Wells Established and Demonstrated Through Initial Attainment of Maximum Reservoir Pressure and Total Inventory  Testing and commissioning  Reservoir integrity monitoring  Mechanical integrity monitoring  Verify functional integrity of the natural gas storage reservoir and wells during reservoir development and during commissioning until reaching the designed maximum reservoir pressure and/or total capacity.  Establish and document baseline conditions.  Monitor material balance behavior of the storage reservoir. RP provides monitoring and analysis methods such as reservoir pressure monitoring, use of observation wells, gas identification logs.  Monitor wells and related facilities. RP describes measures for wellheads, well safety systems, piping, and site locations, wellhead injection pressure and flow rate, observation well pressures and fluid levels, and well annulus pressures or vents.  Maintain records of natural gas storage testing and monitoring activities conducted during commissioning for the life of the facility. RP lists records needing to be maintained as applicable and available. 8. Risk management for gas storage operations  Risk management  Data collection and integration  Threat and hazard identification and analysis  Risk assessment  Preventative and mitigative measures  Periodic review and assessment  Develop, implement, and document a program to manage risk. Measures include: data collection, identification of potential threats and hazards to the storage operation, risk analysis including estimation of the likelihood of occurrence of events related to each threat, the likelihood of occurrence and potential severity of the consequences of such events, and the preventive, mitigative, and monitoring processes to reduce the likelihood of occurrence and/or the likelihood and severity of consequences, and a periodic review and reassessment of the processes. A-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix A. Summary of API RPs 1 Exhibit A-2: Summary of RP 1171 Measures with Associated Operator Actions. Title: Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs Scope Overview: This recommended practice (RP) applies to natural gas storage in depleted oil and gas reservoirs and aquifer reservoirs, and focuses on storage well, reservoir, and fluid management for functional integrity in design, construction, operation, monitoring, maintenance, and documentation practices. This RP applies to both existing and newly constructed facilities. However, Sections 5 and 7 apply exclusively to new facilities and facilities undergoing expansion, and Section 6 applies to new well construction and remediation of a new or existing well. RP Section Scope or Facility Components Selected Measures and Operator Actions 9. Integrity Demonstration, Verification, and Monitoring Practices  Well integrity identification and analysis  Risk assessment  Preventative and mitigative measures  Periodic review and assessment  Evaluate the mechanical integrity of each active well that penetrates the storage reservoir and buffer zone or areas influenced by storage operations.  RP discusses measures including review of design, completion, and well work records, wellhead and downhole inspection, well pressure monitoring and testing, and gas sampling.  Monitor well integrity. RP provides expected frequencies for some inspections and tests.  Document inspections, tests and patrols and maintain records for the life of the facility. 10. Site Security and Safety, Site Inspections, and Emergency Preparedness and Response  Site security and safety  Ingress and egress  Signage  Site inspections  Emergency preparedness/emergency response  Assess and monitor site security and emergency preparedness  Develop and implement an emergency preparedness/response plan and provide training to applicable staff. RP lists element of the Plan and training scope and activities.  Have in place a blowout contingency plan 11. Procedures and Training  Procedures  Develop, implement, and maintain programs, plans, and procedures for O&M, emergency plans, well work, other well entry and well operation, interaction with control room, integrity and risk management, safety and environmental programs, public awareness and damage prevention, management of change, and training. 1 This table provides only a summary of selected measures. Refer to the full text of the API RP for details on the measures. A-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix B. Operator-level Costs Appendix B - Operator-level Costs Exhibit B-1: Estimated Mechanical Integrity Testing Costs per Operator under Partial Compliance Baseline Scenario Operator Name Number Number of Number Total Costs Annualized Total Fields of Wells' of Wells Tested (Thousand, 2015$3 Costs (7%; 2015$/Year)3,4 Thousand AMEREN ILLINOIS 14 12 409 $0 $0 ANR PIPELINE COMPANY 932 $0 $0 ARCADIA GAS STORAGE LLC 1 6 6 $88 ARLINGTON GAS STORAGE COMPANY LLC 3 23 23 ATMOS ENERGY CORPORATION 12 154 $0 $0 ATMOS PIPELINE TEXAS 5 56 $O $0 BAY GAS STORAGE COMPANY LTD $0 BEAR CREEK STORAGE COMPANY $0 $0 $0 BLUE LAKE STORAGE COMPANY 14 $0 $O BLUEWATER GAS STORAGE LLC $O $0 BOARDWALK LOUISIANA MIDSTREAM LLC $O $O BOBCAT GAS STORAGE $0 BRIDGELINE HOLDINGS LP $380 CADEVILLE GAS STORAGE CALEDONIA ENERGY PARTNERS LLC $1,900 $0 $ CENTANA INTERSTATE PIPELINE LLC $760 $1 101 CENTERPOINT ENERGY 33 ,534 $8 6 CENTRAL NEW YORK OIL AND GAS COMPANY 33 $75 CENTRAL VALLEY GAS STORAGE LLC 1 CENTURY ALUMINUM SEBREE CHEROKEE WELLS LLC 37 CHEVRON KEYSTONE GAS STORAGE, LLC 5 CHEVRON PHILLIPS CHEMICAL CO LP 1 CITIZENS ENERGY GROUP 2 CITY OF ELIZABETHTOWN NATURAL GAS $0 93 $0 CLEAR CREEK STORAGE COMPANY LLC $O COLORADO INTERSTATE GAS COMPANY COLUMBIA GAS OF PA INC COLUMBIA GAS TRANSMISSION LLC 32 3,362 $0 $0 CONSUMERS ENERGY COMPANY 14 981 COOK INLET NATURAL GAS STORAGE 35 35 CRANBERRY PIPELINE CORPORATION DELTA NATURAL GAS COMPANY INC 1 4 11 $0 DOMINION EAST OHIO 780 DOMINION TRANSMISSION INC 15 1431 DOW PL CO 1 EAST CHEYENNE GAS STORAGE LLC 1 $0 EATON RAPIDS GAS STORAGE SYSTEM 14 $0 EGYPTIAN GAS STORAGE CORPORATION EL PASO NATURAL GAS COMPANY 20 ENABLE GAS TRANSMISSION LLC 71 B-1 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix B. Operator-level Costs Exhibit B-1: Estimated Mechanical Integrity Testing Costs per Operator under Partial Compliance Baseline Scenario Operator Name Number Number of Number Total Costs Annualized Total Fields of Wells' of Wells Tested (Thousand, 2015$) Costs (7%; 2015$/Year 3,4 Thousand ENABLE MIDSTREAM PARTNERSENOGEX 2 $0 $0 ENABLE MISSISSIPPI RIVER TRANSM CORP 3 91 $0 $0 ENERGY TRANSFER FUEL LP 2 29 $0 $0 ENLINK MIDSTREAM SERVICES LLC 1 $0 $0 ENSTOR GRAMA RIDGE STORAGE TRANSP 1 5 5 $1,650 ENSTOR KATY STORAGE TRANSPLP 1 12 $0 $0 ENTERPRISE TEXAS PIPELINE 1 $0 $0 EQUITRANS L P 17 351 $0 $0 FORT CONCHO GAS STORAGE INC $0 $0 FREEBIRD GAS STORAGE LLC FREEPORT LNG DEVELOPMENT LP GILL RANCH STORAGE LLC 19 $0 GOLDEN TRIANGLE STORAGE INC GULF SOUTH PIPELINE 2 2 90 90 HAMPSHIRE GAS CO 2 17 17 HARDY STORAGE COMPANY LLC 24 $0 HILCORP ALASKA LLC 130 130 HILL LAKE GAS STORAGE LLC HONEYE STORAGE CORPORATION 11 38 HOUSTON PIPE LINE COMPANY 46 INDIANA GAS COMPANY DBA VECTREN 156 ON OOOO JEFFERSON ISLAND STORAGE AND HUB LLC 2 KINDER MORGAN INTERSTATE GAS TRNAMIS 51 $0 KINDERMORGAN TEXAS PIPELINE LP 29 $0 $0 LACLEDE GAS COMPANY 81 81 Leaf River Energy Center 4 $0 $0 LEE 8 STORAGE PARTNERSHIP LODI GAS STORAGE LLC ∞ O LOUISVILLE GAS AND ELECTRIC COMPANY 296 MICHIGAN CONSOLIDATED GAS COMPANY LOWER COLORADO RIVER AUTHORITY 102 $0 $0 MICHIGAN GAS UTILITIES CORPORATION 1 12 MID CONTINENT CENTER 2 20 $0 $0 MISSISSIPPI HUB LLC 1 0 $0 $0 MONROE GAS STORAGE COMPANY LLC 1 1,212 23 23 NATIONAL FUEL GAS SUPPLY CORP 30 $0 $0 NATURAL GAS PIPELINE CO OF AMERICA 691 • ° $0 $0 NGO DEVELOPMENT CORPORATION 0 $0 $0 NGO TRANSMISSION INC 516 49 49 $917 NORTHERN ILLINOIS GAS COMPANY 0 0 $0 $0 NORTHERN INDIANA PUBLIC SVC C 84 $0 $0 NORTHERN NATURAL GAS COMPANY 338 338 $5,775 NORTHWESTERN CORP DBA NW ENERGY 72 72 $1,083 NW NATURAL 43 43 $593 B-2 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix B. Operator-level Costs Exhibit B-1: Estimated Mechanical Integrity Testing Costs per Operator under Partial Compliance Baseline Scenario Operator Name Number Number of Number Total Costs Annualized Total Fields of Wells' of Wells Tested (Thousand, 2015$3 Costs (7%; 2015$/Year) 3,4 Thousand ONEOK GAS STORAGE LLC 4 77 $0 $0 ONEOK TEXAS GAS STORAGE LP 2 8 $0 $0 PACIFIC GAS AND ELECTRIC COMPANY 116 $0 $0 PB ENERGY STORAGE SERVICES INC 1 2 2 $380 $51 PEOPLES GAS LIGHT AND COKE COMPANY 1 202 $0 $0 PEOPLES NATURAL GAS COMPANY 1 9 $0 $0 PEOPLES TWP LLC 4 19 $0 $0 PERRYVILLE GAS STORAGE LLO 1 1 PETAL GAS STORAGE LLC 1 $110 $15 $0 PINE PRAIRIE ENERGY CENTER LLC PONTCHARTRAIN NATURAL GAS SYSTEM PUBLIC SERVICE COMPANY OF COLORADO 4 PUGET SOUND ENERGY 103 QUESTAR PIPELINE COMPANY 78 ROCKY MOUNTAIN NATURAL GAS 10 $1,900 $2 RYCKMAN CREEK RESOURCES LLC $0 $O SALT PLAINS STORAGE LLC 30 $5,130 $683 SEMCO ENERGY GAS COMPANY SG RESOURCES MISSISSIPPI LLC $2,090 $950 SOURCEGAS DISTRIBUTION LLC $2, ,530 $337 SOUTHERN CALIFORNIA GAS COMPANY 196 $0 SOUTHERN INDIANA GAS ELECTRIC 132 SOUTHERN NATURAL GAS COMPANY 73 SOUTHERN STAR CENTRAL GAS PIPELINE 599 $O SOUTHWEST GAS STORAGE COMPANY STECKMAN RIDGE LP 227 13 $0 TENNESSEE GAS PIPELINE COMPANY 52 $0 TEXAS EASTERN TRANSMISSION LP 138 $0 TRANSCONTINENTAL GAS PIPELINE TEXAS GAS TRANSMISSION CORPORATION 497 $0 $0 COMPANY 51 $0 $0 TRES PALACIOS GAS STORAGE LLC 1 3 3 $330 $44 TRUNKLINE GAS COMPANY 1 62 62 $6,138 $817 UGI STORAGE COMPANY 1 3 3 $570 $76 UNDERGROUND SERVICES MARKHAM LP 1 5 5 $950 $126 UNDERGROUND STORAGE LLC 1 1 $0 $0 WILD GOOSE STORAGE INC 1 21 $0 $0 WILLISTON BASIN INTERSTATE PIPELINE 2 203 203 $20,097 $2,674 WORSHAM STEED GAS STORAGE LLC 1 57 $0 $0 WYCKOFF GAS STORAGE 1 $0 $0 Operators for which the number of wells is equal to 0 indicate fields identified in EIA (2016e) but not included in the TOTAL 16,991 2,408 $271,535 $36,131 AGA (2014) inventory. 2 Number of wells tested is less than the total number of wells presented in the column to the left in cases where wells are already covered under an existing operator commitment or regulated by the state where the facility is B-3 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix B. Operator-level Costs Exhibit B-1: Estimated Mechanical Integrity Testing Costs per Operator under Partial Compliance Baseline Scenario Total Operator Name Number Number of Number Total Costs Fields of Wells' of Wells Tested (Thousand, Annualized 2015$) Costs (7%; 2015$/Year)3, Thousand located. member, has an existing integrity testing program, and/or operates only intrastate fields in states with existing " Costs may be $0 for certain operators with greater than O number of wells in cases where the operator is an INGAA * Costs annualized using a 7 percent discount rate over 10 years (assuming tests conducted every 10 years). Exhibit B-2: Estimated Mechanical Integrity Testing Costs per Operator under Regulatory Compliance Only Baseline Scenario Operator Name Number Number of Number Total Costs Annualized Total Fields of Wells' of Wells Tested (Thousand, 2015$3 Costs (7%; 2015$/Year 3,4 Thousand AMEREN ILLINOIS 12 409 14 932 932 $112,078 $0 $0 ANR PIPELINE COMPANY $14,913 ARCADIA GAS STORAGE LLC 1 6 6 $660 $88 ARLINGTON GAS STORAGE COMPANY LLC 12 3 23 23 $3,982 $530 ATMOS ENERGY CORPORATION 154 $0 $0 ATMOS PIPELINE TEXAS 5 1 56 $0 $0 BAY GAS STORAGE COMPANY LTD 2 $0 $0 BEAR CREEK STORAGE COMPANY 74 74 $21,978 $2,924 BLUE LAKE STORAGE COMPANY 14 14 $2,394 $319 BLUEWATER GAS STORAGE LLC $0 $0 BOARDWALK LOUISIANA MIDSTREAM LLC NO 2 $380 $51 BOBCAT GAS STORAGE $0 $0 BRIDGELINE HOLDINGS LP 10 2 2 $380 $51 CADEVILLE GAS STORAGE 10 $1,900 $253 CALEDONIA ENERGY PARTNERS LLC 1 $0 $0 CENTANA INTERSTATE PIPELINE LLC 1 4 4 $760 $101 CENTERPOINT ENERGY 1 66 66 $6,534 $869 CENTRAL NEW YORK OIL AND GAS COMPANY 1 1 33 33 $5,643 $751 CENTRAL VALLEY GAS STORAGE LLC 12 $0 $0 CENTURY ALUMINUM SEBREE 1 4 $0 $0 CHEROKEE WELLS LLC 2 37 $0 $0 CHEVRON KEYSTONE GAS STORAGE, LLC 1 5 $0 $0 CHEVRON PHILLIPS CHEMICAL CO LP 1 $0 $0 CITIZENS ENERGY GROUP 224 $0 $0 CITY OF ELIZABETHTOWN NATURAL GAS 193 $0 $0 CLEAR CREEK STORAGE COMPANY LLC 1 $0 $0 COLORADO INTERSTATE GAS COMPANY 233 233 $42,867 COLUMBIA GAS OF PA INC 1 8 $0 $5,704 $0 COLUMBIA GAS TRANSMISSION LLC 32 3,362 3,362 $382,621 $50,913 CONSUMERS ENERGY COMPANY 14 981 981 $97,262 $12,942 COOK INLET NATURAL GAS STORAGE 1 35 35 $3,503 $466 B-4 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix B. Operator-level Costs Exhibit B-2: Estimated Mechanical Integrity Testing Costs per Operator under Regulatory Compliance Only Baseline Scenario Operator Name Number Number of Number Total Costs Annualized Total Fields of Wells' of Wells Tested (Thousand, 2015$3 Costs (7%; 20158/Year) 3,4 Thousand CRANBERRY PIPELINE CORPORATION 1 4 4 $440 $59 DELTA NATURAL GAS COMPANY INC 1 11 0 $0 $0 DOMINION EAST OHIO 15 3 780 780 $133,380 $17,748 DOMINION TRANSMISSION INC 1,431 1,431 $180,608 $24,032 DOW PL CO 1 1 $0 $0 EAST CHEYENNE GAS STORAGE LLC 1 $0 $0 EATON RAPIDS GAS STORAGE SYSTEM 1 14 14 $2,394 $319 EGYPTIAN GAS STORAGE CORPORATION 1 $0 $0 EL PASO NATURAL GAS COMPANY 20 20 $3,420 $455 ENABLE GAS TRANSMISSION LLC 71 71 $9,648 $1,284 ENABLE MIDSTREAM PARTNERSENOGEX $0 $0 ENABLE MISSISSIPPI RIVER TRANSM CORP 91 91 $24,651 $3,280 ENERGY TRANSFER FUEL LP 29 $0 $0 ENLINK MIDSTREAM SERVICES LLC 11 $0 ENSTOR GRAMA RIDGE STORAGE TRANSP 12 5 5 $1,650 $220 ENSTOR KATY STORAGE TRANSPLP 1 $0 $0 ENTERPRISE TEXAS PIPELINE $0 $0 EQUITRANS L P FORT CONCHO GAS STORAGE INC 17 351 329 $33,011 $4,393 1 16 $0 $0 FREEBIRD GAS STORAGE LLC $0 $0 FREEPORT LNG DEVELOPMENT LP $0 $0 GILL RANCH STORAGE LLC 1 19 0 $0 $0 GOLDEN TRIANGLE STORAGE INC 1 2 2 $380 $51 GULF SOUTH PIPELINE 2 90 90 $14,238 $1,895 HAMPSHIRE GAS CO 2 17 17 $3,230 $430 HARDY STORAGE COMPANY LLC 1 24 24 $7,128 $948 HILCORP ALASKA LLC 130 130 $13,027 $1,733 HILL LAKE GAS STORAGE LLC 11 $0 $0 HONEYE STORAGE CORPORATION 38 38 $3,762 $501 HOUSTON PIPE LINE COMPANY 46 $0 INDIANA GAS COMPANY DBA VECTREN 4 156 ° ON $0 $0 $0 JEFFERSON ISLAND STORAGE AND HUB LLC 2 $380 $51 KINDER MORGAN INTERSTATE GAS TRNAMIS 51 51 $8,721 KINDERMORGAN TEXAS PIPELINE LP 3 29 $1,160 $0 $0 LACLEDE GAS COMPANY 81 81 $8,019 $1,067 Leaf River Energy Center 4 $0 $0 LEE 8 STORAGE PARTNERSHIP LODI GAS STORAGE LLC 8 $880 $117 • 0 ∞ $0 $0 LOUISVILLE GAS AND ELECTRIC COMPANY LOWER COLORADO RIVER AUTHORITY 1O r 296 $0 $0 $0 $0 MICHIGAN CONSOLIDATED GAS COMPANY 5 102 102 $10,197 $1,357 MICHIGAN GAS UTILITIES CORPORATION 12 12 $1,188 $158 MID CONTINENT CENTER 20 $0 $0 MISSISSIPPI HUB LLC 1 $0 $0 B-5 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix B. Operator-level Costs Exhibit B-2: Estimated Mechanical Integrity Testing Costs per Operator under Regulatory Compliance Only Baseline Scenario Operator Name Number Number of Number Total Costs Annualized Total Fields of Wells' of Wells Tested (Thousand, 2015$) Costs (7%; 20158/Year) 3,4 Thousand MONROE GAS STORAGE COMPANY LLC 1 23 23 $2,277 $303 NATIONAL FUEL GAS SUPPLY CORP 30 1,212 1,212 $136,300 $18,136 NATURAL GAS PIPELINE CO OF AMERICA 8 691 535 $60,093 $7,996 NGO DEVELOPMENT CORPORATION 2 $0 $0 NGO TRANSMISSION INC 3 49 $6,894 $917 NORTHERN ILLINOIS GAS COMPANY 8 516 $0 $0 NORTHERN INDIANA PUBLIC SVC C 2 84 $0 $0 NORTHERN NATURAL GAS COMPANY 3 338 00 $43,398 $5,775 NORTHWESTERN CORP DBA NW ENERGY 3 72 $8,141 $1,083 NW NATURAL ^ + 43 $4,455 $593 ONEOK GAS STORAGE LLC 77 $9,533 $1,268 ONEOK TEXAS GAS STORAGE LP 8 $0 $0 PACIFIC GAS AND ELECTRIC COMPANY 116 $0 PB ENERGY STORAGE SERVICES INC 2 •ON OO $380 $51 PEOPLES GAS LIGHT AND COKE COMPANY 202 $0 $0 PEOPLES NATURAL GAS COMPANY 9 $0 $0 PEOPLES TWP LLC 19 $0 PERRYVILLE GAS STORAGE LLC $110 $15 PETAL GAS STORAGE LLC $1,470 $196 PINE PRAIRIE ENERGY CENTER LLC 1 5 5 $950 $126 PONTCHARTRAIN NATURAL GAS SYSTEM 1 $190 $25 PUBLIC SERVICE COMPANY OF COLORADO 3 46 46 $6,952 $925 PUGET SOUND ENERGY 103 103 $10,197 $1,357 QUESTAR PIPELINE COMPANY 78 78 $10,978 $1,461 ROCKY MOUNTAIN NATURAL GAS 10 10 $1,900 $253 RYCKMAN CREEK RESOURCES LLC 0 $0 $0 SALT PLAINS STORAGE LLC 30 30 $5,130 $683 SEMCO ENERGY GAS COMPANY 19 19 $2,090 $278 SG RESOURCES MISSISSIPPI LLC 23 5 5 $950 $126 SOURCEGAS DISTRIBUTION LLC 23 $2,530 $337 SOUTHERN CALIFORNIA GAS COMPANY 4 196 $0 $0 SOUTHERN INDIANA GAS ELECTRIC 4 132 $0 $0 SOUTHERN NATURAL GAS COMPANY 1 73 73 $12,483 $1,661 SOUTHERN STAR CENTRAL GAS PIPELINE 8 599 599 $65,997 $8,782 SOUTHWEST GAS STORAGE COMPANY 4 227 227 $32,769 $4,360 STECKMAN RIDGE LP 1 13 13 $2,223 $296 TENNESSEE GAS PIPELINE COMPANY 52 52 $8,892 $1,183 TEXAS EASTERN TRANSMISSION LP 5 138 134 $33,631 $4,475 TEXAS GAS TRANSMISSION CORPORATION 497 COMPANY TRANSCONTINENTAL GAS PIPELINE 497 $49,203 $6,547 2 51 51 $14,025 $1,866 TRES PALACIOS GAS STORAGE LLC 1 3 3 $330 $44 TRUNKLINE GAS COMPANY 1 62 $6,138 $817 UGI STORAGE COMPANY 1 3 3 $570 $76 B-6 <<>> Regulatory Impact Analysis: Underground Natural Gas Storage Appendix B. Operator-level Costs Exhibit B-2: Estimated Mechanical Integrity Testing Costs per Operator under Regulatory Compliance Only Baseline Scenario Total Operator Name Number Number Number Total Costs Annualized Fields of Wells' of Wells Tested (Thousand, 2015$)j Costs (7%; 015$/Year)3 housand UNDERGROUND SERVICES MARKHAM LP 1 5 $950 $126 UNDERGROUND STORAGE LLC 1 1 $0 $0 WILD GOOSE STORAGE INC 1 21 $0 $0 WILLISTON BASIN INTERSTATE PIPELINE 2 203 203 $20,097 $2,674 WORSHAM STEED GAS STORAGE LLC 1 57 WYCKOFF GAS STORAGE 1 $0 $0 $0 $0 "Operators for which the number of wells is equal to 0 indicate fields identified in EIA (2016e) but not included in the TOTAL 16,991 13,682 $1,705,519 $226,942 AGA (2014) inventory. 2 Number of wells tested is less than the total number of wells presented in the column to the left in cases where wells are already covered under an existing operator commitment or regulated by the state where the facility is only intrastate fields in states with existing regulatory requirements. 3 Costs may be $0 for certain operators with greater than 0 number of wells in cases where the operator operates 4 Costs annualized using a 7 percent discount rate over 10 years (assuming tests conducted every 10 years). 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