UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
CURRENT REPORT
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| Item 8.01 | Other Events |
On February 1, 2019, pursuant to the Agreement and Plan of Merger, dated as of April 21, 2018, among CenterPoint Energy, Inc. (“CenterPoint Energy”), Vectren Corporation (“Vectren”) and Pacer Merger Sub, Inc., CenterPoint Energy acquired Vectren for approximately $6 billion in cash (the “Merger”).
This Current Report on Form 8-K provides certain additional disclosure as a result of the Merger for CenterPoint Energy related to the business, properties and regulations of, or applicable to, Vectren. This information should be read in conjunction with CenterPoint Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 (the “2018 Form 10-K”), CenterPoint Energy’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2019 (the “1st Quarter 2019 10-Q”) and June 30, 2019 (the “2nd Quarter 2019 10-Q” and, together with the 1st Quarter 2019 10-Q, the “2019 Form 10-Qs”), and Vectren’s audited consolidated financial statements as of and for the year ended December 31, 2018 and related notes thereto, filed as exhibits to CenterPoint Energy’s Current Report on Form 8-K filed on August 12, 2019.
As of June 30, 2019, Vectren held three public utilities through its wholly-owned subsidiary, Vectren Utility Holdings, Inc. (“VUHI”), a public utility holding company:
| • | Indiana Gas Company, Inc. (“Indiana Gas”), which provides energy delivery services to natural gas customers located in central and southern Indiana; |
| • | Southern Indiana Gas and Electric Company (“SIGECO”), which provides energy delivery services to electric and natural gas customers located near Evansville in southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market; and |
| • | Vectren Energy Delivery of Ohio, Inc. (“VEDO”), which provides energy delivery services to natural gas customers located near Dayton in west-central Ohio. |
As of June 30, 2019, Vectren also performed nonutility activities through:
| • | Infrastructure Services, which provides underground pipeline construction and repair services through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC and serves natural gas utilities across the United States, focusing on recurring integrity, station and maintenance work and opportunities for large transmission pipeline construction projects; and |
| • | Energy Systems Group, LLC (“ESG”), which provides energy performance contracting and sustainable infrastructure services, such as renewables, distributed generation and combined heat and power projects. |
Natural Gas Distribution
Upon the consummation of the Merger, CenterPoint Energy’s Natural Gas Distribution reportable segment added the legacy natural gas utility services of Vectren, which includes the natural gas utility operations of Indiana Gas, SIGECO and VEDO. At June 30, 2019, CenterPoint Energy supplied natural gas service to approximately 1,034,100 Indiana and Ohio customers, including 946,500 residential, 85,800 commercial, and 1,800 industrial and other contract customers. Average gas utility Indiana and Ohio customers served were approximately 1,031,200 in 2018 and 1,022,000 in 2017.
The Indiana and Ohio service areas contain diversified manufacturing and agriculture-related enterprises. The principal industries served include automotive assembly, parts and accessories; feed, flour and grain processing; metal castings, plastic products; gypsum products; electrical equipment, metal specialties, glass and steel finishing;
pharmaceutical and nutritional products; gasoline and oil products; ethanol; and coal mining. The largest Indiana communities served are Evansville, Bloomington, Terre Haute, suburban areas surrounding Indianapolis and Indiana counties near Louisville, Kentucky. The largest community served in Ohio is Dayton, Ohio.
Revenues
For its Indiana and Ohio natural gas distribution operations, CenterPoint Energy receives gas revenues by selling gas directly to customers at approved rates or by transporting gas through its pipelines at approved rates to customers that have purchased gas directly from other producers, brokers, or marketers. Total throughput was 153.4 million dekatherms (“MMDth”) for the six months ended June 30, 2019 and 268.0 million MMDth for the year ended December 31, 2018. Gas sold and transported to residential and commercial customers was 70.9 MMDth (representing 46 percent of throughput) for the six months ended June 30, 2019 and 114.9 MMDth (representing 43 percent of throughput) for the year ended December 31, 2018. Gas transported or sold to industrial and other contract customers was 82.5 MMDth (representing 54 percent of throughput) for the six months ended June 30, 2019 and 153.1 MMDth (representing 57 percent of throughput) for the year ended December 31, 2018.
For the five-month period from February 1, 2019 to June 30, 2019, CenterPoint Energy’s Indiana and Ohio natural gas distribution operation revenues were $351 million. For the year ended December 31, 2018, gas utility revenues were $857.8 million, of which residential customers accounted for 67 percent and commercial accounted for 23 percent. Industrial and other contract customers accounted for 10 percent of revenues. Rates for transporting gas generally provide for the same margins earned by selling gas under applicable sales tariffs.
Availability of Natural Gas
The volumes of gas sold are seasonal and affected by variations in weather conditions. To meet seasonal demand, as of June 30, 2019, CenterPoint Energy’s Indiana natural gas distribution operations have storage capacity at seven active underground gas storage fields and three propane plants. Periodically, purchased natural gas is injected into storage. The injected gas is then available to supplement contracted and manufactured volumes during periods of peak requirements. See “—Properties” below for additional details.
Natural Gas Purchasing Activity in Indiana
CenterPoint Energy’s Indiana natural gas distribution operations enter into short-term and long-term contracts with third party suppliers to purchase natural gas. Certain contracts are firm commitments under five and ten-year arrangements. During the six months ended June 30, 2019 and during all of 2018, CenterPoint Energy’s Indiana natural gas distribution operations purchased all of their gas supply from third parties and 79 percent and 77 percent of such purchases were from a single third party for the six months ended June 30, 2019 and for the year ended December 31, 2018, respectively.
Natural Gas Purchasing Activity in Ohio
On April 30, 2008, the Public Utilities Commission of Ohio (“PUCO”) issued an order which approved an exit from the merchant function in CenterPoint Energy’s natural gas distribution Ohio service territory. As a result, substantially all of CenterPoint Energy’s Ohio customers purchase natural gas directly from retail gas marketers rather than from CenterPoint Energy.
Total Natural Gas Purchased Volumes
In the six months ended June 30, 2019, CenterPoint Energy’s Indiana and Ohio natural gas distribution operations purchased 43.9 MMDth of gas at an average cost of $3.53 per dekatherm (“Dth”). In 2018, CenterPoint Energy’s Indiana and Ohio natural gas distribution operations purchased 78.7 MMDth of gas at an average cost of $3.90 per Dth. The average cost of gas per Dth purchased for CenterPoint Energy’s Indiana and Ohio natural gas distribution operations for the previous three years was $4.02 in 2017, $3.75 in 2016 and $3.96 in 2015. The costs provided are inclusive of demand charges.
Properties
As of December 31, 2018, CenterPoint Energy’s Indiana natural gas distribution operations owned and operated seven active underground gas storage fields in Indiana covering 67,224 acres of land, with an estimated ready delivery from storage capability of 11.5 billion cubic feet (“BCF”) of natural gas with maximum peak day delivery capabilities of 243,500 thousand cubic feet (“MCF”) per day. CenterPoint Energy’s Indiana natural gas distribution operations also owned and operated three liquified petroleum (propane) air-gas manufacturing plants located in Indiana with the ability to store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of manufactured gas per day. In addition to its company-owned storage and propane capabilities, CenterPoint Energy’s Indiana natural gas distribution operations have 23.1 BCF of interstate natural gas pipeline storage service in Indiana and Ohio with maximum peak day delivery capabilities of 456,013 million British thermal units per day. CenterPoint Energy has released its Ohio storage service to retail gas marketers and those suppliers are responsible for the demand charges. CenterPoint Energy’s natural gas delivery system in Indiana and Ohio includes approximately 22,500 miles of distribution and transmission mains, all of which are located in Indiana and Ohio except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported to customers in Indiana.
Indiana Electric
Upon consummation of the Merger, CenterPoint Energy added Indiana Electric Integrated as a new reportable segment, which consists of SIGECO’s electric transmission and distribution services, including its power generating and wholesale power operations (“Indiana Electric”). At June 30, 2019, Indiana Electric supplied electric service to approximately 147,100 Indiana customers, including approximately 128,200 residential, 18,700 commercial, and 200 industrial and other customers. Average electric utility customers served were approximately 146,300 in 2018, 145,200 in 2017 and 144,400 in 2016.
The principal industries served include plastic products; automotive assembly and steel finishing; pharmaceutical and nutritional products; automotive glass; gasoline and oil products; ethanol; and coal mining.
Revenues
For the five-month period from February 1, 2019 to June 30, 2019, CenterPoint Energy’s Indiana Electric revenues were $223 million. For the six months ended June 30, 2019, retail electricity sales totaled 2,254.0 gigawatt hours (“GWh”). In addition, in the six months ended June 30, 2019, Indiana Electric sold 271.2 GWh through wholesale activities principally to the Midcontinent Independent System Operator (“MISO”).
For the year ended December 31, 2018, Indiana Electric revenues were $582.5 million. Retail electricity sales totaled 4,958.0 GWh. Residential customers accounted for 40 percent of 2018 revenues; commercial 28 percent; industrial 30 percent; and other 2 percent. In addition, in 2018 Indiana Electric sold 856.4 GWh through wholesale activities principally to MISO.
System Load
Total load for each of the years 2014 through 2018 at the time of the system summer peak, and the related reserve margin, is presented below in megawatts (“MW”).
| Date of summer peak load |
7/5/2018 |
7/21/2017 |
6/22/2016 |
7/29/2015 |
8/27/2014 |
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| Total load at peak |
1,042 |
1,042 |
1,096 |
1,088 |
1,095 |
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| Generating capability |
1,252 |
1,248 |
1,248 |
1,248 |
1,298 |
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| Purchase supply (effective capacity) |
35 |
36 |
37 |
37 |
38 |
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| Interruptible contracts & direct load control |
56 |
53 |
75 |
72 |
71 |
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| Total power supply capacity |
1,343 |
1,337 |
1,360 |
1,357 |
1,407 |
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| Reserve margin at peak |
29 |
% | 28 |
% | 24 |
% | 25 |
% | 22 |
% | ||||||||||
The winter peak load for the 2018-2019 season of approximately 757 MW occurred on January 30, 2019. The prior year winter peak load for the 2017-2018 season was approximately 824 MW, occurring on January 16, 2018.
Generating Capacity
Indiana Electric’s installed generating capacity as of December 31, 2018, was rated at 1,252 MW. Coal-fired generating units provide 1,000 MW of capacity, natural gas or oil-fired turbines used for peaking or emergency conditions provide 245 MW, solar units provide 4 MW of capacity and a landfill gas electric generation project provides 3 MW. Two natural gas turbines, with 20 MW of combined capacity, were retired in April 2019, making Indiana Electric’s generating capacity 1,232 MW at June 30, 2019.
Electric generation for 2018 was fueled by coal (95 percent), wind (3 percent), natural gas (1 percent), and landfill gas and solar (less than 1 percent, respectively). Oil was used only for testing of gas/oil-fired peaking units. Indiana Electric generated approximately 3,856 GWh in 2018. Further information about Indiana Electric’s owned generation is included in “—Properties,” below.
Coal for coal-fired generating stations has been supplied from operators of nearby coal mines as there are substantial coal reserves in the southern Indiana area. Approximately 1.3 million tons were purchased for generating electricity during the six months ended June 30, 2019. Indiana Electric purchased 2.0 million tons and 2.1 million tons in 2018 and 2017, respectively. Indiana Electric’s coal inventory was approximately 500 thousand tons and 300 thousand tons at June 30, 2019 and December 31, 2018, respectively.
Coal Purchases
The average cost of coal per ton purchased and delivered in the six months ended June 30, 2019 was $51.11. The average cost of coal per ton purchased and delivered in 2018, 2017, 2016, 2015 and 2014 was $52.75, $53.88, $54.24, $55.22 and $55.18, respectively. Since August 2014, Indiana Electric has purchased substantially all of its coal from Sunrise Coal, LLC.
Firm Purchase Supply
As part of its power portfolio, Indiana Electric is a 1.5 percent shareholder in the Ohio Valley Electric Corporation (“OVEC”), and based on its participation in the Inter-Company Power Agreement (“ICPA”) between OVEC and its shareholder companies, many of whom are regulated electric utilities, Indiana Electric has the right to 1.5 percent of OVEC’s generating capacity output, which, as of June 30, 2019, was approximately 32 MWs. Per the ICPA, Indiana Electric is charged demand charges which are based on OVEC’s operating expenses, including its financing costs. Those demand charges are available to pass through to customers under Indiana Electric’s fuel adjustment clause. Under the ICPA, and while OVEC’s plants are operating, Indiana Electric is severally responsible for its share of OVEC’s debt obligations. Based on OVEC’s current financing, as of June 30, 2019, Indiana Electric’s 1.5 percent share of OVEC’s debt obligation equates to between $20 and 25 million, depending on revolving capacity commitments. Due to concerns regarding bankruptcy proceedings of one of OVEC’s shareholders that holds a 4.9 percent interest under the ICPA, both Moody’s Investors Service, Inc. and S&P Global Ratings rate OVEC one notch below investment grade. Fitch, Inc. continues to rate OVEC as investment grade and on July 24, 2019, revised its outlook from negative to stable. OVEC has represented it has both liquidity and financing capability that will allow it to continue to operate and provide power to its participating members, who include American Electric Power Co Inc., Duke Energy Corporation, and PPL Corporation. In the first six months of 2019 and in the year ended December 31, 2018, Indiana Electric purchased approximately 66 GWh and 149 GWh, respectively, from OVEC. If a default were to occur by a member, any reallocation of the existing debt requires consent of the remaining ICPA participants. If any such reallocation were to occur, Indiana Electric would expect to recover any related costs through the fuel adjustment clause, as it does currently for its 1.5 percent share. In July 2019, the Ohio Legislature enacted House Bill 6, which will provide financial support to the members of OVEC serving Ohio customers.
In April 2008, Indiana Electric executed a capacity contract with Benton County Wind Farm, LLC to purchase as much as 30 MW from a wind farm located in Benton County, Indiana, with Indiana Utility Regulatory Commission (“IURC”) approval. The contract expires in 2029. Indiana Electric purchased approximately 47 GWh and 77 GWh in the six months ended June 30, 2019, and in the year ended December 31, 2018, respectively, under this contract.
In December 2009, Indiana Electric executed a 20-year power purchase agreement with Fowler Ridge II Wind Farm, LLC to purchase as much as 50 MW of energy from a wind farm located in Benton and Tippecanoe Counties in Indiana, with the approval of the IURC. Indiana Electric purchased approximately 81 GWh and 128 GWh in the six months ended June 30, 2019, and in the year ended December 31, 2018, respectively, under this contract. In total, wind resources provided 5 percent and 3 percent of total GWh sourced in the first six months of 2019 and in the year ended December 31, 2018, respectively.
MISO Related Activity
Indiana Electric is a member of the MISO, a Federal Energy Regulatory Commission (“FERC”) approved regional transmission organization. The MISO serves the electric transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission facilities as well as other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, where it bids its generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (“LMP”) as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position. During the six months ended June 30, 2019, in intervals when purchases from the MISO were in excess of generation sold to the MISO, the net purchases were 143 GWh. During the six months ended June 30, 2019, in intervals when sales to the MISO were in excess of purchases from the MISO, the net sales were 271 GWh. During the year ended December 31, 2018, in intervals when purchases from the MISO were in excess of generation sold to the MISO, the net purchases were 398 GWh. During the year ended December 31, 2018, in intervals when sales to the MISO were in excess of purchases from the MISO, the net sales were 856 GWh.
Interconnections
As of June 30, 2019, Indiana Electric had interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc. and Big Rivers Electric Corporation providing the ability to simultaneously interchange approximately 900 MW during peak load periods. Indiana Electric, as required as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets to the MISO. Indiana Electric, in conjunction with the MISO, must operate the bulk electric transmission system in accordance with North American Electric Reliability Corporation (“NERC”) Reliability Standards. As a result, interchange capability varies based on regional transmission system configuration, generation dispatch, seasonal facility ratings, and other factors.
Properties
Indiana Electric’s installed generating capacity as of December 31, 2018 was rated at 1,252 MW. As of December 31, 2018, Indiana Electric’s coal-fired generating facilities were the A.B. Brown Generating Station (“Brown”) with two units totaling 490 MW of combined capacity, located in Posey County approximately eight miles east of Mt. Vernon, Indiana; the F.B. Culley Generating Station (“Culley”) with two units totaling 360 MW of combined capacity; and Warrick Unit 4 (“Warrick”) with 150 MW of capacity. Both the Culley and Warrick Stations are located in Warrick County near Yankeetown, Indiana. As of December 31, 2018, Indiana Electric’s gas-fired turbine peaking units were: two 80 MW gas turbines (“Brown Unit 3” and “Brown Unit 4”) located at Brown; one Broadway Avenue Gas Turbine (“Broadway Avenue Unit 2”) located in Evansville, Indiana with a capacity of 65 MW; and two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20 MW. The Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil. As of December 31, 2018, total capacity of Indiana Electric’s five gas turbines was 245 MW; these units are generally used only for reserve, peaking or emergency purposes. As of December 31, 2018, Indiana Electric also had a landfill gas electric generation project in Pike County, Indiana with a total generation capability of 3 MW. In addition, as of December 31, 2018, Indiana Electric had two solar units located in Evansville: Oak Hill Road and Volkman Road, with 2 MW generation capacity each. Two gas turbines, with 20 MW of combined capacity, were retired in April 2019, making Indiana Electric’s generating capacity 1,232 MW at June 30, 2019.
As of December 31, 2018, Indiana Electric’s transmission system consisted of 1,028 circuit miles of 345 kilovolt (“kV”), 138kV and 69kV lines. The transmission system also includes 34 substations with an installed capacity of 4,900 megavolt amperes (“Mva”). As of December 31, 2018, Indiana Electric’s electric distribution system included 4,551 circuit miles of lower voltage overhead lines and 488 trench miles of conduit containing 2,442 circuit miles of underground distribution cable. The distribution system also includes 83 distribution substations with an installed capacity of 2,100 Mva and 55,358 distribution transformers with an installed capacity of 2,481 Mva.
As of December 31, 2018, SIGECO owned utility property outside of Indiana approximating 24 miles of 138kV and 345kV electric transmission lines, which are included in the 1,028 circuit miles discussed above. These assets are located in Kentucky and interconnect with Louisville Gas and Electric Company’s transmission system at Cloverport, Kentucky and with the Big Rivers Electric Cooperative at Sebree, Kentucky.
Infrastructure Services
For the five-month period from February 1, 2019 to June 30, 2019, CenterPoint Energy’s Infrastructure Services revenues were $472 million. Infrastructure Services generated revenues of $966 million in 2018 and $996 million in 2017. For additional information about Infrastructure Services, please see the 2018 Form 10-K and the 2019 Form 10-Qs.
ESG
For the five-month period from February 1, 2019 to June 30, 2019, CenterPoint Energy’s ESG revenues were $116 million. ESG generated revenues of $291 million in 2018 and $282 million in 2017. ESG’s backlog of fixed price construction projects at June 30, 2019 was $314 million, compared to $281 million at December 31, 2018 and $180 million at December 31, 2017. For additional information about ESG, please see the 2018 Form 10-K and the 2019 Form 10-Qs.
Regulation Overview-Indiana Electric and Natural Gas Distribution
CenterPoint Energy’s Indiana gas and electric operations are regulated by the IURC, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters specific to its Indiana customers (specifically, the operations of SIGECO and Indiana Gas). The retail gas operations of VEDO are subject to regulation by the PUCO. The discussion below relates solely to CenterPoint Energy’s Indiana and Ohio utilities.
Rate Design Strategies
Sales of natural gas and electricity to residential and commercial customers are largely seasonal and are impacted by weather. Trends in the average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed, and as CenterPoint Energy’s utilities have implemented conservation programs. In CenterPoint Energy’s two Indiana natural gas service territories, normal temperature adjustment (“NTA”) and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. CenterPoint Energy’s Ohio natural gas service territory has a straight fixed variable rate design for its residential customers. This rate design, which was fully implemented in February 2010, mitigates approximately 90 percent of the Ohio service territory’s weather risk and risk of decreasing consumption specific to its small customer classes.
In CenterPoint Energy’s Indiana and Ohio natural gas service territories, the commissions have authorized bare steel and cast iron replacement programs. In Indiana, state laws were passed in 2012 and 2013 that expand the ability of utilities to recover, outside of a base rate proceeding, certain costs of federally mandated projects and other significant gas distribution and transmission infrastructure replacement investments. Legislation was passed in 2011 in Ohio that supports the investment in other capital projects, allowing the utility to defer the impacts of these investments until its next base rate case. CenterPoint Energy has received approval to implement these mechanisms in both states.
In 2017, SIGECO started recovering certain costs of significant electric distribution and transmission infrastructure replacement investments. SIGECO currently recovers certain transmission investments outside of base rates. SIGECO has neither an NTA nor a decoupling mechanism; however, rate designs provide for a lost margin recovery mechanism that works in tandem with conservation initiatives.
Tracked Operating Expenses
Gas costs and fuel costs incurred to serve Indiana customers are two of CenterPoint Energy’s most significant operating expenses for its Indiana and Ohio operations. Rates charged to natural gas customers in Indiana contain a gas cost adjustment (“GCA”) clause. The GCA clause allows CenterPoint Energy to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on actual experience and subject to caps that are based on historical experience. Electric rates in Indiana contain a fuel adjustment clause (“FAC”) that allows for timely adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an approved variable benchmark based on The New York Mercantile Exchange (“NYMEX”) natural gas prices, is also timely recovered through the FAC.
GCA and FAC procedures involve periodic filings and IURC hearings to establish price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between actual recoveries representing the estimated costs and actual costs incurred. Since April 2010, CenterPoint Energy’s Ohio natural gas utility has not been the supplier of natural gas in its Ohio territory.
The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. In 2018, CenterPoint Energy’s Indiana natural gas utilities were not impacted by the earnings test.
In Indiana, gas pipeline integrity management operating costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of typical base rate recovery. In addition, certain operating costs, including depreciation associated with federally mandated investments, gas and electric distribution and transmission infrastructure replacement investments, and regional electric transmission assets not in base rates are also recovered by mechanisms outside of typical base rate recovery.
In Ohio, expenses such as uncollectible accounts expense, costs associated with exiting the merchant function, and costs associated with the infrastructure replacement program and other gas distribution capital expenditures are subject to recovery outside of base rates.
Revenues and margins in both states are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.
Base Rate Orders
SIGECO’s electric territory received an order from the IURC in April 2011, with rates effective May 2011, and its gas territory received an order from the IURC and implemented rates in August 2007. Indiana Gas received an order from the IURC and implemented rates in February 2008, and VEDO received an order from PUCO in January 2009, with implementation in February 2009. The orders authorize a return on equity ranging from 10.15 percent to 10.40 percent. The authorized returns reflect the impact of rate design strategies that have been authorized by these state commissions.
Gas Rate and Regulatory Matters
The below description should be read in conjunction with “Risk Factors” in the 2018 Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters” in each of the 2019 Form 10-Qs which provide a description of regulatory matters pertaining to CenterPoint Energy’s Indiana and Ohio natural gas distribution operations, including updates as of June 30, 2019 to certain of the matters described below. The discussion below relates solely to CenterPoint Energy’s Indiana and Ohio natural gas utility operations.
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement
CenterPoint Energy monitors and maintains its Indiana and Ohio natural gas distribution systems to ensure natural gas is delivered in a safe and efficient manner. CenterPoint Energy’s natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are the result of federal pipeline safety requirements. Laws passed in both Indiana and Ohio provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.
Indiana Senate Bill 251 (“Senate Bill 251”) provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, based on the overall rate of return most recently approved by the IURC, through a base rate case or other proceeding, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs is deferred for future recovery in the utility’s next general rate case.
Indiana Senate Bill 560 (“Senate Bill 560”) supplements Senate Bill 251 described above and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on the investment that reflects the current capital structure and associated costs, except for the rate of return on equity, which remains fixed at the rate determined in CenterPoint Energy’s last base rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are deferred for future recovery in the utility’s next general rate case, which must be filed before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of not more than two percent.
Ohio House Bill 95 (“House Bill 95”) permits a natural gas utility to apply for recovery of much of its capital expenditure program. This legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post-in-service carrying costs until recovery is approved by the PUCO.
Requests for Recovery under Indiana Regulatory Mechanisms
In August 2014, the IURC issued an Order approving CenterPoint Energy’s Indiana natural gas utilities’ seven-year capital infrastructure replacement and improvement plan (the “Plan”), beginning in 2014, and the proposed accounting authority and recovery. Compliance projects and other infrastructure improvement projects were approved pursuant to Senate Bill 251 and 560, respectively. As provided in the statutes, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses, with 80 percent of the costs, including a return, recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in CenterPoint Energy’s Indiana natural gas utilities’ next base rate proceeding. In addition, the Order established guidelines to annually update the seven-year capital investment plan. Finally, the Order approved CenterPoint Energy’s Indiana natural gas utilities’ proposal to recover eligible costs assigned to the residential customer class via a fixed monthly charge per residential customer.
Since the August 2014 Order, CenterPoint Energy’s Indiana natural gas utilities have received ten semi-annual orders which approved the inclusion in rates of approximately $727 million of approved capital investments through December 31, 2018, and approved updates to the seven-year capital investment plan reflecting capital expenditures of approximately $955 million. For an update on the most recent order before the IURC regarding the recovery of investments as of December 31, 2018, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters” in the 2nd Quarter 2019 10-Q. Some projects were removed from the list of approved capital investments in response to subsequent interpretations of the types of projects that qualify for recovery through Senate Bill 560 by the Indiana Supreme Court. CenterPoint Energy’s Indiana natural gas utilities removed the projects from the plan in its Indiana natural gas utilities’ eighth semi-annual Transmission Distribution System Improvement Charge (“TDSIC”) proceeding on July 25, 2018. CenterPoint Energy does not expect a resulting material impact to results of operations or cash flow from operations as a result of these changes.
In December 2016, the Pipelines and Hazardous Materials Safety Administration (“PHMSA”) issued interim final rules related to integrity management for storage operations. Efforts are underway to implement the new requirements. Further, CenterPoint Energy reviewed the Underground Natural Gas Storage Safety Recommendations from a joint Department of Energy and PHMSA led task force. On August 3, 2017, CenterPoint Energy’s Indiana natural gas utilities filed for authority to recover the associated costs using the mechanism allowed under Senate Bill 251. CenterPoint Energy’s Indiana natural gas utilities received the IURC Order approving the request for recovery and inclusion in the approved seven-year capital investment plan on December 28, 2017. Approximately $15 million of operating expenses and $12 million of capital investments have been included in the plan over a three-year period beginning in 2018. CenterPoint Energy does not have company-owned storage operations in Ohio.
At December 31, 2018 and December 31, 2017, CenterPoint Energy’s Indiana natural gas utilities had regulatory assets related to the Plan totaling $99.4 million and $78.0 million, respectively.
Ohio Recovery and Deferral Mechanisms
The PUCO Order approving CenterPoint Energy’s Ohio natural gas utility’s 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (“DRR”). The DRR’s primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines, as well as certain other infrastructure investments. This rider is updated annually for qualifying capital expenditures and allows for a return on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and CenterPoint Energy’s Ohio natural gas utility which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of certain other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order. In the event CenterPoint Energy’s Ohio natural gas utility exceeds these caps, amounts in excess can be deferred for future recovery. The Order also approved CenterPoint Energy’s Ohio natural gas utility’s commitment that the DRR can only be further extended as part of a base rate case.
CenterPoint Energy’s Ohio natural gas utility’s pending base rate case, which was filed in March 2018, requested an extension to include investments made starting 2018 through completion of the program, currently estimated at 2023. In total, CenterPoint Energy’s Ohio natural gas utility has made capital investments on projects that are now in-service under the DRR totaling $390.9 million as of December 31, 2018, of which $321.1 million has been approved for recovery under the DRR through December 31, 2017. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $38.1 million and $31.2 million at December 31, 2018 and December 31, 2017, respectively. For an update on the pending rate case and CenterPoint Energy’s Ohio natural gas utility’s pending DRR proceeding, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters” in the 2nd Quarter 2019 10-Q.
The PUCO has also issued Orders approving CenterPoint Energy’s Ohio natural gas utility’s filings under Ohio House Bill 95. These Orders approve deferral of CenterPoint Energy’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential
and small general service customer per month. CenterPoint Energy’s Ohio natural gas utility requested recovery of these deferrals through December 31, 2017 in its rate case, along with a mechanism to recover future Ohio House Bill 95 deferrals. At December 31, 2018 and December 31, 2017, CenterPoint Energy’s Ohio natural gas utility had regulatory assets totaling $97.6 million and $66.1 million, respectively, associated with the deferral of depreciation, post-in-service carrying costs, and property taxes. On May 31, 2019, CenterPoint Energy’s Ohio natural gas utility submitted its most recent annual report required under its House Bill 95 Order. This report covers CenterPoint Energy’s Ohio natural gas utility’s capital expenditure program through calendar year 2018.
Vectren Ohio Gas Rate Case
On March 30, 2018, CenterPoint Energy’s Ohio natural gas utility filed with the PUCO a request for a $34 million increase in its base rates and charges for VEDO’s distribution business in its 17 county service area in west-central Ohio. The requested increase includes the benefit of the tax reform legislation informally called the Tax Cuts and Jobs Act of 2017, which decreased the corporate rate from 35 percent to 21 percent. The filing is necessary to extend the DRR mechanism beyond 2017 through completion of the accelerated replacement program, and to recover the costs of capital investments made over the past ten years, much of which has been deferred as part of CenterPoint Energy’s Ohio natural gas utility’s capital expenditure program under Ohio House Bill 95. The filing also addresses the recovery of the current Ohio House Bill 95 regulatory asset balance, and a proposed mechanism to recover future Ohio House Bill 95 deferrals.
On January 4, 2019, CenterPoint Energy’s Ohio natural gas utility, in conjunction with the PUCO Staff, the City of Dayton, Interstate Gas Supply, and the Retail Energy Supply Association, filed a stipulation and recommendation with the PUCO regarding the requested revenue increase. The non-unanimous Stipulation provides for a nearly $22.7 million increase in the base rates and charges for VEDO’s distribution business, based on approximately $622 million of rate base and a rate of return of 7.48%. The Stipulation supports the continuation of the straight-fixed-variable rate design for residential customers and expansion to small commercial customers. In addition, the Stipulation supports the extension of the DRR with targeted completion of the accelerated replacement program by 2023, and the continuation of the deferral authority under Ohio House Bill 95 for VEDO’s capital expenditure program with a new mechanism to recover future deferrals over the life of the investments. Finally, the Stipulation supports the continuation of CenterPoint Energy’s Ohio natural gas utility’s energy efficiency programs through 2020, with a commitment to file for further extension by the end of 2019. CenterPoint Energy’s Ohio natural gas utility expects an order later in 2019.
For an update on the pending case, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters” in the 2nd Quarter 2019 10-Q.
Pipeline and Hazardous Materials Safety Administration (PHMSA)
In March 2016, PHMSA published a notice of proposed rulemaking on the safety of gas transmission and gathering lines. The proposed rule addresses many of the remaining requirements of the 2011 Pipeline Safety Act, with a focus on extending integrity management rules to address a much larger portion of the natural gas infrastructure and adds requirements to address broader threats to the integrity of a pipeline system. CenterPoint Energy continues to evaluate the impact these proposed rules will have on its integrity management programs and transmission and distribution systems.
Progress on finalizing the rule continues to work through the administrative process. Although the rule has not yet been finalized as of this filing, the final rule is still expected in 2019. CenterPoint Energy believes the costs to comply with the new rules would be considered federally mandated and therefore should be recoverable under Senate Bill 251 in Indiana and eligible for deferral under House Bill 95 in Ohio.
Electric Rate and Regulatory Matters
The below description should be read in conjunction with “Risk Factors” in the 2018 Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters” in each of the 2019 Form 10-Qs which provide a description of regulatory matters pertaining to CenterPoint Energy’s Indiana electric utility operations, including updates as of June 30, 2019 to certain of the matters described below. The discussion below relates solely to CenterPoint Energy’s Indiana electric utility operations.
Electric Requests for Recovery under Senate Bill 560
The provisions of Senate Bill 560, as described in Note 16 for gas projects, are the same for qualifying electric projects. On February 23, 2017, Indiana Electric filed for authority to recover costs related to its electric system modernization plan, using the mechanism allowed under Senate Bill 560. The electric system modernization plan includes investments to upgrade portions of Indiana Electric’s network of substations, transmission and distribution systems in Indiana, to enhance reliability and allow the grid to accept advanced technology to improve the information and service provided to customers.
On September 20, 2017, the IURC issued an Order approving Indiana Electric’s electric system modification as reflected in the settlement agreement reached between Indiana Electric, the Indiana Office of the Utility Consumer Counselor, and a coalition of industrial customers. The settlement agreement includes defined annual caps on recoverable capital investments, with the total approved plan set at $446.5 million. The settlement agreement also addresses how the eligible costs would be recoverable in rates, with a cap on the residential and small general service fixed monthly charge per customer in each semi-annual filing. The remaining costs to residential and small general service customers would be recovered via a volumetric energy charge.
The settlement agreement removed advanced metering infrastructure (“AMI” or digital meters) from the plan. However, deferral of the costs for AMI was agreed upon in the settlement whereby Indiana Electric can move forward with deployment in the near-term. The request for cost recovery for the AMI project will not occur until the next base rate review proceeding, which is expected to be filed by the end of 2023. In that proceeding, settling parties have agreed not to oppose inclusion of the AMI project in rate base.
On December 20, 2017, the IURC issued an Order approving the initial rates necessary to begin cash recovery of 80 percent of the revenue requirement, inclusive of return, with the remaining 20 percent deferred for recovery in the utility’s next general rate case. These initial rates captured approved investments made through April 30, 2017.
On December 5, 2018, the IURC issued an order (“December 2018 order”) for the third semi-annual filing approving the inclusion in rates of investments made from November 2017 through April 2018. Some projects were removed from the list of approved capital investments in this filing as a result of subsequent interpretations of the types of projects that qualify for recovery through Senate Bill 560 by the Indiana Supreme Court. As Indiana Electric has the ability under the electric plan to substitute projects with other approved projects within defined annual cost caps, Indiana Electric does not expect these subsequent interpretations to impact the total amount of the approved plan, and therefore does not expect a resulting material impact to results of operations or cash flow from operations. Indiana Electric removed the projects from the plan in accordance with these subsequent interpretations when it filed its third semi-annual TDSIC proceeding on August 1, 2018. Through the December 2018 order, approximately $59 million of the approved capital investment plan has been incurred and approved for recovery. As of December 31, 2018 and December 31, 2017, Indiana Electric had regulatory assets related to the Electric TDSIC plan totaling $2.2 million and $4.3 million, respectively. For an update on the completed and pending cases, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters” in the 2nd Quarter 2019 10-Q.
SIGECO Electric Environmental Compliance Filing
On January 28, 2015, the IURC issued an Order approving Indiana Electric’s request for approval of capital investments in its coal-fired generation units to comply with new Environmental Protection Agency (“EPA”) mandates related to mercury and air toxic standards (“MATS”) effective in 2015 and to address an outstanding Notice of Violation (“NOV”) from the EPA pertaining to its Brown generating station sulfur trioxide emissions. The MATS rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two subcategories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants.
Indiana Electric has completed investments of $30 million on equipment to control mercury in both air and water emissions, and $40 million to address the issues raised in the NOV. The Order approved Indiana Electric’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014 and the remaining investment went into service in 2016. At December 31, 2018 and December 31, 2017, respectively, Indiana Electric had regulatory assets totaling $18.6 million and $12.8 million related to depreciation and operating expenses and $6.5 million and $4.7 million related to post-in-service carrying costs. MATS compliance was required beginning April 16, 2015 and Indiana Electric continues to operate in full compliance with the MATS rule.
On February 20, 2018, as part of the electric generation transition plan case discussed below, Indiana Electric filed a request to commence recovery, under Senate Bill 251, of its already approved investments associated with the MATS and NOV Compliance Projects, including recovery of the authorized deferred balance. As proposed, recovery would reflect 80 percent of the authorized costs, including a return, recovery of depreciation and incremental operating expenses, and recovery of the prior deferred balance over a proposed period of 15 years. The remaining 20 percent will be deferred until Indiana Electric’s next base rate proceeding. In April 2019, Indiana Electric received approval for its request to commence recovery. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters” in the 2nd Quarter 2019 10-Q.
SIGECO Electric Demand Side Management (DSM) Program Filing
On March 28, 2014, Indiana Senate Bill 340 was signed into law. The legislation allows for industrial customers to opt out of participating in energy efficiency programs and as a result of this legislation, customers representing most of the eligible load have since opted out of participation in the applicable energy efficiency programs.
Indiana Senate Bill 412 (“Senate Bill 412”) requires electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also requires the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. Indiana Electric made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. On March 23, 2016, the IURC issued an Order approving Indiana Electric’s 2016-2017 energy efficiency plan. The Order provided for cost recovery of program and administrative expenses and included performance incentives for reaching energy savings goals.
The Order also included a lost margin recovery mechanism that would have limited recovery related to new programs to the shorter of four years or the life of the installed energy efficiency measure. Prior electric energy efficiency orders did not limit lost margin recovery in this manner. This ruling followed other IURC decisions implementing the same lost margin recovery limitation with respect to other electric utilities in Indiana. Indiana Electric appealed this lost margin recovery restriction based on Indiana Electric’s commitment to promote and drive participation in its energy efficiency programs.
On March 7, 2017, the Indiana Court of Appeals reversed the IURC finding on Indiana Electric’s 2016-2017 energy efficiency plan that the four year cap on lost margin recovery was arbitrary and the IURC failed to properly interpret the governing statute requiring it to review the utility’s originally submitted DSM proposal and either approve or reject it as a whole, including the proposed lost margin recovery. The case was remanded to the IURC for further proceedings. On June 13, 2017, Indiana Electric filed additional testimony supporting the plan. In response to the proposals to cap lost margin recovery, Indiana Electric filed supplemental testimony that supported lost margin recovery based on the average measure life of the plan, estimated at nine years, on 90 percent of the direct energy savings attributed to the programs. Testimony of intervening parties was filed on July 26, 2017, opposing Indiana Electric’s proposed lost margin recovery. An evidentiary hearing was held in September 2017. On December 20, 2017, the IURC issued an order approving the DSM Plan for 2016-2017 including the recovery of lost margins consistent with Indiana Electric’s proposal. On January 22, 2018, certain intervening parties initiated an appeal to the Indiana Court of Appeals. On March 7, 2019, the Indiana Court of Appeals issued its decision upholding the IURC’s Order and denying the appeal raised by the intervening parties.
On April 10, 2017, Indiana Electric submitted its request for approval to the IURC of its Energy Efficiency Plan for calendar years 2018 through 2020. Consistent with prior filings, this filing included a request for continued cost recovery of program and administrative expenses, including performance incentives for reaching energy savings goals and continued recovery of lost margins consistent with the modified proposal in the 2016-2017 plan. Filed testimony of intervening parties was received on July 26, 2017, opposing Indiana Electric’s proposed lost margin recovery. An evidentiary hearing was held in September 2017. On December 28, 2017, the IURC issued an order approving the 2018 through 2020 Plan, inclusive of recovery of lost margins consistent with the Order issued on December 20, 2017. On January 26, 2018, certain intervening parties initiated an appeal to the Indiana Court of Appeals. On February 19, 2019, the Indiana Court of Appeals issued its decision upholding IURC’s Order and denying the appeal raised by the intervening parties.
For the twelve months ended December 31, 2018, 2017, and 2016, Indiana Electric recognized electric utility revenue of $12.3 million, $11.6 million, and $11.1 million, respectively, associated with lost margin recovery approved by IURC.
Electric Generation Transition Plan
For a description of Indiana Electric’s 2016 Integrated Resource Plan (“IRP”) for SIGECO, including a description of the IURC’s order denying a proposed new 700-850 MW natural gas combined cycle generating facility to be constructed by SIGECO and other updates as of June 30, 2019, please see the 2018 Form 10-K and the 2019 Form 10-Qs.
Other Generation Developments
On September 21, 2017, CenterPoint Energy and Alcoa Corporation agreed to continue the joint ownership and operation of Warrick through 2023.
Environmental Matters
CenterPoint Energy’s Indiana and Ohio natural gas and electric utility operations are subject to extensive environmental regulation pursuant to a variety of federal, state, and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others. Environmental legislation and regulation also requires that facilities, sites, and other properties associated with CenterPoint Energy’s operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. CenterPoint Energy’s current costs to comply with these laws and regulations are significant to its results of operations and financial condition. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO’s electric operations.
The below description should be read in conjunction with “Risk Factors” in the 2018 Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters” and Note 14 to the Unaudited Condensed Consolidated Financial Statements in each of the 2019 Form 10-Qs which provide a description of environmental matters pertaining to CenterPoint Energy’s Indiana and Ohio natural gas and electric utility operations, including updates as of June 30, 2019 to certain of the matters described below. The discussion below relates solely to CenterPoint Energy’s Indiana and Ohio natural gas and electric utility operations.
Coal Combustion Residuals Rule
For a description of the applicability of the Environmental Protection Agency’s Coal Combustion Residuals rule (the “CCR Rule”), please see Note 14 to the Unaudited Condensed Consolidated Financial Statements in each of the 2019 Form 10-Qs.
As disclosed in the 2nd Quarter 2019 10-Q, the CCR Rule required companies to complete location restriction determinations relating to ash ponds by October 18, 2018. Indiana Electric completed its evaluation and determination that one F.B. Culley pond and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, Indiana Electric is required to cease disposal of new ash ponds and commence closure of the ponds by October 31, 2020.
Indiana Electric expects to file a request with the IURC to recover the cost of closing the ash pond at its Brown facility and anticipates seeking authority to recover these costs in accordance with the framework of Senate Bill 251. While Indiana Electric continues to refine site specific estimates of closure costs, Indiana Electric currently estimates such closure will require approximately $74 million in capital investments and $90 million in expenses over at least a 14 year period.
Effluent Limitation Guidelines (“ELG”)
For a description of the applicability of the Environmental Protection Agency’s Effluent Limitation Guidelines, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters—ELG” in each of the 2019 Form 10-Qs.
Clean Power Plan and ACE Rule
On August 3, 2015, the EPA released its final Clean Power Plan rule (“CPP”) which required a 32 percent reduction in carbon emissions from 2005 levels. This would result in a final emission rate goal for Indiana of 1,242 lb CO2/MWh to be achieved by 2030 and implemented through a state implementation plan. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies, including the 24 state coalition referenced above, filed a request for immediate stay of implementation of the rule with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted the stay request to delay the implementation of the regulation while being challenged in court. Oral argument was held in September 2016. The stay will remain in place while the lower court concludes its review. In March 2017, as part of the ongoing regulatory reform efforts of the Administration, the EPA filed a motion with the U.S. Court of Appeals for the District of Columbia circuit to suspend litigation pending the EPA’s reconsideration of the CPP rule, which was granted on April 28, 2017. Moreover, as indicated above, in October 2017, EPA published its proposal to repeal the CPP. Comments to the repeal proposal were due in April 2018. EPA’s repeal proposal was quickly followed by an advanced notice of proposed rulemaking intended to solicit public comments on issues related to formulating a CPP replacement rule, which were similarly due in April 2018.
On August 31, 2018, EPA published its proposed CPP replacement rule, the Affordable Clean Energy (ACE) rule, which if finalized, would require that each state set unit by unit heat rate performance standards, considering such factors as remaining useful life. The ACE rule was finalized on July 8, 2019. Under the ACE rule, states have three years to develop implementation programs and the EPA has 18 months to approve these plans, making compliance likely in 2023-2024.
For an update on the EPA’s Clean Power Plan and ACE Rule, please see “Risk Factors in the 2018 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters—CPP and ACE Rule” in each of the 2019 Form 10-Qs.
Impact of Legislative Actions & Other Initiatives
For a description the Impact of Legislative Actions & Other Initiatives, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries—Liquidity and Capital Resources—Regulatory Matters—Impact of Legislative Actions & Other Initiatives” in each of the 2019 Form 10-Qs.
Manufactured Gas Plants
For a description of the applicability of the Manufactured Gas Plants, please see Note 14 to the Unaudited Condensed Consolidated Financial Statements in each of the 2019 Form 10-Qs.
| Item 9.01 | Financial Statements and Exhibits |
The exhibit listed below is filed herewith.
(d) Exhibits.
| EXHIBIT NUMBER |
EXHIBIT DESCRIPTION | |||
| 104 |
Cover Page Interactive Data File – the cover page XBRL tags are embedded within the Inline XBRL document. | |||
Cautionary Statements Regarding Forward-Looking Statements
This Current Report on Form 8-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based upon assumptions of management which are believed to be reasonable at the time made and are subject to significant risks and uncertainties. Actual events and results may differ materially from those expressed or implied by these forward-looking statements. Any statements in this Current Report on Form 8-K regarding future actions, financial performance and results of operations, including, but not limited to Indiana Electric’s expected filing with the IURC to request the recovery of the cost of closing the ash pond at its Brown generation facility, expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and any other statements that are not historical facts are forward-looking statements. Each forward-looking statement contained in this Current Report on Form 8-K speaks only as of the date of this Current Report on Form 8-K. Factors that could affect actual results include timing and impact of future regulatory and legislative decisions, weather variations, effects of competition, changes in business plans and other factors discussed in CenterPoint Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 and other reports CenterPoint Energy or its subsidiaries may file from time to time with the Securities and Exchange Commission.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| CENTERPOINT ENERGY, INC. | ||||||
| Date: August 12, 2019 |
By: |
/s/ Kristie L. Colvin | ||||
| Kristie L. Colvin | ||||||
| Senior Vice President and Chief Accounting Officer | ||||||