# ONE Gas, Inc.: Form 10-Q for the period ended Mar 31, 2021

- Company: [ONE Gas, Inc.](/companies/ogs.md) (CIK 1587732)
- Form: 10-Q
- Filed: 2021-05-04
- Accepted by EDGAR: May 4, 2021, 16:50 ET
- Period: 2021-03-31
- Accession: 0001587732-21-000045
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1587732/000158773221000045/ogs-20210331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1587732/000158773221000045/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2021-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Cost of revenue | 3 months, 2021-01-01 to 2021-03-31 | $314.1m | us-gaap:CostOfGoodsAndServicesSold |
| Operating income | 3 months, 2021-01-01 to 2021-03-31 | $130.3m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2021-01-01 to 2021-03-31 | $15.4m | us-gaap:InterestExpense |
| Income tax | 3 months, 2021-01-01 to 2021-03-31 | $18.9m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2021-01-01 to 2021-03-31 | $95.6m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2021-01-01 to 2021-03-31 | $1.79 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2021-01-01 to 2021-03-31 | $1.79 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2021-01-01 to 2021-03-31 | 53,515,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2021-01-01 to 2021-03-31 | −$1.66bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 3 months, 2021-01-01 to 2021-03-31 | $99.1m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 3 months, 2021-01-01 to 2021-03-31 | $30.9m | us-gaap:PaymentsOfDividends |
| Current assets | at 2021-03-31 | $1.16bn | us-gaap:AssetsCurrent |
| Total assets | at 2021-03-31 | $8.68bn | us-gaap:Assets |
| Current liabilities | at 2021-03-31 | $879.0m | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2021-03-31 | $4.08bn | us-gaap:LongTermDebtNoncurrent |
| Short-term borrowings | at 2021-03-31 | $447.0m | us-gaap:CommercialPaper |
| Shareholders' equity | at 2021-03-31 | $2.30bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 88,259 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 months ended March 31, 2021 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 Kansas, Oklahoma, and Texas. During this time, the governors of Kansas, Oklahoma, 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 Kansas, Oklahoma, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month of February 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.

On March 11, 2021, we issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 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 (0.79% at March 31, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from 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.

Our purchased gas costs are recoverable through our 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 local natural gas distribution companies, 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. We have deferred approximately $2.0 billion in 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 the 2021 winter weather event on us.

ONE Gas Credit Agreement - On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017. The ONE Gas Credit Agreement provides for a $1 billion revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. In connection with the amendment of the ONE Gas Credit Agreement, all commitments under the ONE Gas 364-day Credit Agreement were terminated, and all obligations under the 364-day Credit Agreement were paid in full and discharged.

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. These actions include following safety protocols developed during the pandemic, remote work for our office-based employees, limiting direct contact with our customers, and generally suspending disconnections and late payment fees beginning in mid-March 2020 through April 2021, when disconnects were resumed in all service areas, except Texas, which is still subject to a moratorium. Although we have experienced employee absences due to our protocols for self-isolation of employees who may be exhibiting symptoms or who may have been exposed to or contracted the COVID-19 virus, we have continued, and expect to continue, to execute our work in the field, including our capital work for system integrity, pipeline replacements and extending service to new customers.

During the three months ended March 31, 2021, impacts on our results of operations as a result of COVID-19 include but are not limited to:

- lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the suspension of disconnects for nonpayment in each of our jurisdictions;
- incremental expenses for PPE, cleaning supplies, outside services and other expenses; and
- lower expenses for travel and employee training that have been impacted by the pandemic.

Going forward, we expect these impacts on our revenues and expenses to continue during the course of the pandemic. We also could experience a reduction in revenues from commercial and transportation customers temporarily or permanently impacted by the pandemic. However, we do not expect COVID-related impacts to have a material adverse effect on our results of operations or cash flows during 2021.

We are in regular communication with our regulators to keep them apprised of the effects COVID-19 is having on the service we provide. 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 revenue 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 March 31, 2021, no regulatory assets have been recorded. 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. Accordingly, there could be a delay in the recognition of amounts that may be approved for recovery until the conclusion of future regulatory proceedings.

See “Regulatory Activities,” “Financial Results and Operating Information,” “Capital Expenditures and Asset Removal Costs,” and Note 3 and Note 12 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the effects of COVID-19 on us.

Dividend - In May 2021, we declared a dividend of $0.58 per share ($2.32 per share on an annualized basis) for shareholders of record as of May 17, 2021, payable on June 1, 2021.

### REGULATORY ACTIVITIES

Oklahoma - On February 12, 2021, the governor of Oklahoma declared a state of emergency for all 77 counties in the state of Oklahoma in light of expected severe weather and freezing temperatures associated with a winter weather event. The declaration cited anticipated damage to private and public properties and utilities, including electric, gas, and water systems, within the state of Oklahoma.

On February 16, 2021, the OCC approved an emergency order (the “OCC Order”) (i) directing natural gas and electric utilities to prioritize deliveries of natural gas and electricity for services necessary for life, health, and public safety, and of natural gas to electric generation facilities that serve human needs customers, and (ii) directing local utilities to communicate with their customers in order to reduce all non-essential energy consumption, and to reduce load in a safe and reasonable manner. The OCC Order recognized that the severe weather conditions resulted in increased commodity prices for both gas and electric utilities, along with issues relating to commodity acquisition, line pressure, and supply shortages. The OCC Order expired on February 20, 2021.

In response to a motion filed by Oklahoma Natural Gas on March 2, 2021, the OCC issued an order stating that Oklahoma Natural Gas shall defer to a regulatory asset the extraordinary costs associated with this unprecedented winter weather event, including commodity costs, operational costs and carrying costs. The order further states that after all deferred costs have been accumulated and recorded, Oklahoma Natural Gas shall file a compliance report detailing the extent of such costs incurred. The order also provides that recovery of the deferred costs will be addressed in a future proceeding that will include a prudence review. At March 31, 2021, we have deferred approximately $1.32 billion in extraordinary costs attributable to Oklahoma Natural Gas customers associated with Winter Storm Uri.

In April 2021, a bill permitting the state to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred by regulated utilities during extreme weather events, was signed into law by the Oklahoma governor. Pursuant to this legislation, we will submit an application to the OCC for a financing order authorizing extraordinary costs approved for recovery, the period over which costs will be recovered, and other such specifications necessary for the issuance of securitized bonds. The OCC will have 180 days to consider our application. After issuance of the financing order by the OCC, the Oklahoma Development Finance Authority (ODFA) has 24 months to complete the process to issue the securitized bonds. On April 29, 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to this legislation. In the application, Oklahoma Natural Gas indicates it will file a supplemental motion with all required components pursuant to the legislation for the issuance of a financing order. Upon filing the supplemental motion, the OCC will have 180 days to issue an order regarding our application. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.

In June 2020, the OCC issued an order permitting the creation of regulatory assets and deferrals related to COVID-19. Each utility is authorized under the OCC’s order to record as a regulatory asset increased bad debt expenses, costs associated with expanded payment plans, waived fees, and incremental expenses that are directly related to the suspension of or delay in disconnection of service (or the reconnection of service) beginning March 15, 2020, as a result of the governor’s executive order declaring a state of emergency. In addition, the OCC recognizes that utilities report taking many steps to ensure the continuity of utility service, while protecting utility personnel, customers, and the general public. Such steps include procuring additional PPE, increasing sanitation efforts at facilities, implementing health-screening processes, and securing temporary facilities for potential sequestration of critical operations personnel. The OCC has stated it supports the continuation of these critical response and planning efforts and acknowledges such efforts cause incremental costs that it will allow to be deferred and reviewed in a future rate case. The OCC’s deferral authorization does not bind the OCC to any specific treatment of these items in any future proceeding, nor does it prohibit the OCC from considering the effect of any operational savings, or other financial impacts that may occur as a result of COVID-19. Determination of the recovery of the regulatory assets and deferrals will occur in the next rate case that is required to be filed on or before June 30, 2021.

In February 2020, Oklahoma Natural Gas filed its fourth annual PBRC application following the general rate case that was approved in January 2016. A settlement was reached, and the OCC approved a joint stipulation in July 2020. This stipulation includes a base rate increase of $9.7 million and an energy efficiency incentive of $2.2 million, with new rates reflecting these changes effective in June 2020. This stipulation also includes a credit of $12.2 million associated with EDIT issued through a bill credit to Oklahoma customers in the first quarter of 2021.

As required, PBRC filings are made annually on or before March 15, until the next general rate case, which is currently required to be filed on or before June 30, 2021, based on a calendar 2020 test year.

Kansas - On February 14, 2021, the governor of Kansas issued a State of Disaster Emergency due to wind chill warnings and stress on utility and natural gas providers expected from the significantly colder than normal weather forecasted throughout Kansas. The executive order also urged Kansas citizens to conserve energy to help ensure a continued supply of natural gas and electricity and keep their personal costs down. The declaration also noted that due to increased energy demand and natural gas supply constraints caused by sub-zero temperatures, utilities at the time were experiencing wholesale natural gas prices anywhere from 10 to 100 times higher than normal.

On February 15, 2021, the KCC issued an emergency order (i) directing all jurisdictional natural gas and electric utilities to coordinate efforts and take all reasonably feasible, lawful, and appropriate actions to ensure adequate delivery of natural gas and electricity to interconnected, non-jurisdictional utilities in Kansas, (ii) 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 in Kansas, and (iii) allowing those electric and natural gas distribution utilities who incur extraordinary costs to ensure their customers and other interconnected customers continued to receive utility service during this unprecedented cold weather event to defer those costs to a regulatory asset account. Each jurisdictional utility will be required to file a compliance report detailing the extent of such costs incurred and presenting a plan to minimize the financial impacts of this event on ratepayers over a reasonable time frame. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings. On March 9, 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific investigations 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 the winter weather event. Kansas Gas Service expects to file its compliance report in the second quarter of 2021. At March 31, 2021, we have deferred approximately $381 million in extraordinary costs attributable to Kansas Gas Service customers associated with Winter Storm Uri.

In April 2021, a bill permitting utilities to pursue securitization to finance extraordinary expenses, such as fuel costs incurred during extreme weather events, was signed into law by the Kansas governor. This bill gives the KCC the authority to oversee and authorize the issuance of ratepayer-backed securitized bonds issued by a public utility. Pursuant to this legislation, we can submit an application to the KCC for a financing order authorizing extraordinary costs approved for recovery, the period over which costs will be recovered, and other such specifications necessary for the issuance of securitized bonds. The KCC will have 180 days to consider our application. Following KCC approval of the financing order, we can begin the process to issue the securitized bonds. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.

In August 2020, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $7.8 million related to its GSRS. This filing incorporates the effect on the requested GSRS rate increase of a bill amending the Kansas income tax code that eliminates public utilities regulated by the KCC from paying Kansas state income taxes beginning January 1, 2021. In September 2020, Kansas Gas Service submitted an erratum to the application which modified the requested increase to approximately $7.5 million. In November 2020, the KCC approved the increase effective December 2020.

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 $81.5 million was recorded as an EDIT 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 year ended December 31, 2020. 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. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

In April 2020, Kansas Gas Service filed an application with the KCC for an AAO to accumulate and defer certain incremental costs incurred, including bad debt expenses and lost revenues, as well as associated carrying costs, related to COVID-19 beginning March 1, 2020, for recovery in Kansas Gas Service’s next rate case filing. In July 2020, the KCC approved the request for an AAO subject to the recommendations set forth in its Staff Report and Recommendation and clarifications sought by Kansas Gas Service. The AAO provides notice that Kansas Gas Service may identify, track, document, accumulate, and defer in a regulatory asset extraordinary costs (net of any cost decreases) and lost revenue, plus carrying costs, associated with the COVID-19 pandemic. The KCC states that approval of the AAO is not a finding that tracked costs and lost revenue will be included in future rates; rather, any determination regarding recoverability will occur in a future rate proceeding. In a separate order applicable to all regulated utilities, the KCC approved the deferral of bad debt expense and late payment fees associated with the KCC’s suspension of disconnection activity and customer protection provisions. The recovery, the carrying charges and amortization period will be determined in Kansas Gas Service’s next rate case or alternative rate recovery filing.

In November 2018, Kansas Gas Service submitted an application to the KCC requesting approval of its contract to own, operate and maintain the natural gas distribution system at Fort Riley, a United States Army installation. The KCC approved the Company’s application in May 2019 and the transition period, which was delayed due to COVID-19, has been extended to June 1, 2021. The acquisition of these assets is now expected to be completed before the end of third quarter 2021 for approximately $8.5 million.

Texas - On February 12, 2021, the governor of Texas issued a state of disaster for all 254 counties in Texas in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat due to prolonged freezing temperatures, heavy snow, and freezing rain statewide.

Also, on February 12, 2021, the RRC issued an emergency order to temporarily implement a statewide utilities curtailment program intended to protect residences, hospitals, schools, churches, and other human needs customers. On February 17, 2021, the RRC extended its emergency order issued on February 12, 2021, to February 23, 2021.

On February 13, 2021, the RRC issued a Notice to Local Distribution Companies acknowledging that due to the demand for natural gas expected during the upcoming winter weather event, natural gas utility LDCs may be required to pay extraordinarily high prices in the market for natural gas and may be subjected to other extraordinary costs when responding to the event. The RRC also encouraged natural gas utilities to continue to work to ensure that the citizens of the State of Texas were provided with safe and reliable natural gas service. To partially defer and reduce the impact on customers for these costs that ultimately are reflected in customer bills, the RRC authorized LDCs to record a regulatory asset to account for the extraordinary costs associated with this winter weather event, including but not limited to gas cost and other costs related to the procurement and transportation of gas supply. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings. At March 31, 2021, we have deferred approximately $295 million in extraordinary costs attributable to Texas Gas Service customers associated with Winter Storm Uri.

In April 2021, a bill permitting the state to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred during extreme weather events, was proposed and is advancing in the Texas legislature. This proposed bill would give the RRC the authority to approve the amounts to be recovered from the issuance of ratepayer-backed securitized bonds by the Texas Public Financing Authority (TPFA). Pursuant to this proposed legislation, we will submit an application to the RRC, within 60 days of the legislation becoming effective, for an order authorizing the amount of extraordinary costs for recovery, the period over which costs will be recovered, and other such specifications necessary for the issuance of securitized bonds. The RRC will have 90 days to consider our application. If approved, the TPFA will begin the process to issue the securitized bonds. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.

In April 2020, the RRC issued an order authorizing utilities to use a regulatory accounting mechanism and a subsequent process through which Texas Gas Service may seek future recovery of incremental expenses resulting from the effects of COVID-19, including bad debt and associated credit and collections costs, and other reasonable and necessary incremental costs to address the impact of COVID-19. The timing of any recovery will be determined as we work with our regulators.

*West Texas Service Area -* 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.

In March 2020, Texas Gas Service made GRIP filings for all customers in the West Texas service area. In June 2020, the RRC and the cities in the West Texas service area agreed to an increase of $4.7 million, and new rates became effective in June 2020.

*Central-Gulf Service Area -* 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.

In 2019, Texas Gas Service filed a rate case for all customers in the Central Texas and Gulf Coast service areas, seeking a rate increase of $15.6 million and a $1.3 million credit to customers associated with EDIT, and requesting to consolidate the two service areas into one. In August 2020, the RRC approved all terms of a $10.3 million settlement, as well as consolidation of the Central Texas service area and the Gulf Coast service area into a new Central-Gulf service area. The RRC also approved an $8.5 million credit to customers associated with EDIT. The settlement included an ROE of 9.5 percent and a capital structure with equity of 59 percent and debt of 41 percent, and new rates became effective in August 2020.

*Other Texas Service Areas* - In April 2021, Texas Gas Service filed annual Cost-of-Service Adjustments (COSA) for the incorporated areas of the Rio Grande Valley service area and the North Texas service area requesting increases in rates of $4.6 million and $2.2 million, respectively. If approved in each service area, new rates will become 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. As of the three months ended March 31, 2021, no annual rate increases associated with these filings have been approved and $1.8 million were approved for the year ended December 31, 2020.

Winter Storm Uri Deferred Costs - The amounts deferred at March 31, 2021, 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 and may assess penalties as a result of over- or under-deliveries during periods that operational flow orders were imposed on us or that we, in turn, imposed on our transport customers or their agents. Amounts recorded reflect management’s best estimate and may be adjusted in future periods as the disposition 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 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 March 31, 2021, net income was $95.6 million, or $1.79 per diluted share, compared with $91.7 million, or $1.72 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 March 31, 2021 | 2020 | Three Months 2021 vs. 2020 Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: |
| Natural gas sales | **$582.8** | $486.8 | **$96.0** | **20%** |
| Transportation revenues | **36.2** | 34.2 | **2.0** | **6%** |
| Other revenues | **6.3** | 7.2 | **(0.9)** | **(13)%** |
| Total revenues | **625.3** | 528.2 | **97.1** | **18%** |
| Cost of natural gas | **314.1** | 226.1 | **88.0** | **39%** |
| Net margin | **311.2** | 302.1 | **9.1** | **3%** |
| Operating costs | **128.6** | 121.4 | **7.2** | **6%** |
| Depreciation and amortization | **52.3** | 47.5 | **4.8** | **10%** |
| Operating income | **$130.3** | $133.2 | **$(2.9)** | **(2)%** |
| Capital expenditures and asset removal costs | **$109.0** | $123.4 | **$(14.4)** | **(12)%** |

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, which are included as other revenues in our Notes to Consolidated Financial Statements.

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 utility 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, which are included in the consolidated statements of income and our Notes to Consolidated Financial Statements as other revenues.

Non-GAAP Financial Measure - We have disclosed net margin, which is considered a non-GAAP financial measure, in our selected financial data and selected financial results. Net margin is comprised of total revenues less cost of natural gas. Cost of natural gas includes commodity purchases, fuel, storage, transportation 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. In addition, 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, net margin is not affected by fluctuations in the cost of natural gas. Accordingly, we routinely use net margin in the analysis of our financial performance. We believe that net margin provides investors a more relevant and useful measure to analyze our financial performance as a 100 percent regulated natural gas utility than total revenues because the change in the cost of natural gas from period to period does not impact our operating income. As such, the following discussion and analysis of our financial performance will reference net margin rather than total revenues and cost of natural gas individually.

The following table sets forth a reconciliation of net margin to the most directly comparable GAAP measure for the periods indicated:

*(Millions of dollars, except percentages)*

| Non-GAAP Reconciliation | Three Months Ended March 31, 2021 | 2020 | Three Months 2021 vs. 2020 Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: |
| Total revenues | **$625.3** | $528.2 | **$97.1** | **18%** |
| Cost of natural gas | **314.1** | 226.1 | **88.0** | **39%** |
| Net margin | **$311.2** | $302.1 | **$9.1** | **3%** |

The following table sets forth our net margin by type of customer for the periods indicated:

*(Millions of dollars, except percentages)*

| Net Margin Natural gas sales | Three Months Ended March 31, 2021 | 2020 | Three Months 2021 vs. 2020 Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: |
| Residential | **$223.2** | $215.6 | **$7.6** | **4%** |
| Commercial and industrial | **43.0** | 42.4 | **0.6** | **1%** |
| Other | **2.5** | 2.7 | **(0.2)** | **(7)%** |
| Net margin on natural gas sales | **268.7** | 260.7 | **8.0** | **3%** |
| Transportation revenues | **36.2** | 34.2 | **2.0** | **6%** |
| Other revenues | **6.3** | 7.2 | **(0.9)** | **(13)%** |
| Net margin | **$311.2** | $302.1 | **$9.1** | **3%** |

Our net margin on natural gas sales is comprised of two components, fixed and variable margin. Fixed margin reflects the portion of our net margin attributable to the monthly fixed customer charge component of our rates, which does not fluctuate based on customer usage in each period. Variable margin reflects the portion of our net margin that fluctuates with the volumes delivered and billed and the effects of weather normalization. The following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:

*(Millions of dollars, except percentages)*

| Net Margin on Natural Gas Sales Net margin on natural gas sales | Three Months Ended March 31, 2021 | 2020 | Three Months 2021 vs. 2020 Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: |
| Fixed margin | **$152.1** | $149.6 | **$2.5** | **2%** |
| Variable margin | **116.6** | 111.1 | **5.5** | **5%** |
| Net margin on natural gas sales | **$268.7** | $260.7 | **$8.0** | **3%** |

Net margin increased $9.1 million for the three months ended March 31, 2021, compared with the same period last year, due primarily to the following:

- an increase of $9.1 million from new rates, primarily in Texas and Oklahoma;
- an increase of $2.3 million in residential sales due primarily to net customer growth in Oklahoma and Texas; and
- an increase of $1.4 million in rider and surcharge recoveries due to a higher ad-valorem surcharge in Kansas, which was offset with higher regulatory amortization expense, in depreciation and amortization expense, offset partially by:
- a decrease of $3.1 million due to the reduction in net margin associated with the impact of weather normalization, net of increased sales volumes, primarily in Texas and Kansas. For the three months ended March 31, 2021, heating degree days in Texas and Kansas were 24% and 12% higher, respectively, compared with the same period in 2020.

Operating costs increased $7.2 million for the three months ended March 31, 2021, compared with the same period last year, due primarily to the following:

- an increase of $3.4 million in employee-related costs;
- an increase of $1.6 million in outside services costs;
- an increase of $1.5 million in expenses related to our response to the COVID-19 pandemic; and
- an increase of $1.0 million in ad valorem taxes.

The portion of the decrease in late payment, reconnect and collection fees resulting from the moratoriums on disconnecting customers for nonpayment in response to the COVID-19 pandemic, increased bad debt expense and the net incremental expenses related to the COVID-19 pandemic are eligible for future recovery under the regulatory orders we have received in each of our jurisdictions. For financial reporting purposes, the amounts deferred as a regulatory asset for future recovery under the accounting orders must be probable of recovery. At March 31, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial statement purposes at such time as recovery is deemed probable.

Depreciation and amortization expense increased $4.8 million for the three months ended March 31, 2021, compared with the same period last year, due primarily to an increase in depreciation from our capital expenditures being placed in service and an increase in the amortization of the ad-valorem surcharge rider in Kansas.

Other Factors Affecting Net Income - Other factors that affected net income for the three months ended March 31, 2021, compared with the same period last year, include a decrease of $5.4 million in other expense, net, due primarily to a $4.9 million reduction in expense resulting from the change in the value of investments associated with nonqualified employee benefit plans.

During the three months ended March 31, 2021 and 2020, we credited income tax expense $8.1 million and $6.9 million, respectively, for the amortization of the regulatory liability associated with EDIT that was returned to customers.

Capital Expenditures and Asset Removal Costs - Our capital expenditures program includes expenditures for pipeline integrity, extension of service to new areas, modifications to customer service lines, increases in system capacity, pipeline replacements, automated meter reading, government-mandated pipeline relocations, fleet, facilities, information technology 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.

Capital expenditures and asset removal costs decreased $14.4 million for the three months ended March 31, 2021, compared with the same period last year, due primarily to the timing of our capital projects in the first quarter 2021, compared with the first quarter 2020. Our capital expenditures and asset removal costs are expected to be $540 million for 2021.

**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 March 31, 2021 OK | KS | TX | Total | 2020 OK | KS | TX | Total | Variances 2021 vs. 2020 Increase (Decrease) OK | KS | TX | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Residential | **826** | **595** | **647** | **2,068** | 814 | 591 | 638 | 2,043 | **12** | **4** | **9** | **25** |
| Commercial and industrial | **77** | **50** | **35** | **162** | 76 | 51 | 36 | 163 | **1** | **(1)** | **(1)** | **(1)** |
| Other | **—** | **—** | **3** | **3** | — | — | 3 | 3 | **—** | **—** | **—** | **—** |
| Transportation | **5** | **6** | **1** | **12** | 5 | 6 | 1 | 12 | **—** | **—** | **—** | **—** |
| Total customers | **908** | **651** | **686** | **2,245** | 895 | 648 | 678 | 2,221 | **13** | **3** | **8** | **24** |

The increase in the average number of customers for the three months ended March 31, 2021, compared with the same period last year, 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 March 31, 2021, our average customer count includes approximately 6,200 new customer connections during the period compared to approximately 5,900 for the same period last year. Additionally, for the three months ended March 31, 2021, our average customer count includes the impact of approximately 26,400 new customer connections in 2020. Also contributing to the increase is a reduction in disconnects for nonpayment by our customers as a result of the suspension of collection activities in response to the COVID-19 pandemic.

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

| Volumes (MMcf) Natural gas sales | Three Months Ended March 31, 2021 | 2020 |
| --- | ---: | ---: |
| Residential | **62,979** | 55,244 |
| Commercial and industrial | **18,489** | 16,312 |
| Other | **1,081** | 1,017 |
| Total sales volumes delivered | **82,549** | 72,573 |
| Transportation | **64,319** | 65,413 |
| Total volumes delivered | **146,868** | 137,986 |

Total sales volumes delivered increased for the three months ended March 31, 2021, compared with the same period last year, due primarily to colder weather in the first quarter 2021. The impact of weather on residential and commercial net margin 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 March 31, 2021 Actual | Normal | 2020 Actual | Normal | 2021 vs. 2020 Actual Variance | 2021 Actual as a percent of Normal | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Oklahoma | **2,045** | **1,775** | 1,636 | 1,775 | **25%** | **115%** | 92% |
| Kansas | **2,490** | **2,461** | 2,222 | 2,461 | **12%** | **101%** | 90% |
| Texas | **1,065** | **1,000** | 856 | 1,010 | **24%** | **107%** | 85% |

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 2016 through the current period, 10-year weighted average HDDs as of December 31, 2014, 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. For 2017 to March 2019, 30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using four 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, and capital expenditures, primarily with cash from operations and commercial paper.

We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales net margin 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 an investment-grade credit rating, which we believe will provide us access to diverse sources of capital.

**Short-term Financing -** We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs. The maturities of the commercial paper notes vary but may not exceed 270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest factor. At March 31, 2021, we had $447.0 million of commercial paper outstanding.

On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017. The ONE Gas Credit Agreement provides for a $1 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. We will be able to extend the maturity date by one year, subject to the lenders’ consent, up to two times. The ONE Gas Credit Agreement expires in March 2026, and 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 utilizes LIBOR as the reference rate for determining interest to accrue on the borrowings. In the event LIBOR is not available, and such circumstances are unlikely to be temporary, our lenders may establish an alternative interest rate for the senior notes by replacing LIBOR with one or more secured overnight financing-based rates or another alternate benchmark rate.

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 72.5 percent at the end of any calendar quarter through December 31, 2021, and 70 percent at the end of any calendar quarter thereafter. At March 31, 2021, our total debt-to-capital ratio was 66 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 connection with the amendment 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 364-day Credit Agreement were paid in full and discharged.

At March 31, 2021, 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 available to repay our commercial paper borrowings.

**Long-Term Debt -** In March 2021, ONE Gas issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 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 (0.79% at March 31, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from Winter Storm Uri.

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.

We may redeem the senior notes issued in March 2021 in whole or in part, plus accrued and unpaid interest to the redemption date, on or after September 11, 2021. We do not have the right to redeem these senior notes prior to September 11, 2021.

In April 2020, ONE Gas issued $300 million of 2.00 percent senior notes due 2030. The proceeds from the issuance were used to reduce the amount of outstanding commercial paper and for general corporate purposes.

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.

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. 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.

In April 2021, legislation in Oklahoma and Kansas was approved and legislation in Texas is advancing that permits utilities to pursue securitization to finance extraordinary expenses, such as fuel costs incurred during extreme weather events. See “Regulatory Activities” for Oklahoma, Kansas and Texas in this Quarterly Report for additional discussion of the securitization legislation in each state. We expect to seek approval from our regulators to utilize the securitization legislation in each state to repay or refinance our debt incurred due to the extraordinary costs associated with Winter Storm Uri.

At March 31, 2021, our long-term debt-to-capital ratio was 64 percent.

**Credit Ratings -** Our credit ratings as of March 31, 2021, were:

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

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. 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. During the quarters ended March 31, 2021 and 2020, we did not issue or sell shares of our common stock under the at-the-market equity program. At March 31, 2021, we had $236.4 million of equity available for issuance under the program. Proceeds from the program are available for general corporate purposes, which may include repaying or refinancing a portion of our outstanding indebtedness and funding working capital and capital expenditures.

**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 offset by a noncash reduction in income tax expense. However, as a result, cash flows for the three months ended March 31, 2021 and 2020, were reduced by approximately $8.1 million and $6.9 million, respectively, for EDIT returned to customers.

**Pension and Other Postemployment Benefit Plans -** In 2021, our contributions are expected to be $1.1 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans. Information about our pension and other postemployment benefits plans, including anticipated contributions, is included under Note 13 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): | Three Months Ended March 31, 2021 (Millions of dollars) | 2020 | Variance 2021 vs. 2020 |
| --- | ---: | ---: | ---: |
| Operating activities | **$(1,659.3)** | $182.7 | **$(1,842.0)** |
| Investing activities | **(101.2)** | (113.2) | **12.0** |
| Financing activities | **2,457.4** | (76.3) | **2,533.7** |
| Change in cash and cash equivalents | **696.9** | (6.8) | **703.7** |
| Cash and cash equivalents at beginning of period | **8.0** | 17.9 | **(9.9)** |
| Cash and cash equivalents at end of period | **$704.9** | $11.1 | **$693.8** |

**Operating Cash Flows -** Changes in cash flows from operating activities are due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information, the effects of 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 lower for the three months ended March 31, 2021, compared with the prior period, due primarily to the increased natural gas purchases 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 decreased for the three months ended March 31, 2021, compared with the prior period, due primarily to a decrease in capital expenditures associated with the timing of our capital projects in the first quarter 2021, compared with the first quarter 2020.

**Financing Cash Flows -** Cash provided by financing activities increased for the three months ended March 31, 2021, compared with the prior period, due primarily to borrowings to finance the increased natural gas purchases resulting from Winter Storm Uri.

### ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

**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. These actions include following safety protocols developed during the pandemic, remote work for our office- based employees, limiting direct contact with our customers, and generally suspending disconnections and late payment fees beginning in mid-March 2020 through April 2021, when disconnects were resumed in all service areas, except Texas, which is still subject to a moratorium. Although we have experienced employee absences due to our protocols for self- isolation of employees who may be exhibiting symptoms or who may have been exposed to or contracted the COVID-19 virus, we have continued, and expect to continue, to execute our work in the field, including our capital work for system integrity, pipeline replacements and extending service to new customers. See “Regulatory Activities,” “Financial Results and Operating Information,” and “Capital Expenditures and Asset Removal Costs,” 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.

Since the onset of the pandemic in the first quarter of 2020, impacts on our results of operations as a result of COVID-19 include but are not limited to:

- lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the suspension of disconnects for nonpayment in each of our jurisdictions;
- incremental expenses for PPE, cleaning supplies, outside services and other expenses; and
- lower expenses for travel and employee training that have been impacted by the pandemic.

Going forward, we expect these impacts on our revenues and expenses to continue during the course of the pandemic. We also could experience a reduction in revenues from commercial and transportation customers temporarily or permanently impacted by the pandemic.

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 revenue 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 March 31, 2021, no regulatory assets have been recorded. 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. We do not expect COVID-related impacts to have a material adverse effect on our results of operations or cash flows during 2021.

**Environmental Matters -** We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, 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, hazardous materials 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 Clean Air Act 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 months ended March 31, 2021 and 2020.

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 three of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs.

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at eight 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 was submitted to the KDHE concerning this site in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan that will be submitted to the KDHE in 2021 for an additional site. At March 31, 2021, the reserve for remediation of our MGP sites was $13.7 million.

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 March 31, 2021, we have deferred $18.8 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 2021.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the Texas Commission on Environmental Quality, 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. Until the investigation is complete, we are unable to determine what, if any, active remediation will be required. A reliable estimate of potential remediation costs is not feasible at this point due to the amount of uncertainty as to the levels and extent of contamination.

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 months ended March 31, 2021 and 2020. 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. We do not expect expenditures for these matters to have a material adverse effect on our financial condition, results of operations or cash flows.

**Pipeline Safety -** We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated HCAs. In January 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act was signed into law. The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and the Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following:

- an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current HCAs;
- a verification of records for pipelines in class 3 and 4 locations and HCAs to confirm MAOPs; and
- a requirement to test previously untested pipelines operating above 30 percent yield strength in HCAs.

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 include changes to pipeline integrity-management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines. The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal. The GPAC met six times since January 2017 to review public comments and make recommendations to PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering pipelines. The GPAC met in June 2019 on gas gathering pipelines. In addition to reviewing public and committee comments, PHMSA announced they will split this NPRM into three separate final rulemakings:

- the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation Act and will be 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.

A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas transmission and 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. The estimated capital and operating expenditures associated with compliance with the first final rule 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 regulations. We do not expect to be impacted by the third final rule, as we do not own gas gathering pipelines.

**Air and Water Emissions -** The Clean Air Act, the Clean Water Act, 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. Under the Clean Air Act, 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. We do not expect that these expenditures will have a material impact on our respective results of operations, financial position or cash flows. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.

International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to regulate greenhouse gas emissions. 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.

**CERCLA -** 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) that caused and/or contributed to the release of a hazardous substance into the environment. 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. We do not expect that our responsibilities under CERCLA will have a material impact on our respective results of operations, financial position or cash flows.

**Pipeline Security -** The U.S. Department of Homeland Security’s Transportation Security Administration issued updated pipeline security guidelines in March 2018. Our pipeline facilities have been reviewed according to the current guidelines and no material changes have been required to date.

**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; (2) improving the integrity of and reducing leaks on our pipelines; (3) following developing technologies for reducing emissions; (4) promoting end-use conservation through programs that incentivize and inform customers regarding the use of high-efficiency equipment; and (5) reducing the release of methane into the atmosphere from operational practices, such as blow-downs, and third party line hits. In addition, RNG and hydrogen technologies offer potential opportunities to secure new natural gas supply sources that could be transported on our pipeline system and reduce greenhouse gas emissions.

We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on reducing emissions through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. Additionally, in March 2016, we were one of 40 founding partners to launch the EPA’s

Natural Gas STAR Methane Challenge Program, whereby oil and natural gas companies agree to promote and track commitments to reduce methane emissions beyond what is federally required. Our Methane Challenge Program commitment to annually replace or rehabilitate at least two percent of our combined inventory of cast iron and noncathodically-protected steel pipe 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 in 2016, 2017, 2018, and 2019 and anticipate reporting on our 2020 progress in 2021.

In September 2020, we announced membership in Our Nation’s Energy Future (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. In its most recent report, ONE Future reported that its members registered a 2019 methane intensity of 0.334%.

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-months ended March 31, 2021 and 2020.

**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 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), 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;
- 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;
- regulations in local jurisdictions in which we operate authorizing utilities to record in a regulatory asset account or comparable account the expenses associated with Winter Storm Uri, including but not limited to gas costs, other costs related to the procurement and transportation of gas supply and the associated financing costs;
- 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, and the measures that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address it, which may (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;
- conservation and energy efficiency efforts of our customers;
- adverse weather conditions and variations in weather, including seasonal effects on demand and/or supply, the occurrence of storms, including Winter Storm Uri in the territories in which we operate and the related effects on supply, demand, and costs and disasters, and climate change;
- 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, margin 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 borrow funds, if needed, to meet our liquidity needs including raising the funds 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;
- 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 conditions in these areas’ housing markets;
- acts of nature and the potential effects of threatened or actual terrorism and war;
- 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;
- 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;
- discovery of material weaknesses in our internal controls;
- our ability to comply with all covenants in our indentures, 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, and 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
- the 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, 3,432 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. We may use derivative instruments to economically hedge the cost of 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 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 expect to 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 2.2 million customers across three states, we are not exposed materially to a concentration of credit risk. As a result of regulatory orders and safety considerations, customer disconnects for nonpayment were generally suspended beginning mid-March 2020 through April 2021, when disconnects were resumed in all service areas, except Texas, which is still subject to a moratorium. 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 March 31, 2021, no regulatory assets have been recorded. 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. 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 first quarter ended March 31, 2021, 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 May 4, 2021.
Source: SEC EDGAR, the filing index for accession 0001587732-21-000045. Last ingested by Listed: Nov 3, 2026, 18:56 ET. No prices; not investment advice.