# ONE Gas, Inc.: Form 10-Q for the period ended Jun 30, 2022

- Company: [ONE Gas, Inc.](/companies/ogs.md) (CIK 1587732)
- Form: 10-Q
- Filed: 2022-08-02
- Accepted by EDGAR: Aug 2, 2022, 16:20 ET
- Period: 2022-06-30
- Accession: 0001587732-22-000061
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1587732/000158773222000061/ogs-20220630.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1587732/000158773222000061/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2022-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Cost of revenue | 3 months, 2022-04-01 to 2022-06-30 | $188.3m | us-gaap:CostOfGoodsAndServicesSold |
| Cost of revenue | 6 months, 2022-01-01 to 2022-06-30 | $828.2m | us-gaap:CostOfGoodsAndServicesSold |
| Operating income | 3 months, 2022-04-01 to 2022-06-30 | $58.6m | us-gaap:OperatingIncomeLoss |
| Operating income | 6 months, 2022-01-01 to 2022-06-30 | $199.3m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2022-04-01 to 2022-06-30 | $16.3m | us-gaap:InterestExpense |
| Interest expense | 6 months, 2022-01-01 to 2022-06-30 | $31.9m | us-gaap:InterestExpense |
| Income tax | 3 months, 2022-04-01 to 2022-06-30 | $6.2m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2022-01-01 to 2022-06-30 | $28.3m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2022-04-01 to 2022-06-30 | $32.1m | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2022-01-01 to 2022-06-30 | $131.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2022-04-01 to 2022-06-30 | $0.59 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2022-01-01 to 2022-06-30 | $2.42 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2022-04-01 to 2022-06-30 | $0.59 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2022-01-01 to 2022-06-30 | $2.42 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2022-04-01 to 2022-06-30 | 54,335,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2022-01-01 to 2022-06-30 | 54,183,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2022-01-01 to 2022-06-30 | $286.7m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 6 months, 2022-01-01 to 2022-06-30 | $251.1m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 6 months, 2022-01-01 to 2022-06-30 | $66.8m | us-gaap:PaymentsOfDividends |
| Current assets | at 2022-06-30 | $2.15bn | us-gaap:AssetsCurrent |
| Total assets | at 2022-06-30 | $8.41bn | us-gaap:Assets |
| Current liabilities | at 2022-06-30 | $2.33bn | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2022-06-30 | $2.28bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2022-06-30 | $1.40bn | us-gaap:LongTermDebtCurrent |
| Short-term borrowings | at 2022-06-30 | $490.1m | us-gaap:CommercialPaper |
| Shareholders' equity | at 2022-06-30 | $2.45bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 86,859 characters.

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2022 are not necessarily indicative of the results that may be expected for a 12-month period.

### RECENT DEVELOPMENTS

Winter Storm Uri - In February 2021, the U.S. experienced Winter Storm Uri, a historic winter weather event impacting supply, market pricing and demand for natural gas in a number of states, including our service territories of Oklahoma, Kansas, and Texas. During this time, the governors of Oklahoma, Kansas, and Texas each declared a state of emergency, and certain regulatory agencies issued emergency orders that impacted the utility and natural gas industries, including statewide utility curtailment programs and orders requiring jurisdictional natural gas and electric utilities to do all things possible and necessary to ensure that natural gas and electricity utility services continued to be provided to their customers. Due to the historic nature of this winter weather event, we experienced unforeseeable and unprecedented market pricing for gas costs in our Oklahoma, Kansas, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month of February 2021 of approximately $2.1 billion.

On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri.

In March 2021, we issued $1.0 billion of 0.85 percent senior notes due March 2023, $700 million of 1.10 percent senior notes due March 2024, and $800 million of floating-rate senior notes due March 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year, reset quarterly for the applicable interest period (2.35 percent at June 30, 2022). The net proceeds from the issuance were used for payment of gas purchases and related costs resulting from Winter Storm Uri and general corporate purposes. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

On September 21, 2021, we called $400 million of the floating-rate senior notes due March 2023 at par, using a combination of cash on hand and commercial paper. We did not have the right to call these senior notes prior to September 11, 2021.

Our purchased gas costs are recoverable through the tariffs in each state where we operate. Due to the higher level of gas purchase costs during Winter Storm Uri, related financing costs and other operational response costs, we are working with regulators to extend the recovery periods of such costs in order to lessen the immediate customer impact. In that regard, the OCC, KCC and the RRC each authorized certain utilities, including LDCs, to record regulatory assets to account for the extraordinary costs associated with this winter weather event, including but not limited to gas purchase costs and other costs related to the procurement and transportation of gas supply, carrying costs and other operational costs. As of June 30, 2022, we have deferred approximately $1.9 billion in costs associated with Winter Storm Uri.

In the second quarter of 2021, legislation in Oklahoma, Kansas and Texas was approved that permits utilities to pursue securitization to finance extraordinary expenses, such as fuel costs, incurred during extreme weather events. We have received or are currently seeking approval from our regulators to utilize the securitization legislation in each state to repay or refinance the debt we incurred to finance the extraordinary costs associated with Winter Storm Uri.

See “Regulatory Activities,” “Liquidity and Capital Resources,” and Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the effects of Winter Storm Uri on us.

ONE Gas Credit Agreement - On March 16, 2022, we entered into the first amendment to the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the maturity date of the ONE Gas Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changes the benchmark rate defined in the ONE Gas Credit Agreement to SOFR as administered by the Federal Reserve Bank of New York. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.

In connection with the second amendment and restatement of the ONE Gas Credit Agreement on March 16, 2021, all commitments under our ONE Gas 364-day Credit Agreement, dated as of April 7, 2020, were terminated and all obligations under the ONE Gas 364-day Credit Agreement were paid in full and discharged.

ONE Gas Commercial Paper Program - On June 22, 2021, we increased the size of our commercial paper program to permit the issuance of commercial paper to fund short-term borrowing needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time.

COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and communities.

We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At June 30, 2022, no regulatory assets have been recorded. In Oklahoma, the test period for our recently completed rate case included the impacts of COVID-19 on our cost of service in determining new rates that became effective in November 2021. In addition, annual PBRC filings, including the PBRC filing made in March 2022, allow us to include any impacts from COVID-19 in our test period cost of service to determine the impact on our rates. In Kansas and Texas, we continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.

See Notes 3 and 12 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion regarding the effects of COVID-19 on us.

Dividend - In July 2022, we declared a dividend of $0.62 per share ($2.48 per share on an annualized basis) for shareholders of record as of August 15, 2022, payable on September 1, 2022.

### REGULATORY ACTIVITIES

Oklahoma - In April 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to newly enacted securitization legislation in Oklahoma. On January 25, 2022, the OCC approved the financing order that reflected the terms of a settlement agreement reached in November 2021, which includes an agreement that all extreme gas purchase and extraordinary costs incurred as a result of Winter Storm Uri were reasonable and prudent and a financing order should be issued to recover these costs through securitization over a 25-year period. Following the issuance of the financing order, no parties to our application appealed the financing order to the Oklahoma Supreme Court during the 30-day appeal period. The securitization legislation allows the ODFA 24 months to complete the process to issue the securitized bonds; however, the financing order requests the ODFA to issue bonds and provide the net proceeds to Oklahoma Natural Gas as soon as feasible, but no later than December 31, 2022. Pursuant to the securitization statute in Oklahoma, the Oklahoma Supreme Court must validate that the bond issuance proposed by the ODFA complies with the securitization statute and the laws of Oklahoma. The ODFA received a hearing before the Oklahoma Supreme Court on April 13, 2022, seeking validation of the bond issuance. On May 24, 2022, validation was received from the Oklahoma Supreme Court. On July 15, 2022, the ODFA began the marketing process for the bonds. Bonds are expected to be issued and proceeds received in the third quarter of 2022. At June 30, 2022, Oklahoma Natural Gas has deferred approximately $1.3 billion in extraordinary costs attributable to Winter Storm Uri.

As required, PBRC filings are made annually on or before March 15, until the next general rate case which is required to be filed on or before June 30, 2027. On March 15, 2022, Oklahoma Natural Gas filed its required PBRC application for a calendar year 2021 test year. The filed request includes a $19.7 million base rate revenue increase, $2.3 million energy efficiency incentive, and $9.1 million of estimated EDIT to be credited to customers in 2023. On May 27, 2022, the Public Utility Division (“PUD”) of the OCC filed responsive testimony supporting an increase of $19.6 million. On May 31, 2022, the Office of the Attorney General filed a statement of position supporting PUD’s position. Pursuant to its tariff, Oklahoma Natural Gas placed new rates into effect on July 13, 2022, reflecting a base rate revenue increase of $19.6 million. These rates are subject to refund until approved by the OCC. We expect a hearing to be scheduled in September 2022.

As required by OCC rule, on April 6, 2022, Oklahoma Natural Gas filed a request for approval of a demand portfolio of conservation and energy efficiency programs for calendar years 2023-2025. The request includes an annual portfolio of program costs of $17.4 million with an estimated annual utility incentive of $2.6 million.

In May 2021, Oklahoma Natural Gas filed a general rate case. In October 2021, a joint stipulation and settlement agreement was signed by all parties to the rate case. In November 2021, the OCC issued an order approving the joint stipulation and settlement agreement. Upon approval of the order, Oklahoma Natural Gas’ base rates increased by $15.3 million. Premised on a return on equity of 9.4 percent and a common equity ratio of 58.55 percent, the order also includes the continuation of the PBRC tariff that was established in 2009. The approved order also states that Oklahoma Natural Gas may recover commodity costs of no more than $5.0 million annually for the purchase of RNG and that Oklahoma Natural Gas shall file an application on or before December 31, 2022, requesting approval of an RNG pilot program including an “opt-in” tariff allowing Oklahoma Natural Gas to allocate costs and benefits of RNG to those customers who choose RNG for their fuel source.

In May 2021, a bill amending the Oklahoma state income tax code was signed into law that reduced the state income tax rate to four percent from six percent beginning January 1, 2022. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $29.3 million was recorded as a regulatory liability. The impact of the change in the state income tax rate on Oklahoma Natural Gas’ rates, as well as the timing and amount of the impact on the annual crediting mechanism for the EDIT regulatory liability, is included in the March 15, 2022 PBRC filing, which is pending approval by the OCC.

Kansas - In March 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific dockets to accept each utility’s filing of financial impact compliance reports and permit the KCC staff to conduct a review of the utility’s compliance report and its actions during Winter Storm Uri.

In May 2021, Kansas Gas Service filed a motion in its company-specific docket opened by the KCC, requesting a limited waiver of the penalty provisions of its tariff to eliminate the multipliers in the penalty calculation when calculating the penalties to assess on marketers and individually-balanced transportation customers for their unauthorized natural gas usage during Winter Storm Uri. In October 2021, a nonunanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. Prior to a hearing on the amended settlement in January 2022, all parties reached a unanimous settlement, which was filed with a motion requesting approval of the unanimous settlement. Under the terms of the unanimous settlement, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. On March 3, 2022, the KCC issued an order approving the settlement, which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties will reduce the regulatory asset for the winter weather event, up to $52.6 million. Through June 30, 2022, we collected $48.3 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from its customers over a period of either 5, 7, or 10 years. The KCC issued an order approving a unanimous settlement agreement on February 8, 2022, that allows Kansas Gas Service to recover extraordinary costs as of October 31, 2021, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs calculated at two percent, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds.

On March 31, 2022, Kansas Gas Service submitted its application for a financing order to the KCC as contemplated by the unanimous settlement agreement, requesting approval to issue securitized bonds to recover extraordinary costs resulting from Winter Storm Uri and flexibility to recover the costs over 5, 7, 10 or 12 years. On July 14, 2022, Kansas Gas Service, the KCC Staff and the Citizens’ Utility Ratepayer Board reached a settlement agreement for the issuance of a financing order allowing the Company to issue securitized utility tariff bonds in the amount of approximately $328.0 million plus issuance fees. The final amount to be securitized will be provided in the final Issuance Advice Letter. The agreement provides for the issuance of bonds with a scheduled final maturity of between 7 and 10 years with flexibility within that range, if necessary, to achieve a AAA rating. The KCC has until September 27, 2022, to issue a financing order if it deems the issuance of the securitized bonds to be appropriate. If the KCC approves the financing order, we can begin the process to issue the securitized bonds. At June 30, 2022, Kansas Gas Service has deferred approximately $337.7 million in extraordinary costs, net of penalties billed, attributable to Winter Storm Uri. The amount deferred at June 30, 2022, in excess of the amount to be securitized, primarily includes accrued costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. These amounts will be recovered through our purchased gas cost mechanisms or other regulatory filings and may be adjusted as the differences are resolved.

In August 2021, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $7.6 million related to its GSRS. The KCC issued an order in November 2021, and the new surcharge became effective on December 1, 2021.

In May 2020, a bill amending the Kansas state income tax code was signed into law that exempts public utilities regulated by the KCC from paying Kansas state income taxes beginning January 1, 2021, and authorizes the KCC to adjust utility rates for the elimination of Kansas state income tax beginning January 1, 2021. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $84.2 million was recorded as a regulatory liability and will be refunded to our customers. This adjustment had no material impact on our income tax expense and no impact on our cash flows for the six months ended June 30, 2022. The bill stipulates that, if requested by the utility, this EDIT will be returned to Kansas customers over a period of no less than 30 years, with the exact timing to be determined in our next general rate proceeding. In August 2020, Kansas Gas Service submitted an application to the KCC to reduce its base rates to reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the reduction, effective January 1, 2021.

Texas -Pursuant to securitization legislation enacted in Texas as a result of Winter Storm Uri and a June 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC on July 30, 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.

In November 2021, the RRC approved a unanimous settlement agreement between Texas Gas Service, the other natural gas utilities in Texas participating in the securitization process, the staff of the RRC and all intervenors. The settlement agreement provides that all costs incurred by Texas Gas Service to purchase natural gas during Winter Storm Uri were reasonable, necessary and prudently incurred. Texas Gas Service agreed to reduce its regulatory asset amount to be securitized by the amount of extraordinary costs attributable to the West Texas service area, which will be recovered through a separate surcharge over a three-year period.

On February 8, 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The TPFA formed the Texas Natural Gas Securitization Finance Corporation, a new independent public authority, for purposes of issuing the securitized bonds and has begun the process to issue the securitized bonds, which are expected to be issued in the fourth quarter of 2022. At June 30, 2022, Texas Gas Service has deferred approximately $246.7 million in extraordinary costs associated with Winter Storm Uri, which includes $48.5 million attributable to the West Texas service area. Pursuant to the approved settlement order, in January 2022, Texas Gas Service began collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the West Texas service area from those customers.

*West Texas Service Area -* In March 2022, Texas Gas Service made GRIP filings for all customers in the West Texas service area, requesting a $5.0 million increase to be effective in July 2022. On June 23, 2022, the city of El Paso denied the requested increase and assessed fees associated with its review of the filing. Texas Gas Service appealed the city’s action to the RRC. All other municipalities, and the RRC, approved the new rates or allowed them to take effect with no action. Texas Gas Service implemented the new rates in July 2022, pending the outcome of the appeal.

On June 30, 2022, Texas Gas Service filed a rate case seeking to consolidate its West Texas, North Texas and Borger/Skellytown service areas into a single West-North service area and requesting a rate increase of $13.0 million. If approved, new rates are expected to take effect in the first quarter of 2023.

In March 2021, Texas Gas Service made GRIP filings for all customers in the West Texas service area, requesting an increase of $9.7 million to be effective in July 2021. On June 21, 2021, the city of El Paso approved a motion which found the GRIP filing to be in compliance with the GRIP statute. The city subsequently denied the requested increase and assessed fees associated with its review of the filing. On July 2, 2021, Texas Gas Service appealed the city’s action to the RRC. The RRC granted and approved the appeal, and new rates were effective on August 3, 2021. All other municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.

*Central-Gulf Service Area* - In February 2022, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting a $9.1 million increase effective in June 2022. All municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.

In February 2021, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting an increase of $10.7 million to be effective in June 2021. All municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.

*Other Texas Service Areas* - In April 2022, Texas Gas Service filed its annual COSA filings for the incorporated area of the Rio Grande Valley service area, requesting an increase of $2.9 million. In July 2022, the municipalities approved an increase of $2.5 million, and new rates will become effective in August 2022.

In April 2021, Texas Gas Service made its annual COSA filings for the incorporated areas of the Rio Grande Valley service area and the North Texas service area. In July 2021, the municipalities in the Rio Grande Valley and North Texas service areas agreed to increases of $3.5 million and $1.4 million, respectively. New rates became effective in August 2021.

In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and COSA increases in various other Texas jurisdictions to address investments in rate base and changes in expenses. For the six months ended June 30, 2022, no annual rate increases associated with these filings have been approved and $0.4 million were approved for the year ended December 31, 2021.

Winter Storm Uri Deferred Costs - In accordance with regulatory orders associated with this winter weather event, we have deferred approximately $1.9 billion in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs. The amounts deferred at June 30, 2022, include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. In addition, as a result of Winter Storm Uri, we were assessed penalties as a result of over- or under-deliveries of natural gas during periods that operational flow orders were imposed on us. Additionally, Kansas Gas Service assessed penalties under the modified penalty provisions of its tariff on marketers and individually-balanced transportation customers, or their agents, as approved by the KCC in March 2022. Amounts recorded reflect management’s best estimate of the amounts we may pay or receive and may be adjusted in future periods as the disposition of disputed invoices and the collectability of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments to the amounts we have deferred are not expected to have a material impact on earnings.

### FINANCIAL RESULTS AND OPERATING INFORMATION

We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on net income.

**Selected Financial Results -** For the three months ended June 30, 2022, net income was $32.1 million, or $0.59 per diluted share, compared with $30.1 million, or $0.56 per diluted share, in the same period last year. For the six months ended June 30, 2022, net income was $131.0 million, or $2.42 per diluted share, compared with $125.7 million, or $2.35 per diluted share, in the same period last year.

The following table sets forth certain selected financial results for our operations for the periods indicated:

*(Millions of dollars, except percentages)*

| Financial Results | Three Months Ended June 30, 2022 | 2021 | Six Months Ended June 30, 2022 | 2021 | Three Months 2022 vs. 2021 Increase (Decrease) |  | Six Months 2022 vs. 2021 Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Natural gas sales | **$393.2** | $282.6 | **$1,320.2** | $865.4 | **$110.6** | **39%** | **$454.8** | **53%** |
| Transportation revenues | **28.0** | 26.3 | **64.8** | 62.5 | **1.7** | **6%** | **2.3** | **4%** |
| Other revenues | **7.8** | 6.7 | **15.4** | 13 | **1.1** | **16%** | **2.4** | **18%** |
| Total revenues | **429.0** | 315.6 | **1,400.4** | 940.9 | **113.4** | **36%** | **459.5** | **49%** |
| Cost of natural gas | **188.3** | 93.7 | **828.2** | 407.8 | **94.6** | **101%** | **420.4** | **103%** |
| Operating costs | **127.1** | 120.0 | **260.7** | 248.6 | **7.1** | **6%** | **12.1** | **5%** |
| Depreciation and amortization | **55.0** | 50.8 | **112.2** | 103.1 | **4.2** | **8%** | **9.1** | **9%** |
| Operating income | **$58.6** | $51.1 | **$199.3** | $181.4 | **$7.5** | **15%** | **$17.9** | **10%** |
| Capital expenditures and asset removal costs | **$149.1** | $129.4 | **$272.0** | $238.4 | **$19.7** | **15%** | **$33.6** | **14%** |

Natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariffs and rates approved by the regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales. Additionally, natural gas sales includes the recovery of our cost of natural gas.

Our natural gas sales include fixed and variable charges related to the delivery of natural gas and gas costs that are passed through to our customers in accordance with our cost of natural gas regulatory mechanisms. Fixed charges reflect the portion of our natural gas sales attributable to the monthly fixed customer charge component of our rates, which does not fluctuate based on customer usage in each period. Variable charges reflect the portion of our natural gas sales that fluctuate with the volumes delivered and billed and the effects of weather normalization.

Transportation revenues represent revenue from contracts with customers through implied contracts established by our tariffs and rates approved by the regulatory authorities, as well as tariff-based negotiated contracts.

Other revenues include primarily miscellaneous service charges which represent implied contracts with customers established by our tariffs and rates approved by the regulatory authorities and other revenues from regulatory mechanisms.

Cost of natural gas includes commodity purchases, fuel, storage, transportation, hedging costs and settlement proceeds for natural gas price volatility mitigation programs approved by our regulators and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. These regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Therefore, although our revenues will fluctuate with the cost of natural gas that we pass-through to our customers, operating income is not affected by fluctuations in the cost of natural gas.

Operating income increased $7.5 million for the three months ended June 30, 2022, compared with the same period last year, due primarily to the following:

- an increase of $14.4 million from new rates; and
- an increase of $1.5 million in residential sales due primarily to net customer growth in Oklahoma and Texas.

These increases were offset partially by:

- an increase of $5.8 million in outside service costs; and
- an increase of $0.7 million in employee-related costs, which reflects $3.3 million of higher labor and employee benefit costs, offset partially by a $2.7 million decrease in expenses associated with the change in our nonqualified employee benefit plan liabilities.

Operating income increased $17.9 million for the six months ended June 30, 2022, compared with the same period last year, due primarily to the following:

- an increase of $29.5 million from new rates;
- an increase of $4.1 million in residential sales due primarily to net customer growth in Oklahoma and Texas;
- a decrease of $3.0 million in bad debt expense; and
- an increase of $1.2 million in late payment, reconnect and collection fees.

These increases were offset partially by:

- an increase of $9.5 million in outside service costs;
- an increase of $9.1 million in depreciation expense due to additional capital expenditures being placed in service; and
- an increase of $2.9 million in employee-related costs, which reflects $5.4 million of higher labor and employee benefit costs, offset partially by a $2.5 million decrease in expenses associated with the change in our nonqualified employee benefit plan liabilities.

Other Factors Affecting Net Income - Other factors that affected net income for the three months ended June 30, 2022, compared with the same period last year, include an increase of $4.4 million in other expense, net, due primarily to a $6.5 million decrease in the market value of investments associated with our nonqualified employee benefit plans, offset partially by a $2.4 million decrease in net periodic benefit costs other than service costs.

Other factors that affected net income for the six months ended June 30, 2022, compared with the same period last year, include an increase of $8.2 million in other expense, net, due primarily to a $10.0 million decrease in the market value of investments associated with our nonqualified employee benefit plans, offset partially by a $2.6 million decrease in net periodic benefit costs other than service costs.

EDIT - Income tax expense reflects credits for the amortization of the regulatory liability associated with EDIT that was returned to customers of $3.0 million and $2.6 million for the three months ended June 30, 2022 and 2021, respectively, and credits of $10.9 million and $10.7 million for the six months ended June 30, 2022 and 2021, respectively.

Capital Expenditures and Asset Removal Costs - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, increasing system capabilities, pipeline replacements, automated meter reading, government-mandated pipeline relocations, fleet, facilities, IT assets and cybersecurity. It is our practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations. Asset removal costs include expenditures associated with the replacement or retirement of long-lived assets that result from the construction, development and/or normal use of our assets, primarily our pipeline assets. While we have not experienced a significant impact to our capital expenditures program in the six months ended June 30, 2022, our capital expenditure activity for the remainder of the year could experience a delay if economic conditions worsen, impacting our supply chain for contract labor, materials and supplies.

Capital expenditures and asset removal costs were $19.7 million and $33.6 million higher for the three and six months ended June 30, 2022, respectively, compared with the same period last year, due primarily to expenditures for system integrity and extension of service to new areas. Our full-year capital expenditures and asset removal costs are expected to be approximately $650 million for 2022.

**Selected Operating Information -** The following tables set forth certain selected operating information for the periods indicated:

*(in thousands)*

| Average Number of Customers | Three Months Ended June 30, 2022 OK | KS | TX | Total | 2021 OK | KS | TX | Total | Variances 2022 vs. 2021 Increase (Decrease) OK | KS | TX | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Residential | **833** | **593** | **658** | **2,084** | 826 | 593 | 651 | 2,070 | **7** | **—** | **7** | **14** |
| Commercial and industrial | **77** | **51** | **35** | **163** | 76 | 50 | 35 | 161 | **1** | **1** | **—** | **2** |
| Other | **—** | **—** | **3** | **3** | — | — | 3 | 3 | **—** | **—** | **—** | **—** |
| Transportation | **5** | **6** | **1** | **12** | 5 | 6 | 1 | 12 | **—** | **—** | **—** | **—** |
| Total customers | **915** | **650** | **697** | **2,262** | 907 | 649 | 690 | 2,246 | **8** | **1** | **7** | **16** |

*(in thousands)*

| Average Number of Customers | Six Months Ended June 30, 2022 OK | KS | TX | Total | 2021 OK | KS | TX | Total | Variances 2022 vs. 2021 Increase (Decrease) OK | KS | TX | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Residential | **834** | **595** | **656** | **2,085** | 826 | 594 | 649 | 2,069 | **8** | **1** | **7** | **16** |
| Commercial and industrial | **77** | **51** | **36** | **164** | 77 | 50 | 35 | 162 | **—** | **1** | **1** | **2** |
| Other | **—** | **—** | **3** | **3** | — | — | 3 | 3 | **—** | **—** | **—** | **—** |
| Transportation | **5** | **6** | **1** | **12** | 5 | 6 | 1 | 12 | **—** | **—** | **—** | **—** |
| Total customers | **916** | **652** | **696** | **2,264** | 908 | 650 | 688 | 2,246 | **8** | **2** | **8** | **18** |

The increase in the average number of customers for the periods presented, is due primarily to the connection of new customers resulting from the extension and expansion of our system in our service areas. For the three months ended June 30, 2022, our average customer count includes approximately 5,700 new customer connections during the period compared to approximately 5,400 for the same period last year. For the six months ended June 30, 2022, our average customer count includes approximately 12,400 new customer connections during the period compared to approximately 11,300 for the same period last year. For the year ended December 31, 2021, our average customer count included approximately 24,900 new customer connections.

The following table reflects total volumes delivered, excluding the effects of WNA mechanisms on sales volumes:

| Volumes (MMcf) Natural gas sales | Three Months Ended June 30, 2022 | 2021 | Six Months Ended June 30, 2022 | 2021 |
| --- | ---: | ---: | ---: | ---: |
| Residential | **13,790** | 14,802 | **74,440** | 77,781 |
| Commercial and industrial | **6,188** | 5,617 | **25,557** | 24,106 |
| Other | **564** | 421 | **1,675** | 1,502 |
| Total sales volumes delivered | **20,542** | 20,840 | **101,672** | 103,389 |
| Transportation | **53,392** | 52,457 | **120,463** | 116,776 |
| Total volumes delivered | **73,934** | 73,297 | **222,135** | 220,165 |

The impact of weather on residential and commercial natural gas sales is mitigated by WNA mechanisms in all jurisdictions.

The following table sets forth the HDDs by state for the periods indicated:

| Heating Degree Days | Three Months Ended June 30, 2022 Actual | Normal | 2021 Actual | Normal | 2022 vs. 2021 Actual Variance | 2022 Actual as a percent of Normal | 2021 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Oklahoma | **219** | **228** | 274 | 191 | **(20)%** | **96%** | 143% |
| Kansas | **399** | **394** | 415 | 394 | **(4)%** | **101%** | 105% |
| Texas | **17** | **50** | 62 | 50 | **(73)%** | **34%** | 124% |

| Heating Degree Days | Six Months Ended June 30, 2022 Actual | Normal | 2021 Actual | Normal | 2022 vs. 2021 Actual Variance | 2022 Actual as a percent of Normal | 2021 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Oklahoma | **2,204** | **2,020** | 2,319 | 1,966 | **(5)%** | **109%** | 118% |
| Kansas | **2,931** | **2,855** | 2,905 | 2,855 | **1%** | **103%** | 102% |
| Texas | **1,199** | **1,049** | 1,127 | 1,050 | **6%** | **114%** | 107% |

Normal HDDs are established through rate proceedings in each of our jurisdictions for use primarily in weather normalization billing calculations. See further discussion on weather normalization in our Regulatory Overview section in Part 1, Item 1, “Business,” of our Annual Report. Normal HDDs disclosed above are based on:

- *Oklahoma* - For years 2021 through the current period, 10-year weighted average HDDs as of June 30, 2021, as calculated using 11 weather stations across Oklahoma and weighted on average customer count.
- *Kansas* - For April 2019 and forward, a 30-year rolling average for years 1988-2017 calculated using three weather stations across Kansas and weighted on HDDs by weather station and customers.
- *Texas* - An average of HDDs authorized in our most recent rate proceeding in each jurisdiction and weighted using a rolling 10-year average of actual natural gas distribution sales volumes by service area.

Actual HDDs are based on the quarter-to-date weighted average of:

- 11 weather stations and customers by month for Oklahoma;
- 3 weather stations and customers by month for Kansas; and
- 9 weather stations and natural gas distribution sales volumes by service area for Texas.

### CONTINGENCIES

We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.

### LIQUIDITY AND CAPITAL RESOURCES

**General -** We have relied primarily on operating cash flow and commercial paper for our liquidity and capital resource requirements. We fund operating expenses, working capital requirements, including purchases of natural gas other than the extraordinary gas purchases during Winter Storm Uri, and capital expenditures, primarily with cash from operations and commercial paper. Natural gas prices have increased during the six months ended June 30, 2022, which impacts our investment in natural gas in storage as well as working capital for receivables and payables.

We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales revenues and our rate mechanisms that we have in place result in a stable cash flow profile and historically has generated stable earnings. Additionally, we have rate mechanisms in place in our jurisdictions that reduce the lag in earning a return on our capital expenditures and provide for recovery of certain changes in our cost of service by allowing for adjustments to rates between rate cases. We anticipate that our cash flow generated from operations and our expected short- and long-term financing arrangements will enable us to maintain our current and planned level of operations and provide us flexibility to finance our infrastructure investments.

Our ability to access capital markets for debt and equity financing under reasonable terms depends on market conditions, our financial condition and credit ratings. By maintaining a conservative financial profile and stable revenue base, we expect to maintain credit ratings at a level that supports our access to diverse sources of capital at favorable rates for capital investments and expenses.

**Short-term Debt -** On March 16, 2022, we entered into the first amendment to the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the maturity date of the ONE Gas Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changes the benchmark rate defined in the ONE Gas Credit Agreement to SOFR as administered by the Federal Reserve Bank of New York. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.

The ONE Gas Credit Agreement provides for a $1.0 billion revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. We can request an increase in commitments of up to an additional

$500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At June 30, 2022, our total debt-to-capital ratio was 63 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

In June 2021, we increased the size of our commercial paper program to permit the issuance of commercial paper to fund short-term borrowing needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time. The maturities of the commercial paper vary but may not exceed 270 days from the date of issue. Commercial paper is generally sold at par less a discount representing an interest factor. At June 30, 2022, we had $490.1 million of commercial paper outstanding.

At June 30, 2022, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit, which is available to repay any of our commercial paper borrowings.

In connection with the second amendment and restatement of the ONE Gas Credit Agreement on March 16, 2021, all commitments under our ONE Gas 364-day Credit Agreement, dated as of April 7, 2020, were terminated and all obligations under the ONE Gas 364-day Credit Agreement were paid in full and discharged.

**Long-term Debt -** In March 2021, we issued $1.0 billion of 0.85 percent senior notes due March 2023, $700 million of 1.10 percent senior notes due March 2024, and $800 million of floating-rate senior notes due March 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year, reset quarterly for the applicable interest period (2.35 percent at June 30, 2022).

In the event LIBOR is not available, and such circumstances are unlikely to be temporary, we or our designee may establish an alternative interest rate for our floating-rate senior notes due 2023 by replacing LIBOR with one or more secured financing-based rates or another alternate benchmark rate. The net proceeds from the issuance were used for payment of gas purchases and related costs resulting from Winter Storm Uri and general corporate purposes.

In September 2021, we called $400 million of the floating-rate senior notes due 2023 at par, using a combination of cash on hand and commercial paper. We did not have the right to call these senior notes prior to September 11, 2021. We expect to use the proceeds from the issuance of securitized bonds in each state, as discussed in Note 3 of the Notes to Consolidated Financials

Statements in this Quarterly Report, to call the outstanding senior notes due March 2023 and a portion of the senior notes due March 2024.

The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.

In February 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

At June 30, 2022, our long-term debt-to-capital ratio was 60 percent.

**Credit Ratings -** Our credit ratings as of June 30, 2022, were:

| Rating Agency | Rating | Outlook |
| --- | --- | --- |
| Moody’s | A3 | Stable |
| S&P | BBB+ | Positive |

Our commercial paper is rated Prime-2 by Moody’s and A-2 by S&P. We intend to maintain credit metrics at a level that supports our balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be competitive with our peer group.

**At-the-Market Equity Program -** In February 2020, we initiated an at-the-market equity program by entering into an equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $250 million (including any shares of common stock that may be sold pursuant to the master forward sale confirmation entered into in connection with the equity distribution agreement and the related supplemental confirmations). Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. For the six months ended June 30, 2022 and 2021, respectively, we issued and sold 403,792 shares and 198,438 shares of our common stock for $35.0 million and $15.3 million, generating proceeds, net of issuance costs, of $34.7 million and $15.1 million.

For the six months ended June 30, 2022, we executed forward sale agreements for 591,736 shares of our common stock, which must be settled on or before January 2, 2024. No shares of common stock have been settled under the forward sale agreements. Had we settled all shares under the forward agreements as of June 30, 2022, we would have generated net proceeds of $48.3 million, or $81.54 per share.

**EDIT -** The return of EDIT to our customers is not expected to have a material impact on earnings, as any reduction or credit in rates is largely offset by a noncash reduction in income tax expense. However, as a result, cash flows for the three months ended June 30, 2022 and 2021, were reduced by approximately $3.0 million and $2.6 million, respectively, for EDIT returned to customers. Cash flows for the six months ended June 30, 2022 and 2021, were reduced by approximately $10.9 million and $10.7 million, respectively, for EDIT returned to customers.

**Pension and Other Postemployment Benefit Plans -** In 2022, our contributions are expected to be $1.5 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans. We use a December 31 measurement date for our plans. On April 30, 2022, we amended our defined benefit pension plans to change the variable cost of living adjustment for eligible participants, to a fixed rate. Therefore, our pension plans were remeasured as of April 30, 2022, resulting in an adjustment of approximately $7.2 million to our pension expense, net of capitalization and regulatory deferrals, for the year ending December 31, 2022, beginning May 1, 2022.

Information about our pension and other postemployment benefits plans, including anticipated contributions, is included under Note 14 of the Notes to Consolidated Financial Statements in our Annual Report. See Note 9 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

### CASH FLOW ANALYSIS

We use the indirect method to prepare our consolidated statements of cash flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments and changes in our assets and liabilities not classified as investing or financing activities during the period. Items that impact net income but may not result in actual cash receipts or payments include, but are not limited to, depreciation and amortization, deferred income taxes, share-based compensation expense and provision for doubtful accounts.

The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:

| Total cash provided by (used in): | Six Months Ended June 30, 2022 (Millions of dollars) | 2021 | Variance 2022 vs. 2021 |
| --- | ---: | ---: | ---: |
| Operating activities | **$286.7** | $(1,577.3) | **$1,864.0** |
| Investing activities | **(251.5)** | (219.1) | **(32.4)** |
| Financing activities | **(36.7)** | 1,997.6 | **(2,034.3)** |
| Change in cash and cash equivalents | **(1.5)** | 201.2 | **(202.7)** |
| Cash and cash equivalents at beginning of period | **8.9** | 8.0 | **0.9** |
| Cash and cash equivalents at end of period | **$7.4** | $209.2 | **$(201.8)** |

**Operating Cash Flows -** Changes in cash flows from operating activities are due primarily to changes in sales revenues, natural gas costs and operating expenses discussed in Financial Results and Operating Information, the effects of Winter Storm Uri and tax reform discussed in Regulatory Activities and changes in working capital. Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions, variations in weather not mitigated by WNAs, changes in supply or increased competition from other service providers, could affect our earnings and operating cash flows. Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.

Operating cash flows were higher for the six months ended June 30, 2022, compared with the prior period, due primarily to the increased natural gas purchases in the prior period resulting from Winter Storm Uri, which were deferred and included in regulatory assets. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

**Investing Cash Flows -** Cash used in investing activities increased for the six months ended June 30, 2022, due primarily to an increase in capital expenditures for system integrity and extension of service to new areas.

**Financing Cash Flows -** Cash provided by financing activities decreased for the six months ended June 30, 2022, compared with the prior period, due primarily to increased prior period borrowings to finance natural gas purchases resulting from Winter Storm Uri.

### ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

**COVID-19** - See “Recent Developments,” as well as Notes 3 and 12 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion regarding the effects of COVID-19 on us.

**Environmental Matters** - We are subject to multiple laws and regulations regarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the CAA and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and six months ended June 30, 2022 and 2021.

We own or retain legal responsibility for certain environmental conditions at 12 former MGP sites in Kansas. These sites contain contaminants generally associated with MGP sites and are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE governs all environmental investigation and remediation work at these sites. The terms of the consent agreement require us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. Regulatory closure has been achieved at five of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs.

We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. At June 30, 2022, we have deferred $29.9 million for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2023.

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at seven of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. A remediation plan concerning this site was submitted to the KDHE in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan for an additional site that we expect to submit to the KDHE in 2023.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. On April 14, 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. At June 30, 2022, estimated costs associated with expected remediation activities for this site are not material.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and six months ended June 30, 2022 and 2021. The reserve for remediation of our MGP sites was $17.8 million and $22.8 million at June 30, 2022 and December 31, 2021, respectively. Environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and those costs may adversely affect our financial condition, results of operations and cash flows.

**Pipeline Safety** - We are subject to regulation under federal pipeline safety statutes and any analogous state regulations. These include safety requirements for the design, construction, operation, and maintenance of pipelines, including transmission and distribution pipelines. At the federal level, we are regulated by PHMSA. PHMSA regulations require the following for certain pipelines: inspection and maintenance plans; integrity management programs, including the determination of pipeline integrity risks and periodic assessments on certain pipeline segments; an operator qualification program, which includes certain trainings; a public awareness program that provides certain information; and a control room management plan.

As part of regulating pipeline safety, PHMSA promulgates various regulations. For example, in April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals included changes to pipeline integrity management requirements and other safety-related requirements. Subsequently, PHMSA announced they would split this NPRM into three separate final rulemakings:

- the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and Job Creation Act and is called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;
- the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering pipelines); and
- the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.

On October 1, 2019, PHMSA published the first of the three final rules referenced above, which addressed the 2011 congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline, and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP within 15 years. The first final rule became effective July 1, 2020. Our estimated capital and operating expenditures associated with compliance with the first final rulemaking were not material.

PHMSA has not yet issued the second final rule. The potential capital and operating expenditures associated with compliance with this rule are currently being evaluated and could be significant depending on the final regulation. We do not expect to be impacted by the third final rule, as we do not own gas gathering pipelines.

Separately, as part of the Consolidated Appropriations Act, 2021, the PIPES Act of 2020 reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. To the extent such rulemakings impose more stringent requirements on our facilities, we may be required to incur expenditures that may be material.

**Air and Water Emissions -** The CAA, the Clean Water Act, and analogous state laws and/or regulations promulgated thereunder, impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Failure to comply with these requirements may result in substantial fines or other penalties, including (in certain cases) the revocation of necessary permits. Under the CAA, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air-pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. Such expenditures have not had a material impact on our respective results of operations, financial position or cash flows; however, we cannot predict the impacts of any future requirements. The Clean Water Act imposes substantial potential liability for the discharge of pollutants into waters of the United States, including the potential for fines, civil enforcement, or orders to perform remediation of waters affected by such discharge.

**Climate –** The threat of climate change continues to attract considerable attention. International, federal, regional and/or state legislative and/or regulatory initiatives may be proposed in the future to regulate greenhouse gas emissions. For example, President Biden has announced that climate change will be a focus of his administration and has signed several executive orders on the subject. For more information, see our risk factor titled “Carbon neutral, energy-efficiency or other legislation or regulations intended to address climate change could increase our operating costs or restrict our market opportunities, adversely affecting our financial results, growth, cash flows and results of operations” in our Annual Report. We monitor relevant legislation and regulatory initiatives to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual greenhouse gas emissions reporting as carbon dioxide equivalents from affected facilities and for the natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own emissions. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has been enacted for natural gas distribution that assesses any costs, fees or expenses on any of these emissions.

Our operations may also be indirectly impacted by regulations attempting to limit or control climate impacts. For example, there is a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an executive order calling for the development of a climate finance plan and, separately, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

**Waste and Hazardous Substances -** During the course of our operations, we may use or generate hazardous substances and wastes, including hazardous wastes. The generation, use, storage, transportation, handling, and disposal of such materials may be subject to federal, state, and local laws. For example, the Resource Conservation and Recovery Act regulates both solid and hazardous wastes, including the imposition of detailed requirements for the handling, storage, treatment, and disposal of hazardous wastes. Separately, CERCLA, also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA). These persons include, but are not limited to, the owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies.

**Pipeline Security -** In May and July 2021, TSA issued security directives which included several new cybersecurity requirements for critical pipeline owners and operators. The first security directive requires critical pipeline owners and operators to (1) report confirmed and potential cybersecurity incidents to the CISA; (2) designate a cybersecurity coordinator to be available 24 hours a day, seven days a week; (3) review current practices; and (4) identify any gaps and related remediation measures to address cyber-related risks and report the results to TSA and CISA within 30 days. The second security directive requires owners and operators of TSA-designated critical pipelines to implement specific mitigation measures to protect against ransomware and other known threats to information technology and operational technology systems, develop and implement a cybersecurity contingency and recovery plan, and conduct a cybersecurity architecture design review. Compliance with these measures has not had a material impact on our operations. We continue to evaluate the potential effect of these directives on our operations and facilities, as well as the potential cost of implementation, and will continue to monitor for any clarifications or amendments to these directives.

**Environmental Footprint -** Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (1) developing and maintaining an accurate greenhouse gas emissions inventory according to current rules issued by the EPA; (2) monitoring and improving the integrity of our pipelines; (3) following developing technologies for emission control; (4) promoting end-use conservation through programs that incentivize the use of high-efficiency equipment; and (5) reducing the loss of methane from our facilities. In addition, we are considering potential avenues to incorporate RNG and hydrogen into our operations. RNG and hydrogen technologies offer potential opportunities to secure new natural gas supply sources that could be transported on our pipeline system and potentially reduce greenhouse gas emissions.

We participate in several programs to voluntarily reduce methane emissions including the EPA’s Natural Gas STAR Program, the EPA’s Natural Gas STAR Methane Challenge Program, and Our Nation’s Energy Future (ONE Future). By joining these programs, we committed to: 1) evaluate our methane emission reduction opportunities; 2) implement practices to reduce methane emissions where feasible; and 3) annually report our methane emissions and/or our methane reduction activities. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. As part of the Methane Challenge Program, we have committed to annually replace or rehabilitate at least two percent of our combined inventory of cast iron and noncathodically-protected steel pipe, which aligns with our planned system integrity expenditures for infrastructure replacements. We exceeded our goal by achieving an overall replacement rate greater than two percent annually every year from 2016 through 2021 and anticipate reporting on our 2022 progress in 2023.

We continue to assess various opportunities for emission reductions and other potential improvements to our environmental footprint. However, we cannot guarantee that we will be able to implement any of the opportunities that we may review or explore. For any such opportunities that we do choose to implement, we cannot guarantee that we will be able to implement them within a specific timeframe or across all operational assets.

In September 2020, we announced membership in ONE Future, a group of natural gas companies working together to voluntarily reduce methane emissions across the natural gas value chain to one percent or less by 2025. We submitted our 2020 data, which ONE Future aggregates with peer members. In its most recent report, ONE Future stated that its members registered a 2020 methane intensity of 0.424 percent, which surpassed the 2025 goal of 1.0 percent. The intensity for the distribution sector, which includes us, was 0.118 percent, beating the goal of 0.225 percent by 46 percent. Participating distribution companies represented 40 percent of the natural gas delivered in the U.S. in 2020.

Additional information about our environmental matters is included in the section entitled “Environmental Matters” in Note 12 of the Notes to Consolidated Financial Statements in this Quarterly Report. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation, and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows for the three and six months ended June 30, 2022 and 2021.

**Regulatory -** Several regulatory initiatives impacted the earnings and future earnings potential of our business. See additional information regarding our regulatory initiatives in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

### IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards, if any, is included in Note 1 of the Notes to Consolidated Financial Statements in this Quarterly Report.

### ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

Information about our estimates and critical accounting policies is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Estimates and Critical Accounting Policies,” in our Annual Report.

### FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, liquidity, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking and other statements in this Quarterly Report regarding our environmental, social and other sustainability plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,”

“guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” “likely,” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Quarterly Report. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, costs, liquidity, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

- our ability to recover costs (including operating costs and increased commodity costs related to Winter Storm Uri in February 2021), income taxes and amounts equivalent to the cost of property, plant and equipment, regulatory assets and our allowed rate of return in our regulated rates or other recovery mechanisms;
- cyber-attacks, which, according to experts, have increased in volume and sophistication since the beginning of the COVID-19 pandemic, or breaches of technology systems that could disrupt our operations or result in the loss or exposure of confidential or sensitive customer, employee or Company information; further, increased remote working arrangements as a result of the pandemic have required enhancements and modifications to our IT infrastructure (e.g. Internet, Virtual Private Network, remote collaboration systems, etc.), and any failures of the technologies, including third-party service providers, that facilitate working remotely could limit our ability to conduct ordinary operations or expose us to increased risk or effect of an attack;
- our ability to manage our operations and maintenance costs;
- the concentration of our operations in Kansas, Oklahoma, and Texas;
- changes in regulation of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;
- the economic climate and, particularly, its effect on the natural gas requirements of our residential and

commercial customers;

- the length and severity of a pandemic or other health crisis, such as the outbreak of COVID-19, including the impact to our operations, customers, contractors, vendors and employees, the effectiveness of vaccine campaigns (including the COVID-19 vaccine campaign) on our workforce and customers and the effect of other measures or mandates that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address the pandemic or other health crisis, which could (as with COVID-19) precipitate or exacerbate one or more of the above-mentioned and/or other risks, and significantly disrupt or prevent us from operating our business in the ordinary course for an extended period;
- competition from alternative forms of energy, including, but not limited to, electricity, solar power, wind power, geothermal energy and biofuels;
- adverse weather conditions and variations in weather, including seasonal effects on demand and/or supply, the occurrence of severe storms in the territories in which we operate, and climate change, and the related effects on supply, demand, and costs;
- indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantage compared with competitors;
- our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of existing supply and transportation and storage arrangements that are not replaced with contracts with similar terms and pricing;
- our ability to complete necessary or desirable expansion or infrastructure development projects, which may delay or prevent us from serving our customers or expanding our business;
- operational and mechanical hazards or interruptions;
- adverse labor relations;
- the effectiveness of our strategies to reduce earnings lag, revenue protection strategies and risk mitigation strategies, which may be affected by risks beyond our control such as commodity price volatility, counterparty performance or creditworthiness and interest rate risk;
- the capital-intensive nature of our business, and the availability of and access to, in general, funds to meet our debt obligations prior to or when they become due and to fund our operations and capital expenditures, either through (i) cash on hand, (ii) operating cash flow, or (iii) access to the capital markets and other sources of liquidity;
- our ability to obtain capital on commercially reasonable terms, or on terms acceptable to us, or at all;
- limitations on our operating flexibility, earnings and cash flows due to restrictions in our financing arrangements;
- cross-default provisions in our borrowing arrangements, which may lead to our inability to satisfy all of our outstanding obligations in the event of a default on our part;
- changes in the financial markets during the periods covered by the forward-looking statements, particularly those affecting the availability of capital and our ability to refinance existing debt and fund investments and acquisitions to execute our business strategy;
- actions of rating agencies, including the ratings of debt, general corporate ratings and changes in the rating agencies’ ratings criteria;
- changes in inflation and interest rates;
- our ability to recover the costs of natural gas purchased for our customers, including those related to Winter Storm Uri and any related financing required to support our purchase of natural gas supply, including the securitized financings currently contemplated in each of our jurisdictions;
- impact of potential impairment charges;
- volatility and changes in markets for natural gas and our ability to secure additional and sufficient liquidity on reasonable commercial terms to cover costs associated with such volatility;
- possible loss of LDC franchises or other adverse effects caused by the actions of municipalities;
- payment and performance by counterparties and customers as contracted and when due, including our counterparties maintaining ordinary course terms of supply and payments;
- changes in existing or the addition of new environmental, safety, tax and other laws to which we and our subsidiaries are subject, including those that may require significant expenditures, significant increases in operating costs or, in the case of noncompliance, substantial fines or penalties;
- the effectiveness of our risk-management policies and procedures, and employees violating our risk-management policies;
- the uncertainty of estimates, including accruals and costs of environmental remediation;
- advances in technology, including technologies that increase efficiency or that improve electricity’s competitive position relative to natural gas;
- population growth rates and changes in the demographic patterns of the markets we serve, and economic conditions in these areas’ housing markets;
- acts of nature and the potential effects of threatened or actual terrorism and war, including recent events in Europe;
- the sufficiency of insurance coverage to cover losses;
- the effects of our strategies to reduce tax payments;
- the effects of litigation and regulatory investigations, proceedings, including our rate cases, or inquiries and the requirements of our regulators as a result of the Tax Cuts and Jobs Act of 2017;
- changes in accounting standards;
- changes in corporate governance standards;
- existence of material weaknesses in our internal controls;
- our ability to comply with all covenants in our indentures and the ONE Gas Credit Agreement, a violation of which, if not cured in a timely manner, could trigger a default of our obligations;
- our ability to attract and retain talented employees, management and directors, or a shortage of skilled labor;
- unexpected increases in the costs of providing health care benefits, along with pension and postemployment health care benefits, as well as declines in the discount rates on, declines in the market value of the debt and equity securities of, and increases in funding requirements for, our defined benefit plans; and
- our ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Part 1, Item 1A, Risk Factors, in our Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

## Market risk

As filed, 2,437 characters.

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in our Annual Report.

### Commodity Price Risk

Our commodity price risk, driven primarily by fluctuations in the price of natural gas, is mitigated by our purchased-gas cost adjustment mechanisms through which we pass-through natural gas costs to our customers without profit. We may use derivative instruments to economically hedge the cost of a portion of our anticipated natural gas purchases during the winter heating months to reduce the impact on our customers of upward market price volatility of natural gas. Additionally, we inject natural gas into storage during the summer months, when natural gas prices are typically lower, and withdraw the natural gas during the winter heating season. Gains or losses associated with these derivative instruments and storage activities are included in, and recoverable through our purchased-gas cost adjustment mechanisms, which are subject to review by regulatory authorities.

### Interest-Rate Risk

We are exposed to interest-rate risk primarily associated with commercial paper borrowings and new debt financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt. We may manage interest-rate risk on future borrowings through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates.

### Counterparty Credit Risk

We assess the creditworthiness of our customers. Those customers who do not meet minimum standards are required to provide security, including deposits and other forms of collateral, when appropriate and allowed by tariff. With approximately 2.3 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain a provision for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current credit environment and other information. We are able to recover the fuel-related portion of bad debts through our purchased-gas cost adjustment mechanisms.

## Controls and procedures

As filed, 719 characters.

**Quarterly Evaluation of Disclosure Controls and Procedures** - Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rules 13(a)-15(b) of the Exchange Act.

**Changes in Internal Control Over Financial Reporting** - There have been no changes in our internal control over financial reporting during the second quarter ended June 30, 2022, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 736 characters.

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors, of our Annual Report that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Filed Aug 2, 2022.
Source: SEC EDGAR, the filing index for accession 0001587732-22-000061. Last ingested by Listed: Nov 3, 2026, 18:56 ET. No prices; not investment advice.