UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X☒Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended SeptemberJune 30, 2017.2022.
OR
___☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from __________ to __________.
Commission file number 001-36108
ONE Gas, Inc.
(Exact name of registrant as specified in its charter)
|
| | | | | | | |
| Oklahoma | 46-3561936 |
(State or other jurisdiction of
incorporation or organization)
| (I.R.S. Employer Identification No.) |
| |
15 East Fifth Street Tulsa, OK | 74103 |
| Tulsa, | OK | 74103 |
(Address of principal
executive offices) | (Zip Code) |
Registrant’s telephone number, including area code (918) 947-7000
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | | | | | | | |
| Title of each class | | Trading Symbol | | Name of exchange on which registered |
| Common Stock, par value $0.01 per share | | OGS | | New York Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X☒ No __☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Yes X No __
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
| | | | | | | | | | | |
| Large accelerated filer | ☒ | Accelerated filer | ☐ |
| | | |
| Non-accelerated filer | ☐ | Smaller reporting company | ☐ |
| | | |
| |
Large accelerated filer X
| Accelerated filer __ |
| |
Non-accelerated filer __ | (Do not check if a smaller reporting company) |
| |
| Smaller reporting company__ |
| |
| Emerging growth company__company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.__Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Yes __ No X
On October 24, 2017,July 25, 2022, the Company had 52,273,78354,137,522 shares of common stock outstanding.
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ONE Gas, Inc.
TABLE OF CONTENTS
|
| | | | | | | |
| Financial Information | Page No. |
| | |
| Consolidated Statements of Income - Three and NineSix Months Ended SeptemberJune 30, 20172022 and 20162021 | |
| Consolidated Statements of Comprehensive Income - Three and NineSix Months Ended SeptemberJune 30, 20172022 and 20162021 | |
| Consolidated Balance Sheets - SeptemberJune 30, 20172022 and December 31, 20162021 | |
| Consolidated Statements of Cash Flows - NineSix Months Ended SeptemberJune 30, 20172022 and 20162021 | |
| StatementConsolidated Statements of Equity - NineThree and Six Months Ended SeptemberJune 30, 20172022 and 2021 | |
| Notes to theConsolidated Financial Statements | |
| | |
| | |
| | |
| Other Information | | |
| Legal Proceedings | | |
| Risk Factors | | |
| | |
| | |
| | |
| Other Information | | |
| Exhibits | | |
| | |
As used in this Quarterly Report, references to “we,” “our,” “us” or the “company”“Company” refer to ONE Gas, Inc., an Oklahoma corporation, and its predecessors and subsidiary,subsidiaries, unless the context indicates otherwise.
The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled”“scheduled,” “likely” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations orand assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Forward-Looking Statements,” and Part II, Item 1A, “Risk Factors” in this Quarterly Report and under Part I, Item IA, “Risk Factors,” in our Annual Report.
AVAILABLE ON OUR WEBSITEINFORMATION
We make available, free of charge, on our website (www.onegas.com) copies of(www.onegas.com) our Annual Reports, on Form 10-K, Quarterly Reports, on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of ourSEC, which also makes these materials available on its website (www.sec.gov). Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Certificate of Incorporation, bylaws, the written charters of our Audit Committee, Executive Compensation Committee, Corporate Governance Committee and Director Independence GuidelinesExecutive Committee and our ESG Report are also available on our website, and we will provide copies of these documents are available upon request. Our
In addition to filings with the SEC and materials posted on our website, we also use social media platforms as channels of information distribution to reach public investors. Information contained on our website and any contents thereof areposted on or disseminated through our social media accounts is not incorporated by reference into this report.
We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.
GLOSSARY
- The abbreviations, acronyms and industry terminology used in this Quarterly Report are defined as follows:
|
| | | | |
| AAO | Accounting Authority Order |
| ADIT | Accumulated deferred income taxes |
| Annual Report | Annual Report on Form 10-K for the year ended December 31, 20162021 |
ASUASC | Accounting Standards Codification |
| ASU | Accounting Standards Update |
| Bcf | Billion cubic feet |
CERCLACAA | Federal Clean Air Act, as amended |
| CERCLA | Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended |
Clean Air ActCISA | Federal Clean Air Act, as amendedCybersecurity, & Infrastructure Security Agency |
| Clean Water Act | Federal Water Pollution Control Amendments of 1972, as amended |
| COSA | Cost-of-Service Adjustment |
DOTCOVID-19 | United States Department of TransportationCoronavirus Disease 2019 |
EPAEDIT | Excess accumulated deferred income taxes resulting from a change in enacted tax rates |
| EPA | United States Environmental Protection Agency |
| EPS | Earnings per share |
| ESG | Environmental, social and governance |
| Exchange Act | Securities Exchange Act of 1934, as amended |
| FASB | Financial Accounting Standards Board |
| GAAP | Accounting principles generally accepted in the United States of America |
GPACGRIP | Gas Pipeline Advisory Committee |
GRIP | Texas Gas Reliability Infrastructure Program |
| GSRS | Kansas Gas System Reliability Surcharge |
Heating Degree Day or HDD
| A measure designed to reflect the demand for energy needed for heating based on the extent to which the daily average temperature falls below a reference temperature for which no heating is required, usually 65 degrees Fahrenheit
|
IRSHCA(s) | Internal Revenue ServiceHigh consequence area(s) |
| KCC | Kansas Corporation Commission |
| KDHE | Kansas Department of Health and Environment |
| LDC | Local distribution company |
MGPLIBOR | Manufactured Gas PlantLondon Interbank Offered Rate |
MMcfMAOP(s) | Maximum allowable operating pressure(s) |
| MGP | Manufactured gas plant |
| MMcf | Million cubic feet |
| Moody’s | Moody’s Investors Service, Inc. |
| NPRM | Notice of Proposed Rulemaking |
NYMEXNYSE | New York MercantileStock Exchange |
| OCC | Oklahoma Corporation Commission |
| ODFA | Oklahoma Development Finance Authority |
| ONE Gas | ONE Gas, Inc. |
| ONE Gas 2021 Term Loan Facility | ONE Gas’ $2.5 billion two-year unsecured term loan facility, dated February 22, 2021, which terminated on March 11, 2021 |
| ONE Gas 364-day Credit Agreement | ONE Gas’ $250 million 364-day revolving credit agreement, dated April 7, 2020, which terminated on March 16, 2021 |
| ONE Gas Credit Agreement | ONE Gas’ $700 million$1.0 billion second amended and restated revolving credit agreement as amended,dated March 16, 2021, which expires on October 5, 2022March 16, 2026 |
ONEOKPBRC | ONEOK, Inc. and its subsidiaries |
PBRC | Performance-Based Rate Change |
| PHMSA | United States Department of Transportation Pipeline and Hazardous Materials Safety Administration |
Pipeline Safety, Regulatory Certainty
and Job Creation Act
| Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, as amended |
| Quarterly Report(s) | Quarterly Report(s) on Form 10-Q |
| RNG | Renewable natural gas |
| RRC | Railroad Commission of Texas |
| S&P | Standard & Poor’s Ratings Services |
| SEC | Securities and Exchange Commission |
| Securities Act | Securities Act of 1933, as amended |
| Senior Notes | ONE Gas’ registered notes consisting of $300 million$1.0 billion of 2.070.85 percent senior notes due 2019,March 2023, $400 million of floating-rate senior notes due March 2023, $700 million of 1.10 percent senior notes due March 2024, $300 million of 3.61 percent senior notes due February 2024, and$300 million of 2.00 percent senior notes due May 2030, $600 million of 4.658 percent senior notes due 2044.
February 2044 and $400 million of 4.50 percent notes due November 2048 |
Separation and Distribution AgreementSOFR | Separation and Distribution Agreement dated January 14, 2014, between ONEOK
and ONE Gas
Secured Overnight Financing Rate |
WNATCEQ | Weather-normalization adjustmentsTexas Commission on Environmental Quality |
XBRLTPFA | Texas Public Finance Authority |
| TSA | Transportation Security Administration |
| WNA | Weather normalization adjustment(s) |
| XBRL | eXtensible Business Reporting Language |
PART I - FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
| | | ONE Gas, Inc. |
| |
| |
|
|
|
| ONE Gas, Inc. | | | | | |
| STATEMENTS OF INCOME |
| |
| |
|
|
|
| |
| CONSOLIDATED STATEMENTS OF INCOME | | CONSOLIDATED STATEMENTS OF INCOME | | | | | |
|
| Three Months Ended |
| Nine Months Ended | | Three Months Ended | | Six Months Ended |
| |
| September 30, |
| September 30, | | | June 30, | | June 30, |
(Unaudited) |
| 2017 |
| 2016 |
| 2017 |
| 2016 | (Unaudited) | | 2022 | | 2021 | | 2022 | | 2021 |
|
| (Thousands of dollars, except per share amounts) | | (Thousands of dollars, except per share amounts) |
| Revenues |
| $ | 247,142 |
|
| $ | 232,191 |
|
| $ | 1,077,239 |
|
| $ | 986,479 |
| |
| | Total revenues | | Total revenues | | $ | 428,975 | | | $ | 315,646 | | | $ | 1,400,434 | | | $ | 940,939 | |
| | Cost of natural gas |
| 58,769 |
|
| 52,253 |
|
| 404,495 |
|
| 344,439 |
| Cost of natural gas | | 188,251 | | | 93,701 | | | 828,197 | | | 407,770 | |
| Net margin |
| 188,373 |
|
| 179,938 |
|
| 672,744 |
|
| 642,040 |
| |
| | Operating expenses |
| |
|
| |
|
|
|
|
|
|
| Operating expenses | |
| Operations and maintenance |
| 95,371 |
|
| 99,402 |
|
| 305,969 |
|
| 302,652 |
| Operations and maintenance | | 110,579 | | | 103,534 | | | 225,674 | | | 214,420 | |
| Depreciation and amortization |
| 38,423 |
|
| 36,241 |
|
| 113,293 |
|
| 106,490 |
| Depreciation and amortization | | 55,043 | | | 50,872 | | | 112,180 | | | 103,138 | |
| General taxes |
| 13,799 |
|
| 13,403 |
|
| 43,518 |
|
| 42,311 |
| General taxes | | 16,533 | | | 16,437 | | | 35,057 | | | 34,164 | |
| Total operating expenses |
| 147,593 |
|
| 149,046 |
|
| 462,780 |
|
| 451,453 |
| Total operating expenses | | 182,155 | | | 170,843 | | | 372,911 | | | 351,722 | |
| Operating income |
| 40,780 |
|
| 30,892 |
|
| 209,964 |
|
| 190,587 |
| Operating income | | 58,569 | | | 51,102 | | | 199,326 | | | 181,447 | |
| Other income |
| 1,042 |
|
| 911 |
|
| 3,163 |
|
| 1,345 |
| |
| Other expense |
| (444 | ) |
| (357 | ) |
| (1,246 | ) |
| (1,126 | ) | |
| Other income (expense), net | | Other income (expense), net | | (3,983) | | | 451 | | | (8,128) | | | 46 | |
| Interest expense, net |
| (11,495 | ) |
| (10,809 | ) |
| (34,281 | ) |
| (32,504 | ) | Interest expense, net | | (16,320) | | | (14,996) | | | (31,915) | | | (30,436) | |
| Income before income taxes |
| 29,883 |
|
| 20,637 |
|
| 177,600 |
|
| 158,302 |
| Income before income taxes | | 38,266 | | | 36,557 | | | 159,283 | | | 151,057 | |
| Income taxes |
| (11,086 | ) |
| (7,900 | ) |
| (61,724 | ) |
| (60,521 | ) | Income taxes | | (6,191) | | | (6,464) | | | (28,274) | | | (25,389) | |
| Net income |
| $ | 18,797 |
|
| $ | 12,737 |
|
| $ | 115,876 |
|
| $ | 97,781 |
| Net income | | $ | 32,075 | | | $ | 30,093 | | | $ | 131,009 | | | $ | 125,668 | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Earnings per share |
|
|
|
|
|
|
|
|
|
|
|
| Earnings per share | |
| Basic |
| $ | 0.36 |
|
| $ | 0.24 |
|
| $ | 2.21 |
|
| $ | 1.86 |
| Basic | | $ | 0.59 | | | $ | 0.56 | | | $ | 2.42 | | | $ | 2.35 | |
| Diluted |
| $ | 0.36 |
|
| $ | 0.24 |
|
| $ | 2.19 |
|
| $ | 1.85 |
| Diluted | | $ | 0.59 | | | $ | 0.56 | | | $ | 2.42 | | | $ | 2.35 | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average shares (thousands) |
|
|
|
|
|
|
|
|
|
|
|
| Average shares (thousands) | |
| Basic |
| 52,488 |
|
| 52,453 |
|
| 52,539 |
|
| 52,452 |
| Basic | | 54,262 | | | 53,466 | | | 54,092 | | | 53,419 | |
| Diluted |
| 52,926 |
|
| 52,942 |
|
| 52,984 |
|
| 52,962 |
| Diluted | | 54,335 | | | 53,548 | | | 54,183 | | | 53,531 | |
| | Dividends declared per share of stock |
| $ | 0.42 |
|
| $ | 0.35 |
|
| $ | 1.26 |
|
| $ | 1.05 |
| Dividends declared per share of stock | | $ | 0.62 | | | $ | 0.58 | | | $ | 1.24 | | | $ | 1.16 | |
See accompanying Notes to theConsolidated Financial Statements.
|
| | | | | | | | | | | | | | | |
| ONE Gas, Inc. | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | |
| | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
(Unaudited) | 2017 | | 2016 | | 2017 | | 2016 |
| | (Thousands of dollars) |
| Net income | $ | 18,797 |
| | $ | 12,737 |
| | $ | 115,876 |
| | $ | 97,781 |
|
| Other comprehensive income (loss), net of tax | |
| | |
| | |
| | |
|
| Change in pension and other postemployment benefit plan liability, net of tax of $(81), $(72), $(242) and $(217), respectively | 128 |
| | 116 |
| | 386 |
| | 347 |
|
| Total other comprehensive income, net of tax | 128 |
| | 116 |
| | 386 |
| | 347 |
|
| Comprehensive income | $ | 18,925 |
| | $ | 12,853 |
| | $ | 116,262 |
| | $ | 98,128 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ONE Gas, Inc. | | | | | | | | |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | |
| | | Three Months Ended | | Six Months Ended |
| | | June 30, | | June 30, |
(Unaudited) | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (Thousands of dollars) |
| Net income | | $ | 32,075 | | | $ | 30,093 | | | $ | 131,009 | | | $ | 125,668 | |
| Other comprehensive income, net of tax | | | | | | | | |
| Change in pension and other postemployment benefit plan liability, net of tax of $(10), $(91), $(29) and $(182) respectively | | 30 | | | 299 | | | 99 | | | 599 | |
| Total other comprehensive income, net of tax | | 30 | | | 299 | | | 99 | | | 599 | |
| Comprehensive income | | $ | 32,105 | | | $ | 30,392 | | | $ | 131,108 | | | $ | 126,267 | |
See accompanying Notes to theConsolidated Financial Statements.
|
| | | | | | | | |
| ONE Gas, Inc. | | | | |
| BALANCE SHEETS | | | | |
| | | | | |
| | | September 30, | | December 31, |
(Unaudited) | | 2017 | | 2016 |
| Assets | | (Thousands of dollars) |
| Property, plant and equipment | | |
| | |
|
| Property, plant and equipment | | $ | 5,643,136 |
| | $ | 5,404,168 |
|
| Accumulated depreciation and amortization | | 1,730,857 |
| | 1,672,548 |
|
| Net property, plant and equipment | | 3,912,279 |
| | 3,731,620 |
|
| Current assets | | | | |
| Cash and cash equivalents | | 6,872 |
| | 14,663 |
|
| Accounts receivable, net | | 127,689 |
| | 290,944 |
|
| Materials and supplies | | 38,789 |
| | 34,084 |
|
| Natural gas in storage | | 157,641 |
| | 125,432 |
|
| Regulatory assets | | 99,548 |
| | 83,146 |
|
| Other current assets | | 15,014 |
| | 20,654 |
|
| Total current assets | | 445,553 |
| | 568,923 |
|
| Goodwill and other assets | | |
| | |
|
| Regulatory assets | | 411,653 |
| | 440,522 |
|
| Goodwill | | 157,953 |
| | 157,953 |
|
| Other assets | | 43,625 |
| | 43,773 |
|
| Total goodwill and other assets | | 613,231 |
| | 642,248 |
|
| Total assets | | $ | 4,971,063 |
| | $ | 4,942,791 |
|
| | | | | | | | | | | | | | |
| ONE Gas, Inc. | | | | |
| CONSOLIDATED BALANCE SHEETS | | | | |
| | | | |
| | | June 30, | | December 31, |
(Unaudited) | | 2022 | | 2021 |
| Assets | | (Thousands of dollars) |
| Property, plant and equipment | | | | |
| Property, plant and equipment | | $ | 7,494,631 | | | $ | 7,274,268 | |
| Accumulated depreciation and amortization | | 2,137,601 | | | 2,083,433 | |
| Net property, plant and equipment | | 5,357,030 | | | 5,190,835 | |
| Current assets | | | | |
| Cash and cash equivalents | | 7,385 | | | 8,852 | |
| Accounts receivable, net | | 242,671 | | | 341,756 | |
| Materials and supplies | | 62,819 | | | 54,892 | |
| | | | |
| Natural gas in storage | | 198,306 | | | 179,646 | |
| Regulatory assets | | 1,609,763 | | | 1,611,676 | |
| | | | |
| Other current assets | | 27,929 | | | 27,742 | |
| Total current assets | | 2,148,873 | | | 2,224,564 | |
| Goodwill and other assets | | | | |
| Regulatory assets | | 637,021 | | | 724,862 | |
| Goodwill | | 157,953 | | | 157,953 | |
| | | | |
| Other assets | | 110,535 | | | 103,906 | |
| Total goodwill and other assets | | 905,509 | | | 986,721 | |
| Total assets | | $ | 8,411,412 | | | $ | 8,402,120 | |
See accompanying Notes to theConsolidated Financial Statements.
| | | ONE Gas, Inc. | | | | | ONE Gas, Inc. | | | | |
| BALANCE SHEETS | | | | | |
| CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS | | | | |
| (Continued) | | | | | (Continued) | |
| | | September 30, | | December 31, | | | June 30, | | December 31, |
(Unaudited) | | 2017 | | 2016 | (Unaudited) | | 2022 | | 2021 |
| Equity and Liabilities | | (Thousands of dollars) | Equity and Liabilities | | (Thousands of dollars) |
| Equity and long-term debt | | | | | Equity and long-term debt | |
Common stock, $0.01 par value: authorized 250,000,000 shares; issued 52,598,005 shares and outstanding 52,273,444 shares at September 30, 2017; issued 52,598,005 and outstanding 52,283,260 shares at December 31, 2016 | | $ | 526 |
| | $ | 526 |
| |
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 54,137,217 shares at June 30, 2022; issued and outstanding 53,633,210 shares at December 31, 2021 | | Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 54,137,217 shares at June 30, 2022; issued and outstanding 53,633,210 shares at December 31, 2021 | | $ | 541 | | | $ | 536 | |
| Paid-in capital | | 1,735,638 |
| | 1,749,574 |
| Paid-in capital | | 1,830,678 | | | 1,790,362 | |
| Retained earnings | | 221,185 |
| | 161,021 |
| Retained earnings | | 628,805 | | | 565,161 | |
| Accumulated other comprehensive income (loss) | | (4,329 | ) | | (4,715 | ) | |
| Treasury stock, at cost: 324,561 shares at September 30, 2017 and 314,745 shares at December 31, 2016 | | (21,028 | ) | | (18,126 | ) | |
| Accumulated other comprehensive loss | | Accumulated other comprehensive loss | | (6,428) | | | (6,527) | |
| | Total equity | | 1,931,992 |
| | 1,888,280 |
| Total equity | | 2,453,596 | | | 2,349,532 | |
| Long-term debt, excluding current maturities, and net of issuance costs of $8,239 and $8,851, respectively | | 1,193,052 |
| | 1,192,446 |
| |
| Long-term debt, excluding current maturities and net of issuance costs of $12,038 and $12,418, respectively | | Long-term debt, excluding current maturities and net of issuance costs of $12,038 and $12,418, respectively | | 2,283,865 | | | 3,683,378 | |
| Total equity and long-term debt |
| 3,125,044 |
|
| 3,080,726 |
| Total equity and long-term debt | | 4,737,461 | | | 6,032,910 | |
| Current liabilities | | | | | Current liabilities | | | | |
| Notes payable | | 174,000 |
| | 145,000 |
| |
| Current maturities of long-term debt | | Current maturities of long-term debt | | 1,400,011 | | | 11 | |
| Short-term debt | | Short-term debt | | 490,100 | | | 494,000 | |
| Accounts payable | | 68,184 |
| | 131,988 |
| Accounts payable | | 186,425 | | | 258,554 | |
| Accrued interest | | 7,742 |
| | 18,854 |
| |
| | Accrued taxes other than income | | 44,658 |
| | 42,571 |
| Accrued taxes other than income | | 58,183 | | | 67,035 | |
| Accrued liabilities | | 18,535 |
| | 22,931 |
| |
| | Regulatory liabilities | | Regulatory liabilities | | 33,755 | | | 8,090 | |
| Customer deposits | | 59,643 |
| | 61,209 |
| Customer deposits | | 60,277 | | | 62,454 | |
| Other current liabilities | | 19,466 |
| | 21,380 |
| Other current liabilities | | 99,534 | | | 90,349 | |
| Total current liabilities | | 392,228 |
| | 443,933 |
| Total current liabilities | | 2,328,285 | | | 980,493 | |
| Deferred credits and other liabilities | | |
| | |
| Deferred credits and other liabilities | | | | |
| Deferred income taxes | | 1,089,061 |
| | 1,038,568 |
| Deferred income taxes | | 690,751 | | | 695,284 | |
| Regulatory liabilities | | Regulatory liabilities | | 538,717 | | | 552,928 | |
| Employee benefit obligations | | 282,904 |
| | 303,507 |
| Employee benefit obligations | | 25,131 | | | 35,226 | |
| Other deferred credits | | 81,826 |
| | 76,057 |
| Other deferred credits | | 91,067 | | | 105,279 | |
| Total deferred credits and other liabilities | | 1,453,791 |
| | 1,418,132 |
| Total deferred credits and other liabilities | | 1,345,666 | | | 1,388,717 | |
| Commitments and contingencies | |
|
| |
|
| Commitments and contingencies | | 0 | | 0 |
| Total liabilities and equity | | $ | 4,971,063 |
| | $ | 4,942,791 |
| Total liabilities and equity | | $ | 8,411,412 | | | $ | 8,402,120 | |
See accompanying Notes to theConsolidated Financial Statements.
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|
| | | | | | | | |
| ONE Gas, Inc. | | | | |
| STATEMENTS OF CASH FLOWS | | |
| | | Nine Months Ended |
| | | September 30, |
(Unaudited) | | 2017 | | 2016 |
| | | (Thousands of dollars) |
| Operating activities | | | | |
| Net income | | $ | 115,876 |
| | $ | 97,781 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | |
| Depreciation and amortization | | 113,293 |
| | 106,490 |
|
| Deferred income taxes | | 61,329 |
| | 59,771 |
|
| Share-based compensation expense | | 6,930 |
| | 9,341 |
|
| Provision for doubtful accounts | | 4,508 |
| | 3,521 |
|
| Changes in assets and liabilities: | | | | |
| Accounts receivable | | 158,747 |
| | 107,762 |
|
| Materials and supplies | | (4,705 | ) | | 3,227 |
|
| Natural gas in storage | | (32,209 | ) | | (2,077 | ) |
| Asset removal costs | | (37,928 | ) | | (40,715 | ) |
| Accounts payable | | (65,983 | ) | | (32,923 | ) |
| Accrued interest | | (11,112 | ) | | (11,182 | ) |
| Accrued taxes other than income | | 2,087 |
| | 2,670 |
|
| Accrued liabilities | | (4,396 | ) | | (13,658 | ) |
| Customer deposits | | (1,566 | ) | | 100 |
|
| Regulatory assets and liabilities | | 11,448 |
| | (18,726 | ) |
| Other assets and liabilities | | (13,915 | ) | | 19,053 |
|
| Cash provided by operating activities | | 302,404 |
| | 290,435 |
|
| Investing activities | | |
| | |
|
| Capital expenditures | | (249,057 | ) | | (231,336 | ) |
| Other | | 617 |
| | 492 |
|
| Cash used in investing activities | | (248,440 | ) | | (230,844 | ) |
| Financing activities | | |
| | |
|
| Borrowings (repayments) of notes payable, net | | 29,000 |
| | 28,500 |
|
| Repurchase of common stock | | (17,512 | ) | | (24,066 | ) |
| Issuance of common stock | | 2,208 |
| | 1,983 |
|
| Dividends paid | | (65,996 | ) | | (54,923 | ) |
| Tax withholdings related to net share settlements of stock compensation | | (9,455 | ) | | (9,005 | ) |
| Cash used in financing activities | | (61,755 | ) | | (57,511 | ) |
| Change in cash and cash equivalents | | (7,791 | ) | | 2,080 |
|
| Cash and cash equivalents at beginning of period | | 14,663 |
| | 2,433 |
|
| Cash and cash equivalents at end of period | | $ | 6,872 |
| | $ | 4,513 |
|
| | | | | | | | | | | | | | |
| ONE Gas, Inc. | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | | |
| | Six Months Ended |
| | June 30, |
(Unaudited) | | 2022 | | 2021 |
| | | (Thousands of dollars) |
| Operating activities | | | | |
| Net income | | $ | 131,009 | | | $ | 125,668 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | |
| Depreciation and amortization | | 112,180 | | | 103,138 | |
| Deferred income taxes | | (18,780) | | | 24,954 | |
| Share-based compensation expense | | 5,699 | | | 5,679 | |
| Provision for doubtful accounts | | 2,511 | | | 5,496 | |
| Changes in assets and liabilities: | | | | |
| Accounts receivable | | 100,955 | | | 126,842 | |
| Materials and supplies | | (7,927) | | | 691 | |
| Natural gas in storage | | (18,660) | | | 8,198 | |
| | | | |
| Asset removal costs | | (20,919) | | | (21,375) | |
| Accounts payable | | (92,887) | | | 13,519 | |
| | | | |
| Accrued taxes other than income | | (8,852) | | | (7,710) | |
| | | | |
| Customer deposits | | (2,177) | | | (11,263) | |
| Regulatory assets and liabilities - current | | 43,697 | | | 13,579 | |
| Regulatory assets and liabilities - noncurrent | | 56,135 | | | (1,931,332) | |
| Other assets and liabilities - current | | 8,234 | | | (14,300) | |
| Other assets and liabilities - noncurrent | | (3,541) | | | (19,132) | |
| Cash provided by (used in) operating activities | | 286,677 | | | (1,577,348) | |
| Investing activities | | | | |
| Capital expenditures | | (251,060) | | | (217,039) | |
| Other investing expenditures | | (1,332) | | | (2,821) | |
| Other investing receipts | | 891 | | | 716 | |
| Cash used in investing activities | | (251,501) | | | (219,144) | |
| Financing activities | | | | |
| Borrowings (repayments) on short-term debt, net | | (3,900) | | | (418,225) | |
| Issuance of debt, net of discounts | | — | | | 2,498,895 | |
| Long-term debt financing costs | | — | | | (35,110) | |
| Issuance of common stock | | 37,104 | | | 18,122 | |
| | | | |
| Dividends paid | | (66,821) | | | (61,785) | |
| Tax withholdings related to net share settlements of stock compensation | | (3,026) | | | (4,328) | |
| Cash provided by (used in) financing activities | | (36,643) | | | 1,997,569 | |
| Change in cash and cash equivalents | | (1,467) | | | 201,077 | |
| Cash and cash equivalents at beginning of period | | 8,852 | | | 7,993 | |
| Cash and cash equivalents at end of period | | $ | 7,385 | | | $ | 209,070 | |
See accompanying Notes to theConsolidated Financial Statements.
|
| | | | | | | | | |
| ONE Gas, Inc. | | | | |
| STATEMENT OF EQUITY | | | | |
| | | | | |
(Unaudited) | | Common Stock Issued | Common Stock | Paid-in Capital |
| | | (Shares) | (Thousands of dollars) |
| | | | | |
| January 1, 2017 | | 52,598,005 |
| $ | 526 |
| $ | 1,749,574 |
|
Cumulative effect of accounting change
| | — |
| — |
| — |
|
| Net income | | — |
| — |
| — |
|
| Other comprehensive income | | — |
| — |
| — |
|
| Repurchase of common stock | | — |
| — |
| — |
|
| Common stock issued and other | | — |
| — |
| (14,634 | ) |
| Common stock dividends - $1.26 per share | | — |
| — |
| 698 |
|
| September 30, 2017 | | 52,598,005 |
| $ | 526 |
| $ | 1,735,638 |
|
| | | | | | | | | | | | | | |
| ONE Gas, Inc. | | | | |
| CONSOLIDATED STATEMENTS OF EQUITY | | | | |
| | | | |
(Unaudited) | | Common Stock Issued | Common Stock | Paid-in Capital |
| | | (Shares) | (Thousands of dollars) |
| | | | |
| January 1, 2022 | | 53,633,210 | | $ | 536 | | $ | 1,790,362 | |
| Net income | | — | | — | | — | |
| Other comprehensive income | | — | | — | | — | |
| Common stock issued and other | | 456,607 | | 5 | | 34,135 | |
| Common stock dividends - $0.62 per share | | — | | — | | 274 | |
| March 31, 2022 | | 54,089,817 | | $ | 541 | | $ | 1,824,771 | |
| Net income | | — | | — | | — | |
| Other comprehensive income | | — | | — | | — | |
| Common stock issued and other | | 47,400 | | — | | 5,636 | |
| Common stock dividends - $0.62 per share | | — | | — | | 271 | |
| June 30, 2022 | | 54,137,217 | | $ | 541 | | $ | 1,830,678 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| January 1, 2021 | | 53,166,733 | | $ | 532 | | $ | 1,756,921 | |
| Net income | | — | | — | | — | |
| Other comprehensive income | | — | | — | | — | |
| Common stock issued and other | | 78,278 | | — | | (1,705) | |
| Common stock dividends - $0.58 per share | | — | | — | | 260 | |
| March 31, 2021 | | 53,245,011 | | $ | 532 | | $ | 1,755,476 | |
| Net income | | — | | — | | — | |
| Other comprehensive income | | — | | — | | — | |
| Common stock issued and other | | 254,226 | | 3 | | 21,175 | |
| Common stock dividends - $0.58 per share | | — | | — | | 260 | |
| June 30, 2021 | | 53,499,237 | | $ | 535 | | $ | 1,776,911 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
See accompanying Notes to theConsolidated Financial Statements.
| | | ONE Gas, Inc. | | | | ONE Gas, Inc. | | | | |
| STATEMENT OF EQUITY | | |
| CONSOLIDATED STATEMENTS OF EQUITY | | CONSOLIDATED STATEMENTS OF EQUITY | | |
| (Continued) | | | (Continued) | | | |
(Unaudited) | | Retained Earnings | Treasury Stock | Accumulated Other Comprehensive Income (Loss) | Total Equity | (Unaudited) | | Retained Earnings | | Accumulated Other Comprehensive Loss | Total Equity |
| | | (Thousands of dollars) | | | (Thousands of dollars) |
| | | | | | |
| January 1, 2017 | | $ | 161,021 |
| $ | (18,126 | ) | $ | (4,715 | ) | $ | 1,888,280 |
| |
Cumulative effect of accounting change
| | 10,982 |
| — |
| — |
| 10,982 |
| |
| January 1, 2022 | | January 1, 2022 | | $ | 565,161 | | | $ | (6,527) | | $ | 2,349,532 | |
| Net income | | 115,876 |
| — |
| — |
| 115,876 |
| Net income | | 98,934 | | | — | | 98,934 | |
| Other comprehensive income | | — |
| — |
| 386 |
| 386 |
| Other comprehensive income | | — | | | 69 | | 69 | |
| Repurchase of common stock | | — |
| (17,512 | ) | — |
| (17,512 | ) | |
| Common stock issued and other | | — |
| 14,610 |
| — |
| (24 | ) | Common stock issued and other | | — | | | — | | 34,140 | |
| Common stock dividends - $1.26 per share | | (66,694 | ) | — |
| — |
| (65,996 | ) | |
| September 30, 2017 | | $ | 221,185 |
| $ | (21,028 | ) | $ | (4,329 | ) | $ | 1,931,992 |
| |
| Common stock dividends - $0.62 per share | | Common stock dividends - $0.62 per share | | (33,559) | | | — | | (33,285) | |
| March 31, 2022 | | March 31, 2022 | | $ | 630,536 | | | $ | (6,458) | | $ | 2,449,390 | |
| Net income | | Net income | | 32,075 | | | — | | 32,075 | |
| Other comprehensive income | | Other comprehensive income | | — | | | 30 | | 30 | |
| Common stock issued and other | | Common stock issued and other | | — | | | — | | 5,636 | |
| Common stock dividends - 0.62 per share | | Common stock dividends - 0.62 per share | | (33,806) | | | — | | (33,535) | |
| June 30, 2022 | | June 30, 2022 | | $ | 628,805 | | | $ | (6,428) | | $ | 2,453,596 | |
| | | January 1, 2021 | | January 1, 2021 | | $ | 483,635 | | | $ | (7,777) | | $ | 2,233,311 | |
| Net income | | Net income | | 95,575 | | | — | | 95,575 | |
| Other comprehensive income | | Other comprehensive income | | — | | | 300 | | 300 | |
| Common stock issued and other | | Common stock issued and other | | — | | | — | | (1,705) | |
| Common stock dividends - $0.58 per share | | Common stock dividends - $0.58 per share | | (31,142) | | | — | | (30,882) | |
| March 31, 2021 | | March 31, 2021 | | $ | 548,068 | | | $ | (7,477) | | $ | 2,296,599 | |
| Net income | | Net income | | 30,093 | | | — | | 30,093 | |
| Other comprehensive income | | Other comprehensive income | | — | | | 299 | | 299 | |
| Common stock issued and other | | Common stock issued and other | | — | | | — | | 21,178 | |
| Common stock dividends - $0.58 per share | | Common stock dividends - $0.58 per share | | (31,163) | | | — | | (30,903) | |
| June 30, 2021 | | June 30, 2021 | | $ | 546,998 | | | $ | (7,178) | | $ | 2,317,266 | |
|
See accompanying Notes to theConsolidated Financial Statements.
ONE Gas, Inc.
NOTES TO THECONSOLIDATED FINANCIAL STATEMENTS
| |
1. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements also have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 20162021 year-end consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and footnotes in our Annual Report. Our significant accounting policies are described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and ninesix months ended SeptemberJune 30, 2017,2022, are not necessarily indicative of the results that may be expected for a 12-month period.
We provide natural gas distribution services to more than 2our approximately 2.3 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We primarily serve residential, commercial industrial and transportation customers in all three states. In addition, we also provide natural gas distribution services to wholesale and public authority customers.
Other - In October 2017, we filed and received approval from the Oklahoma Insurance Department to form a wholly-owned captive insurance company.
Use of Estimates - 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 amount 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 revenue and expensesexpense during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provisionprovisions for doubtful accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred income tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.
We evaluate these estimates on an ongoing basis using historical experience and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.
Segments - We operate in one reportable and operating business segment: regulated public utilities that deliver natural gas primarily to residential, commercial industrial, wholesale, public authority and transportation customers. The accounting policies for our segment are the same as those described in Note 1 of our Notes to theConsolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on operatingnet income. For the three and ninesix months ended SeptemberJune 30, 2017,2022 and 2016,2021, we had no single external customer from which we received 10 percent or more of our gross revenues.
Goodwill Impairment TestProperty, Plant and Equipment and Asset Removal Costs - Accounts payable for construction work in process and asset removal costs decreased by approximately $7.8 million and $7.5 million for the six months ended June 30, 2022 and 2021, respectively. Such amounts are not included in capital expenditures or asset removal costs in our consolidated statements of cash flows.
Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for natural gas sold or services rendered, net of allowances for doubtful accounts. We assess our goodwill for impairment at least annually as of July 1. At July 1, 2017, we assessed qualitative factors to determine whether it was more likely than not that the fair valuecreditworthiness of our reporting unitcustomers. Those customers who do not meet minimum standards may be required to provide security, including deposits and other forms of collateral, when appropriate and allowed by our tariffs. With approximately 2.3 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain an allowance for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current environment and other information. We recover natural gas costs related to accounts written off when they are deemed uncollectible through the purchased-gas cost adjustment mechanisms in each of our jurisdictions. At June 30, 2022 and December 31, 2021, our allowance for doubtful accounts was less than its carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry$18.9 million and market considerations, cost factors and overall financial performance), we determined that no further testing was necessary.$18.7 million, respectively.
Recently Issued Accounting Standards Update - In August 2017,November 2021, the FASB issued ASU 2017-12, “Derivatives and Hedging2021-10, “Government Assistance (Topic 815)832): Targeted Improvements to Accounting for Hedging Activities,Disclosures by Business Entities about Government Assistance,” which allows more types of hedging strategieswill require disclosure about government assistance in the notes to be eligiblethe financial statements. The amendment requires annual disclosures about transactions with a government that are accounted for hedgeby applying a grant or contribution accounting and simplifies application of hedge accounting. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted, but must be applied as of the beginning of the fiscal year, or initial application date. The impact of this guidance is not material to us, as we have not elected hedge accounting due tomodel by analogy, including
information about the nature of the types of derivatives we have entered.
In March 2017,transactions and the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires (1) separation of net periodic service costs for pension and other postemployment benefits into service cost and other components, (2) presentation of the service cost component in the same line as other compensation costs rendered by pertinent employees during the period, and (3) reporting the other components of net periodic benefit costs separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization, when
applicable. However, all of our cost components remain eligible for capitalization under therelated accounting requirements for rate regulated entities.
We will adopt this guidance for our interim and annual reports for periods in the first quarter of 2018. When adopted, the presentation changes required for net periodic benefit costs will not impact previously reported net income; however, the reclassification of the other components of benefits costs will result in an increase in operating income and an increase in other expenses for 2016 and 2017. We will use the retroactive presentation that permits the use of the amounts disclosed for the various components of net benefit cost in our respective Annual Report’s Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we are currently updating our systems for the capitalization of service costs to property and non-service costs to a regulatory asset on a prospective basis, as well as the appropriate accounts for non-service costs to apply retroactive reclassification.
In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 of the goodwill test, where the measurement of a goodwill impairment loss was determined by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Upon adoption, a goodwill impairment will be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. We early adopted this new guidance in the current quarter, and it did not have an impact on our financial statements. See our conclusions regarding our current year Goodwill Impairment Test above.
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments,’’ which introduces new guidance to the accounting for credit losses on instruments within its scope, including trade receivables. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and may be adopted a year earlier. The new guidance will be initially applied through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. We are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of 2021.
In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” which includes various new aspects to simplify how share-based payments are accounted for and presented in the financial statements. The new standard modifies several aspects of the accounting and reporting for employee share-based payments and related tax accounting impacts, including the presentation in the statements of operations and cash flows. We adopted this new guidance in the first quarter 2017, and in accordance with the transition requirements, we recorded $5.2 million of excess tax benefit in income tax expense and have transitioned all provisions of this new guidance prospectively, other than our presentation of our withholding shares for tax-withholding purposes, which we accounted for retrospectively in the financing activities section of the statement of cash flows. We recorded a noncash cumulative-effect increase of $11.0 million to retained earnings, with an offset to a deferred tax asset, as of the beginning of the reporting period in 2017, for excess tax benefits earned prior to January 1, 2017, that had not been recognized. We continue our use of the estimation methodpolicy used to account for share unit award forfeitures rather than actual forfeitures. The retrospective impact of our withholding shares for tax-withholding purposes to our Statement of Cash Flows for the nine months ended September 30, 2016, was a $9.0 million increase to net cash provided by operating activities and a $9.0 million decrease to net cash used in financing activities.
In February 2016,transactions, the FASB issued ASU 2016-02, “Leases (Topic 842),” which prescribes recognizing lease assets and liabilitiesline items on the balance sheet and includes disclosure of key information about leasing arrangements. A modified retrospective transition approach is required for leases existing atincome statement that are affected by the time of adoption. We are evaluating our population of leases, analyzing lease agreements, and holding meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operationstransactions and the transition approach we will utilize. We are also continuingsignificant terms and conditions of the transactions, including commitments and contingencies. The amendment became effective for us beginning January 1, 2022. As the guidance is related only to monitordisclosures in the FASB for additional guidance surrounding an exposure draft regarding land easements. This information will help us determine what information will ultimately be disclosed in ournotes to the financial statements, and footnotes. Until this item is resolved, we cannot complete our evaluation of the potential effect the new guidance will havedo not anticipate any impact on our financial position, results of operations or cash flows or business processes. We will adopt this new guidanceflows.
2.REVENUE
The following table sets forth our revenues disaggregated by source for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended | | |
| | June 30, | | June 30, | | |
| | 2022 | | 2021 | | 2022 | | 2021 | | | | |
| | (Thousands of dollars) |
| Natural gas sales to customers | | $ | 393,292 | | | $ | 281,450 | | | $ | 1,318,449 | | | $ | 865,244 | | | | | |
| Transportation revenues | | 28,000 | | | 26,216 | | | 64,316 | | | 62,418 | | | | | |
| Miscellaneous revenues | | 5,128 | | | 4,073 | | | 9,624 | | | 7,728 | | | | | |
| Total revenues from contracts with customers | | 426,420 | | | 311,739 | | | 1,392,389 | | | 935,390 | | | | | |
| Other revenues - natural gas sales related | | (115) | | | 1,325 | | | 2,231 | | | 304 | | | | | |
| Other revenues | | 2,670 | | | 2,582 | | | 5,814 | | | 5,245 | | | | | |
| Total other revenues | | 2,555 | | | 3,907 | | | 8,045 | | | 5,549 | | | | | |
| Total revenues | | $ | 428,975 | | | $ | 315,646 | | | $ | 1,400,434 | | | $ | 940,939 | | | | | |
Accrued unbilled natural gas sales revenues at June 30, 2022 and December 31, 2021, were $71.9 million and $183.2 million, respectively, and are included in the first quarter of 2019.
In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards. In July 2015, FASB delayed the effective date for one year. We have substantially completed evaluating all of our sources of revenue to determine the potential effectaccounts receivable on our financial position, results of operations, cash flows and the related accounting policies and business processes. We will adopt this new guidance for our interim and annual reports beginning in the first quarter 2018, using the modified retrospective method. Through our preliminary evaluation, we do not expect a cumulative adjustment to our opening retained earnings, if any, would be material. The only impact we expect would be a reclassification of certain revenuesconsolidated balance sheets.
that do not meet the requirements under ASC 606 as revenues from contracts with customers, but will continue to be reflected as other revenues in determining total revenue. The items we expect to reclassify relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we account for variations in weather. We have determined the majority of our tariffs to be contracts with customers which are settled over time, where our performance obligation is settled with our customer when natural gas is received and simultaneously consumed. In addition, we will elect to use the invoice method, where we will recognize revenue for volumes delivered for which we have a right to invoice.
3. REGULATORY ASSETS AND LIABILITIES
We will continue monitoring the accounting task forces and FASB for the final conclusions surrounding revenue recognition implementation guidance. This guidance will determine what will ultimately be disclosed in our financial statements and footnotes. In addition to updating our revenue recognition disclosures, additional disclosures may include disaggregation of revenues by types of service, source of revenue or customer class, performance obligations and other types of revenues. Until these items are resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes.
| |
2. | REGULATORY ASSETS AND LIABILITIES |
The tables below present a summary of regulatory assets and liabilities, net of amortization, and liabilities for the periods indicated:
| | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 |
| | Current | | Noncurrent | | Total |
| | (Thousands of dollars) |
| Winter weather event costs | | $ | 1,560,219 | | | $ | 350,243 | | | $ | 1,910,462 | |
| Under-recovered purchased-gas costs | | 5,189 | | | — | | | 5,189 | |
| Pension and postemployment benefit costs | | 4,010 | | | 250,630 | | | 254,640 | |
| Reacquired debt costs | | 811 | | | 3,708 | | | 4,519 | |
| MGP remediation costs | | 98 | | | 29,792 | | | 29,890 | |
| Ad-valorem tax | | 10,002 | | | — | | | 10,002 | |
| WNA | | 10,791 | | | — | | | 10,791 | |
| Customer credit deferrals | | 16,408 | | | — | | | 16,408 | |
| Other | | 2,235 | | | 2,648 | | | 4,883 | |
| Total regulatory assets, net of amortization | | 1,609,763 | | | 637,021 | | | 2,246,784 | |
| Income tax rate changes | | — | | | (538,717) | | | (538,717) | |
| Over-recovered purchased-gas costs | | (33,755) | | | — | | | (33,755) | |
| Total regulatory liabilities | | (33,755) | | | (538,717) | | | (572,472) | |
| Net regulatory assets and liabilities | | $ | 1,576,008 | | | $ | 98,304 | | | $ | 1,674,312 | |
| | | | | | | | | | | | December 31, 2021 |
| | | September 30, 2017 | | Current | | Noncurrent | | Total |
| | | Current | | Noncurrent | | Total | | (Thousands of dollars) |
| | | (Thousands of dollars) | |
| Winter weather event costs | | Winter weather event costs | | $ | 1,536,054 | | | $ | 428,023 | | | $ | 1,964,077 | |
| Under-recovered purchased-gas costs | |
| | $ | 43,997 |
| | $ | — |
| | $ | 43,997 |
| Under-recovered purchased-gas costs | | 31,863 | | | — | | | 31,863 | |
| Pension and postemployment benefit costs | |
| | 31,530 |
| | 399,154 |
| | 430,684 |
| Pension and postemployment benefit costs | | 11,507 | | | 260,559 | | | 272,066 | |
| Weather normalization | | 19,618 |
| | — |
| | 19,618 |
| |
| Reacquired debt costs | |
| | 812 |
| | 7,500 |
| | 8,312 |
| Reacquired debt costs | | 812 | | | 4,070 | | | 4,882 | |
| MGP remediation costs | | MGP remediation costs | | 98 | | | 29,841 | | | 29,939 | |
| Ad-valorem tax | | Ad-valorem tax | | 8,561 | | | — | | | 8,561 | |
| WNA | | WNA | | 10,044 | | | — | | | 10,044 | |
| Customer credit deferrals | | Customer credit deferrals | | 10,685 | | | — | | | 10,685 | |
| Other | |
| | 3,591 |
| | 4,999 |
| | 8,590 |
| Other | | 2,052 | | | 2,369 | | | 4,421 | |
| Total regulatory assets, net of amortization | | 99,548 |
| | 411,653 |
| | 511,201 |
| Total regulatory assets, net of amortization | | 1,611,676 | | | 724,862 | | | 2,336,538 | |
| Income tax rate changes | | Income tax rate changes | | — | | | (552,928) | | | (552,928) | |
| Over-recovered purchased-gas costs | |
| | (10,471 | ) | | — |
| | (10,471 | ) | Over-recovered purchased-gas costs | | (8,090) | | | — | | | (8,090) | |
| Ad valorem tax | | (356 | ) | | — |
| | (356 | ) | |
| Total regulatory liabilities (a) | | (10,827 | ) | | — |
| | (10,827 | ) | |
| Net regulatory assets (liabilities) | | $ | 88,721 |
| | $ | 411,653 |
| | $ | 500,374 |
| |
| Total regulatory liabilities | | Total regulatory liabilities | | (8,090) | | | (552,928) | | | (561,018) | |
| Net regulatory assets and liabilities | | Net regulatory assets and liabilities | | $ | 1,603,586 | | | $ | 171,934 | | | $ | 1,775,520 | |
(a) Included in other current liabilities in our Balance Sheets.
|
| | | | | | | | | | | | | | |
| | | | | December 31, 2016 |
| | | | | Current | | Noncurrent | | Total |
| | | | | (Thousands of dollars) |
| Under-recovered purchased-gas costs | |
| | $ | 29,901 |
| | $ | — |
| | $ | 29,901 |
|
| Pension and postemployment benefit costs | |
| | 31,498 |
| | 427,448 |
| | 458,946 |
|
| Weather normalization | | | | 17,661 |
| | — |
| | 17,661 |
|
| Reacquired debt costs | |
| | 812 |
| | 8,108 |
| | 8,920 |
|
| Other | |
| | 3,274 |
| | 4,966 |
| | 8,240 |
|
| Total regulatory assets, net of amortization | | | | 83,146 |
| | 440,522 |
| | 523,668 |
|
| Over-recovered purchased-gas costs | |
| | (10,154 | ) | | — |
| | (10,154 | ) |
| Ad valorem tax | | | | (1,768 | ) | | — |
| | (1,768 | ) |
| Total regulatory liabilities (a) | | | | (11,922 | ) | | — |
| | (11,922 | ) |
| Net regulatory assets (liabilities) | | | | $ | 71,224 |
| | $ | 440,522 |
| | $ | 511,746 |
|
(a) Included in other current liabilities in our Balance Sheets.
Regulatory assets onin our Balance Sheets,consolidated balance sheets, as authorized by various regulatory authorities, are probable of recovery. Base rates and certain riders are designed to provide a recovery of costs during the period such rates are in effect, but do not generally provide for a return on investment for amounts we have deferred as regulatory assets. All of our regulatory assets are subject to review by the respective regulatory authorities during future regulatory proceedings. We are not aware of any evidence that these costs will not be recoverable through either riders, or base rates, or securitization.
Winter weather event costs - 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 believeexperienced unforeseeable and unprecedented market pricing for natural gas in our Kansas, Oklahoma, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month of February 2021 of approximately $2.1 billion.
Oklahoma - Beginning in the first quarter 2021, Oklahoma Natural Gas began deferring to a regulatory asset the extraordinary costs associated with this unprecedented winter weather event, including commodity costs, operational costs and carrying costs in accordance with an order issued by the OCC in March 2021.
In April 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to newly enacted securitization legislation in Oklahoma. On January 25, 2022, the OCC approved the financing order that reflected the terms of a settlement agreement reached in November 2021, which includes an agreement that all extreme gas purchase and extraordinary costs incurred as a result of Winter Storm Uri were reasonable and prudent and a financing order should be issued to recover these costs through securitization over a 25-year period. Following the issuance of the financing order, no parties to our application appealed the financing order to the Oklahoma Supreme Court during the 30-day appeal period. The securitization legislation allows the ODFA 24 months to complete the process to issue the securitized bonds; however, the financing order requests the ODFA to issue bonds and provide the net proceeds to Oklahoma Natural Gas as soon as feasible, but no later than December 31, 2022. Pursuant to the securitization statute in Oklahoma, the Oklahoma Supreme Court must validate that the bond issuance proposed by the ODFA complies with the securitization statute and the laws of Oklahoma. The ODFA received a hearing before the Oklahoma Supreme Court on April 13, 2022, seeking validation of the bond issuance. On May 24, 2022, validation was received from the Oklahoma Supreme Court. On July 15, 2022, the ODFA began the marketing process for the bonds. Bonds are expected to be issued and proceeds received in the third quarter of 2022. At June 30, 2022, Oklahoma Natural Gas has deferred approximately $1.3 billion in extraordinary costs attributable to Winter Storm Uri.
Kansas - In March 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific dockets to accept each utility’s filing of financial impact compliance reports and permit the KCC staff to conduct a review of the utility’s compliance report and its actions during Winter Storm Uri. In April 2021, a bill permitting the 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. The bill gives the KCC the authority to oversee and authorize the issuance of ratepayer-backed securitized bonds issued by a public utility.
In May 2021, Kansas Gas Service filed a motion in its company-specific docket opened by the KCC, requesting a limited waiver of the penalty provisions of its tariff to eliminate the multipliers in the penalty calculation when calculating the penalties to assess on marketers and individually-balanced transportation customers for their unauthorized natural gas usage during Winter Storm Uri. In October 2021, a nonunanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. Prior to a hearing on the amended settlement in January 2022, all parties reached a unanimous settlement, which was filed with a motion requesting approval of the unanimous settlement. Under the terms of the unanimous settlement, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. On March 3, 2022, the KCC issued an order approving the settlement which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties will reduce the regulatory asset for the winter weather event, up to $52.6 million. Through June 30, 2022, we have collected $48.3 million of these penalties.
In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from its customers over a period of either 5, 7, or 10 years. The KCC issued an order approving a unanimous settlement agreement on February 8, 2022, that allows Kansas Gas Service to recover extraordinary costs as of October 31, 2021, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs calculated at two percent, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds.
On March 31, 2022, Kansas Gas Service submitted its application for a financing order to the KCC as contemplated by the unanimous settlement agreement, requesting approval to issue securitized bonds to recover extraordinary costs resulting from Winter Storm Uri and flexibility to recover the costs over 5, 7, 10 or 12 years. On July 14, 2022, Kansas Gas Service, the KCC Staff and the Citizens’ Utility Ratepayer Board reached a settlement agreement for the issuance of a financing order allowing the Company to issue securitized utility tariff bonds in the amount of approximately $328.0 million plus issuance fees. The final amount to be securitized will be ableprovided in the final Issuance Advice Letter. The agreement provides for the issuance of bonds with a scheduled final maturity of between 7 and 10 years with flexibility within that range, if necessary, to recover suchachieve a AAA rating. The KCC has until September 27, 2022, to issue a financing order if it deems the issuance of the securitized bonds to be appropriate. If the KCC approves the financing order, we can begin the process to issue the securitized bonds. At June 30, 2022, Kansas Gas Service has deferred approximately $337.7 million in extraordinary costs, consistentnet of penalties billed, attributable to Winter Storm Uri. The amount deferred at June 30, 2022, in excess of the amount to be securitized, primarily includes accrued costs for natural gas purchases that have not been paid as we work with our historical recoveries.suppliers to resolve discrepancies in invoiced amounts. These amounts will be recovered through our purchased gas cost mechanisms or other regulatory filings and may be adjusted as the differences are resolved.
Texas - Pursuant to securitization legislation enacted in Texas as a result of Winter Storm Uri and a June 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC on July 30, 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.
| |
3. | CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE |
In October 2017,November 2021, the RRC approved a unanimous settlement agreement between Texas Gas Service, the other natural gas utilities in Texas participating in the securitization process, the staff of the RRC and all intervenors. The settlement agreement provides that all costs incurred by Texas Gas Service to purchase natural gas during Winter Storm Uri were reasonable, necessary and prudently incurred.
On February 8, 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The TPFA formed the Texas Natural Gas Securitization Finance Corporation, a new independent public authority, for purposes of issuing the securitized bonds and has begun the process to issue the securitized bonds, which are expected to be issued in the fourth quarter of 2022. At June 30, 2022, Texas Gas Service has deferred approximately $246.7 million in extraordinary costs associated with Winter Storm Uri, which includes $48.5 million attributable to the West Texas service area. Pursuant to the approved settlement order, in January 2022, Texas Gas Service began collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the West Texas service area from those customers.
In accordance with these regulatory orders associated with the winter weather event, we have deferred approximately $1.9 billion in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs.
The amounts deferred at June 30, 2022, include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. In addition, as a result of Winter Storm Uri, we were assessed penalties as a result of over- or under-deliveries of natural gas during periods that operational flow orders were imposed on us. Additionally, Kansas Gas Service assessed penalties under the modified penalty provisions of its tariff on marketers and individually-balanced transportation customers, or their agents, as approved by the KCC in March 2022. Amounts recorded reflect management’s best estimate of the amounts we may pay or receive and may be adjusted in future periods as the disposition of disputed invoices and the collectability of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments to the amounts we have deferred are not expected to have a material impact on earnings.
Other regulatory assets and liabilities - Purchased-gas costs represent the natural gas costs that have been over- or under- recovered from customers through the purchased-gas cost adjustment mechanisms, and includes natural gas utilized in our operations and premiums paid and any cash settlements received from our purchased natural gas call options.
The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension costs and other postemployment benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. The costs recovered through rates are based on the net periodic benefit cost for defined benefit pension and other postemployment costs. Differences, if any, between the net periodic benefit cost, net of deferrals, and the amount recovered through rates are reflected in earnings. We historically have recovered defined benefit pension and other postemployment benefit costs through rates. We believe it is probable that regulators will continue to include the net periodic pension and other postemployment benefit costs in our cost of service.
We amortize reacquired debt costs in accordance with the accounting guidelines prescribed by the OCC and KCC.
Weather normalization represents revenue over- or under- recovered through the WNA rider in Kansas. This amount is deferred as a regulatory asset or liability for a 12-month period. Kansas Gas Service then applies an adjustment to the customers’ bills for 12 months to refund the over-collected revenue or bill the under-collected revenue.
Ad-valorem tax represents the difference in Kansas Gas Service’s taxes incurred each year above or below the amount approved in base rates. This difference is deferred as a regulatory asset or liability for a 12-month period. Kansas Gas Service then applies an adjustment to the customers’ bills to refund the over-collected revenue or bill the under-collected revenue over the subsequent 12 months.
The customer credit deferrals and the noncurrent regulatory liability for income tax rate changes represents deferral of the effects of enacted federal and state income tax rate changes on our ADIT and the effects of these changes on our rates. See Note 10 for additional information regarding the impact of income tax rate changes.
See Note 12 for additional information regarding our regulatory assets for MGP remediation costs.
We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At June 30, 2022, no regulatory assets have been recorded. In Oklahoma, the test period for our recently completed rate case included the impacts of COVID-19 on our cost of service in determining new rates that became effective in November 2021. In addition, annual PBRC filings, including the PBRC filing made in March 2022, allow us to include any impacts from COVID-19 in our test period cost of service to determine the impact on our rates. In Kansas and Texas, we continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.
Recovery through rates resulted in amortization of regulatory assets of approximately $1.6 million and $1.0 million for the three months ended June 30, 2022 and 2021, respectively, and approximately $6.0 million and $3.9 million for the six months ended June 30, 2022 and 2021, respectively.
4.CREDIT FACILITY AND SHORT-TERM DEBT
On March 16, 2022, we entered into the first amendment to the second amended and restated our credit agreement. ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the maturity date of the ONE Gas
Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changes the benchmark rate defined in the ONE Gas Credit Agreement to SOFR as administered by the Federal Reserve Bank of New York. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.
The ONE Gas Credit Agreement remainsprovides for a $700.0 million$1.0 billion revolving unsecured credit facility and includes a $20.0$20 million letter of credit subfacility and a $60.0$60 million swingline subfacility. We will also be able tocan request an increase in commitments of up to an additional $500.0
$500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2022, 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 contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At SeptemberJune 30, 2017,2022, our total debt-to-capital ratio was 4163 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.
We have aAt June 30, 2022, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit, which is available to repay any of our commercial paper borrowings.
In June 2021, we increased the size of our commercial paper program under which we may issue unsecuredto permit the issuance of commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs.needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time. The maturities of the commercial paper notes may vary but may not exceed 270 days from the date of issue. The commercialCommercial paper notes areis generally sold at par less a discount representing an interest factor.
The ONE Gas Credit Agreement is available to repay the At June 30, 2022, we had $490.1 million of commercial paper notes, if necessary. Amounts outstanding underoutstanding.
In connection with the commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement. At September 30, 2017, we had $174.0 million in short-term borrowings, $1.8 million in letterssecond amendment and restatement of credit issued under 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 $524.2 million of remaining credit availableall obligations under the ONE Gas 364-day Credit Agreement.Agreement were paid in full and discharged.
We have senior notes consisting5.LONG-TERM DEBT
Senior Notes - In March 2021, we issued $1.0 billion of $300 million of 2.070.85 percent senior notes due in 2019, $300March 2023, $700 million of 3.611.10 percent senior notes due inMarch 2024, and $600$800 million of 4.658 percentfloating-rate senior notes due March 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year, reset quarterly for the applicable interest period (2.35 percent at June 30, 2022).
In the event LIBOR is not available, and such circumstances are unlikely to be temporary, we or our designee may establish an alternative interest rate for our floating-rate senior notes due March 2023 by replacing LIBOR with one or more secured financing-based rates or another alternate benchmark rate. The net proceeds from the issuance were used for payment of gas purchases and related costs resulting from Winter Storm Uri and general corporate purposes.
In September 2021, we called $400 million of the floating-rate senior notes due March 2023 at par, using a combination of cash on hand and commercial paper. We did not have the right to call these senior notes prior to September 11, 2021. We expect to use the proceeds from the issuance of securitized bonds in 2044. each state, as discussed in Note 3, to call the outstanding senior notes due March 2023 and a portion of the senior notes due March 2024.
The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.
ONE Gas 2021 Term Loan Facility - In February 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.
6.EQUITY
At-the-Market Equity Program - In February 2020, we initiated an at-the-market equity program by entering into an equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $250 million (including any shares of common stock that may be sold pursuant to the firstmaster forward sale confirmation entered into in connection with the equity distribution agreement and the related supplemental confirmations). Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. For the six months of 2017,ended June 30, 2022 and 2021, respectively, we repurchased approximately 256 thousandissued and sold 403,792 shares and 198,438 shares of our common stock for approximately $17.5$35.0 million and $15.3 million, generating proceeds, net of issuance costs, of $34.7 million and $15.1 million. We did not repurchase any
For the six months ended June 30, 2022, we executed forward sale agreements for 591,736 shares of our common stock, duringwhich must be settled on or before January 2, 2024. No shares of common stock have been settled under the three months ended Septemberforward sale agreements. Had we settled all shares under the forward agreements as of June 30, 2017.2022, we would have generated net proceeds of $48.3 million, or $81.54 per share.
At June 30, 2022, we had $131.3 million of equity available for issuance under the program.
Dividends Declared - In October 2017,July 2022, we declared a dividend of $0.42$0.62 per share ($1.682.48 per share on an annualized basis) for shareholders of record as of November 13, 2017,August 15, 2022, payable Decemberon September 1, 2017.2022.
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6. | ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) |
7.ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the effect of reclassifications from accumulated other comprehensive
income (loss)loss in our
Statementsconsolidated statements of
Incomeincome for the periods indicated:
| | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | Affected Line Item in the |
| | | Three Months Ended | | Nine Months Ended | | |
| Details about Accumulated Other Comprehensive | | September 30, | | September 30, | | Affected Line Item in the | |
| Income (Loss) Components | | 2017 | 2016 | | 2017 | 2016 | | Statements of Income | |
| Details About Accumulated Other | | Details About Accumulated Other | | June 30, | | June 30, | | Consolidated Statements |
| Comprehensive Loss Components | | Comprehensive Loss Components | | 2022 | 2021 | | 2022 | 2021 | | of Income |
| | | (Thousands of dollars) | | | (Thousands of dollars) | |
| Pension and other postemployment benefit plan obligations (a) | | | | | | Pension and other postemployment benefit plan obligations (a) | |
| Amortization of net loss | | $ | 10,648 |
| $ | 10,040 |
| | $ | 31,944 |
| $ | 30,113 |
| | Amortization of net loss | | $ | 4,252 | | $ | 11,474 | | | $ | 12,453 | | $ | 22,948 | | |
| Amortization of unrecognized prior service cost | | (1,149 | ) | (909 | ) | | (3,447 | ) | (2,725 | ) | | |
| Amortization of unrecognized prior service cost (credit) | | Amortization of unrecognized prior service cost (credit) | | 72 | | (70) | | | 82 | | (140) | | |
| | | 9,499 |
| 9,131 |
| | 28,497 |
| 27,388 |
| | | 4,324 | | 11,404 | | | 12,535 | | 22,808 | | |
| Regulatory adjustments (b) | | (9,290 | ) | (8,943 | ) | | (27,869 | ) | (26,824 | ) | | Regulatory adjustments (b) | | (4,265) | | (11,014) | | | (12,388) | | (22,027) | | |
| | | 209 |
| 188 |
| | 628 |
| 564 |
| | Income before income taxes | | 59 | | 390 | | | 147 | | 781 | | | Income before income taxes |
| | | (81 | ) | (72 | ) | | (242 | ) | (217 | ) | | Income tax expense | | (15) | | (91) | | | (34) | | (182) | | | Income tax expense |
| Total reclassifications for the period | | $ | 128 |
| $ | 116 |
| | $ | 386 |
| $ | 347 |
| | Net income | Total reclassifications for the period | | $ | 44 | | $ | 299 | | | $ | 113 | | $ | 599 | | | Net income |
(a) These components of accumulated other comprehensive income (loss)loss are included in the computation of net periodic benefit cost. See Note 89 for additional detail of our net periodic benefit cost.cost.
(b) Regulatory adjustments represent pension and other postemployment benefit costs expected to be recovered through rates and are deferred as part of our regulatory assets. See Note 23 for additional disclosures of regulatory assets and liabilities.
8.EARNINGS PER SHARE
Basic EPS is based oncalculated by dividing net income and is calculated based uponby the daily weighted-average number of common shares outstanding during the periods presented. Also, this calculationpresented, which includes fully vested stock awards that have not yet been issued as common stock. Diluted EPS includesis based on shares outstanding for the calculation of basic EPS, plus unvested stock awards granted under our compensation plans, but only to the extent these instruments dilute earnings per share.
The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:
| | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2022 |
| | Income | | Shares | | Per Share
Amount |
| | (Thousands, except per share amounts) |
| Basic EPS Calculation | | | | | |
| Net income available for common stock | $ | 32,075 | | | 54,262 | | | $ | 0.59 | |
| Diluted EPS Calculation | | | | | |
| Effect of dilutive securities | — | | | 73 | | | |
| Net income available for common stock and common stock equivalents | $ | 32,075 | | | 54,335 | | | $ | 0.59 | |
| | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2021 |
| | Income | | Shares | | Per Share
Amount |
| | (Thousands, except per share amounts) |
| Basic EPS Calculation | | | | | |
| Net income available for common stock | $ | 30,093 | | | 53,466 | | | $ | 0.56 | |
| Diluted EPS Calculation | | | | | |
| Effect of dilutive securities | — | | | 82 | | | |
| Net income available for common stock and common stock equivalents | $ | 30,093 | | | 53,548 | | | $ | 0.56 | |
| | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2022 |
| | Income | | Shares | | Per Share
Amount |
| | (Thousands, except per share amounts) |
| Basic EPS Calculation | | | | | |
| Net income available for common stock | $ | 131,009 | | | 54,092 | | | $ | 2.42 | |
| Diluted EPS Calculation | | | | | |
| Effect of dilutive securities | — | | | 91 | | | |
| Net income available for common stock and common stock equivalents | $ | 131,009 | | | 54,183 | | | $ | 2.42 | |
| | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2021 |
| | Income | | Shares | | Per Share
Amount |
| | (Thousands, except per share amounts) |
| Basic EPS Calculation | | | | | |
| Net income available for common stock | $ | 125,668 | | | 53,419 | | | $ | 2.35 | |
| Diluted EPS Calculation | | | | | |
| Effect of dilutive securities | — | | | 112 | | | |
| Net income available for common stock and common stock equivalents | $ | 125,668 | | | 53,531 | | | $ | 2.35 | |
|
| | | | | | | | | | |
| | Three Months Ended September 30, 2017 |
| | Income | | Shares | | Per Share Amount |
| | (Thousands, except per share amounts) |
| Basic EPS Calculation | | | | | |
| Net income available for common stock | $ | 18,797 |
| | 52,488 |
| | $ | 0.36 |
|
| Diluted EPS Calculation | |
| | |
| | |
|
| Effect of dilutive securities | — |
| | 438 |
| | |
|
| Net income available for common stock and common stock equivalents | $ | 18,797 |
| | 52,926 |
| | $ | 0.36 |
|
|
| | | | | | | | | | |
| | Three Months Ended September 30, 2016 |
| | Income | | Shares | | Per Share Amount |
| | (Thousands, except per share amounts) |
| Basic EPS Calculation | | | | | |
| Net income available for common stock | $ | 12,737 |
| | 52,453 |
| | $ | 0.24 |
|
| Diluted EPS Calculation | | | |
| | |
|
| Effect of dilutive securities | — |
| | 489 |
| | |
|
| Net income available for common stock and common stock equivalents | $ | 12,737 |
| | 52,942 |
| | $ | 0.24 |
|
|
| | | | | | | | | | |
| | Nine Months Ended September 30, 2017 |
| | Income | | Shares | | Per Share Amount |
| | (Thousands, except per share amounts) |
| Basic EPS Calculation | | | | | |
| Net income available for common stock | $ | 115,876 |
| | 52,539 |
| | $ | 2.21 |
|
| Diluted EPS Calculation | |
| | |
| | |
|
| Effect of dilutive securities | — |
| | 445 |
| | |
|
| Net income available for common stock and common stock equivalents | $ | 115,876 |
| | 52,984 |
| | $ | 2.19 |
|
|
| | | | | | | | | | |
| | Nine Months Ended September 30, 2016 |
| | Income | | Shares | | Per Share Amount |
| | (Thousands, except per share amounts) |
| Basic EPS Calculation | | | | | |
| Net income available for common stock | $ | 97,781 |
| | 52,452 |
| | $ | 1.86 |
|
| Diluted EPS Calculation | | | |
| | |
|
| Effect of dilutive securities | — |
| | 510 |
| | |
|
| Net income available for common stock and common stock equivalents | $ | 97,781 |
| | 52,962 |
| | $ | 1.85 |
|
In September 2017, we purchased group annuity contracts and transferred approximately $47 million of the assets and liabilities related to certain participants in our defined benefit pension plan to a third-party insurance company.
The following tables set forth the components of net periodic benefit cost for our pension and other postemployment benefit plans for the periods indicated:
| | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | | |
| Three Months Ended | | Six Months Ended | | |
| June 30, | | June 30, | | |
| 2022 | 2021 | | 2022 | 2021 | | | |
| (Thousands of dollars) | | | |
| Components of net periodic benefit cost | | | | | | | | |
| Service cost | $ | 2,592 | | $ | 3,453 | | | $ | 5,686 | | $ | 6,906 | | | | |
| Interest cost | 9,037 | | 7,365 | | | 16,841 | | 14,730 | | | | |
| Expected return on assets | (14,632) | | (15,596) | | | (29,245) | | (31,192) | | | | |
| Amortization of unrecognized prior service cost | 62 | | — | | | 62 | | — | | | | |
| Amortization of net loss | 4,198 | | 11,381 | | | 12,345 | | 22,762 | | | | |
| Net periodic benefit cost | $ | 1,257 | | $ | 6,603 | | | $ | 5,689 | | $ | 13,206 | | | | |
| | | | | | | | | | | | Other Postemployment Benefits | |
| | Pension Benefits | | Three Months Ended | | Six Months Ended | |
| | Three Months Ended | | Nine Months Ended | | June 30, | | June 30, | |
| | September 30, | | September 30, | | 2022 | 2021 | | 2022 | 2021 | |
| | 2017 | 2016 | | 2017 | 2016 | | (Thousands of dollars) | |
| | (Thousands of dollars) | |
| Components of net periodic benefit cost | | | | | | |
| Components of net periodic benefit cost (credit) | | Components of net periodic benefit cost (credit) | | | |
| Service cost | $ | 3,044 |
| $ | 3,014 |
| | $ | 9,132 |
| $ | 9,042 |
| Service cost | $ | 318 | | $ | 397 | | | $ | 636 | | $ | 794 | | |
| Interest cost | 10,113 |
| 11,387 |
| | 30,339 |
| 34,162 |
| Interest cost | 1,612 | | 1,563 | | | 3,224 | | 3,126 | | |
| Expected return on assets | (14,624 | ) | (15,296 | ) | | (43,872 | ) | (45,888 | ) | Expected return on assets | (3,295) | | (4,202) | | | (6,590) | | (8,404) | | |
| Amortization of unrecognized prior service cost (credit) | | Amortization of unrecognized prior service cost (credit) | 10 | | (70) | | | 20 | | (140) | | |
| Amortization of net loss | 9,027 |
| 8,886 |
| | 27,081 |
| 26,657 |
| Amortization of net loss | 54 | | 93 | | | 108 | | 186 | | |
| Net periodic benefit cost | $ | 7,560 |
| $ | 7,991 |
| | $ | 22,680 |
| $ | 23,973 |
| |
| Net periodic benefit cost (credit) | | Net periodic benefit cost (credit) | $ | (1,301) | | $ | (2,219) | | | $ | (2,602) | | $ | (4,438) | | |
|
| | | | | | | | | | | | | |
| | Other Postemployment Benefits |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | 2016 | | 2017 | 2016 |
| | (Thousands of dollars) |
| Components of net periodic benefit cost | | | | | |
| Service cost | $ | 627 |
| $ | 637 |
| | $ | 1,881 |
| $ | 1,913 |
|
| Interest cost | 2,472 |
| 2,626 |
| | 7,416 |
| 7,880 |
|
| Expected return on assets | (3,147 | ) | (3,070 | ) | | (9,441 | ) | (9,212 | ) |
| Amortization of unrecognized prior service cost | (1,149 | ) | (909 | ) | | (3,447 | ) | (2,725 | ) |
| Amortization of net loss | 1,621 |
| 1,154 |
| | 4,863 |
| 3,456 |
|
| Net periodic benefit cost | $ | 424 |
| $ | 438 |
| | $ | 1,272 |
| $ | 1,312 |
|
We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain regulatory authorities require that the recovery of these costs be based on specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the applicable regulatory authorities. RegulatoryFor the six months ended June 30, 2022, regulatory deferrals related to net periodic benefit cost were $1.7 million. For the six months ended June 30, 2021, regulatory deferrals related to net periodic benefit cost were not materialmaterial.
We use a December 31 measurement date for our plans. On April 30, 2022, we amended our defined benefit pension plans to change the variable cost of living adjustment for eligible participants, to a fixed rate. Therefore, our pension plans were remeasured as of April 30, 2022, resulting in an adjustment of approximately $7.2 million to our pension expense, net of capitalization and regulatory deferrals, for the year ending December 31, 2022, beginning May 1, 2022.
We continue to capitalize all eligible service cost and non-service cost components under the accounting requirements of ASC Topic 980 (Regulated Operations) for rate-regulated entities. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset in the amount of $5.2 million and $6.1 million as of June 30, 2022 and December 31, 2021, respectively. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.
10.INCOME TAXES
We use an estimated annual effective tax rate for purposes of determining the income tax provision during interim reporting periods. In calculating our estimated annual effective tax rate, we consider forecasted annual pre-tax income and estimated permanent book versus tax differences, as well as tax credits. Adjustments to the effective tax rate and estimates will occur as information and assumptions change.
As of June 30, 2022, we have no uncertain tax positions. Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date. We are no longer subject to income tax examination for years prior to 2018.
In May 2021, a bill amending the Oklahoma state income tax code was signed into law that reduced the state income tax rate to four percent from six percent beginning January 1, 2022. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $29.3 million was recorded as a regulatory liability. The impact of the change in the state income tax rate on Oklahoma Natural Gas’ rates, as well as the timing and amount of the impact on the annual crediting mechanism for the EDIT regulatory liability, is included in the March 15, 2022 PBRC filing, which is pending approval by the OCC.
Income tax expense reflects credits for the amortization of the regulatory liability associated with EDIT that was returned to customers of $3.0 million and $2.6 million for the three and nine months ended SeptemberJune 30, 2017.2022 and 2021, respectively, and credits of $10.9 million and $10.7 million for the six months ended June 30, 2022 and 2021, respectively.
| |
9. | COMMITMENTS AND CONTINGENCIES |
11. OTHER INCOME AND OTHER EXPENSE
The following table sets forth the components of other income and other expense for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (Thousands of dollars) |
| Net periodic benefit cost other than service cost (credit) | | $ | 1,366 | | | $ | (1,005) | | | $ | 778 | | | $ | (1,775) | |
| Earnings (losses) on investments associated with nonqualified employee benefit plans | | (4,619) | | | 1,883 | | | (7,452) | | | 2,499 | |
| | | | | | | | |
| Other, net | | (730) | | | (427) | | | (1,454) | | | (678) | |
| Total other income (expense), net | | $ | (3,983) | | | $ | 451 | | | $ | (8,128) | | | $ | 46 | |
12.COMMITMENTS AND CONTINGENCIES
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. See Note 3 for more information regarding the effects of COVID-19 on us.
Environmental Matters - We are subject to multiple historical, wildlife preservationlaws and environmental laws and/or regulations regarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air ActCAA and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and ninesix months ended SeptemberJune 30, 20172022 and 2016.2021.
We own or retain legal responsibility for thecertain 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.
We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites, and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. Regulatory closure has been achieved at three5 of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs. During 2016, we completed a site assessment at the twelfth site where no active soil remediation has occurred.
We have submitted a work plan to the KDHE for approval to address a source of contamination and associated contaminated soil on a portion of this site. We are also conducting a study of the feasibility of various options to address the remainder of the site. Costs associated with the remediation at this site are not expected to be material to our results of operations or financial position.
With regard to one of our former MGP sites, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. Additional testing and work plan development is underway in 2017 to determine a remediation work plan to present to the KDHE for approval, which could impact our estimates of the cost of remediation at this site. In the fourth quarter of 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded a reserve of $4.0 million for this site in the fourth quarter of 2016.
In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, its 12 MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC. If approved, the agreement will allowthat allows Kansas Gas Service to defer MGPand seek recovery of costs (costs that are necessary for investigation and remediation at, theand nearby, these 12 former MGP sites)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. At the timeFollowing 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, is expected to exceed $15.0 million, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC is expectedAt June 30, 2022, we have deferred $29.9 million for accrued investigation and remediation costs pursuant to issueour AAO. Kansas Gas Service expects to file an orderapplication as soon as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2023.
We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at 7 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 later than early January 2018. Ifactive soil remediation had previously occurred. A remediation plan concerning this site was submitted to the agreement is approved,KDHE in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan for an additional site that we expect to recordsubmit to the KDHE in 2023.
We also own or retain legal responsibility for certain environmental conditions at a regulatory assetformer MGP site in Texas. At the request of approximately $5.9 million forthe TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. On April 14, 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. At June 30, 2022, estimated costs that have been accrued at January 1, 2017.associated with expected remediation activities for this site are not material.
Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and ninesix months ended SeptemberJune 30, 20172022 and 2016. A number2021. The reserve for remediation of environmentalour MGP sites was $17.8 million and $22.8 million at June 30, 2022 and December 31, 2021, respectively. Environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.
We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and those costs may adversely affect our financial condition, results of operations and cash flows. 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,regulation under federal pipeline safety statutes and any analogous state regulations. These include safety requirements for the design, construction, operation, and maintenance of pipelines, including integrity-management regulations.transmission and distribution pipelines. At the federal level, we are regulated by PHMSA. PHMSA regulations require the following for certain pipelines: inspection and maintenance plans; integrity management programs, including the determination of pipeline companies operating high-pressure transmission pipelines to perform integrity risks and periodic assessments on certain pipeline segmentssegments; an operator qualification program, which includes certain trainings; a public awareness program that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, the Pipeline Safety, Regulatory Certaintyprovides certain information; and Job Creation Act was signed into law. The law increased maximum penalties for violating federala control room management plan.
As part of regulating 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 high-consequence areas;
a verification of records for pipelinesPHMSA promulgates various regulations. For example, in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.
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 includeincluded changes to pipeline integrity management requirements and other safety-related requirements. TheSubsequently, PHMSA announced they would split this NPRM comment period ended July 7, 2016,into three separate final rulemakings:
•the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and comments are under review by PHMSA. As partJob Creation Act and is called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;
•the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the comment review process,NPRM (except for gas gathering pipelines); and
•the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.
On October 1, 2019, PHMSA is being advised bypublished the Technical Pipeline Safety Standards Committee, informally known by first of the three final rules referenced above, which addressed the 2011 congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline, and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP within 15 years. The first final rule became effective July 1, 2020. Our estimated capital and operating expenditures associated with compliance with the first final rulemaking were not material.
PHMSA ashas not yet issued 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.second final rule. The potential capital and operating expenditures associated with compliance with the proposedthis rule are currently being evaluated and could be significant depending on the final regulations.regulation. We do not expect to be impacted by the third final rule, as we do not own gas gathering pipelines.
Separately, as part of the Consolidated Appropriations Act, 2021, the PIPES Act of 2020 reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. To the extent such rulemakings impose more stringent requirements on our facilities, we may be required to incur expenditures that may be material.
Legal Proceedings - 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 final outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.
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10. | DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS |
13.DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS
Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it, or if regulatory rulings requirerequirements impose a different accounting treatment.
If certain conditions are met, we may elect to designate a derivative instrument as a hedge to mitigate the risk of exposure to changes in fair values or cash flows. We have not elected to designate any of our derivative instruments as hedges.
The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
|
| | | | | | | | | | | | | |
| | Recognition and Measurement |
| Accounting Treatment | | Balance Sheet | | Income Statement |
Normal purchases and
normal sales
| - | Recorded at historical costFair value not recorded | - | Change in fair value not recognized in earnings |
| Mark-to-market | - | Recorded at fair value | - | Change in fair value recognized in, and recoverable through, the purchased-gas cost adjustment mechanisms |
We have not elected to designate any of our derivative instruments as hedges. Premiums paid and any cash settlements received associated with the commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost adjustment mechanisms.
Determining Fair Value Measurements - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.
Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our consolidated financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:
•Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;
•Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and
•Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data.
We recognize transfers into and out of the levels as of the end of each reporting period.
Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.
Derivative Instruments -At SeptemberJune 30, 2017,2022, we held purchased natural gas call options for the heating season ending March 31, 2018,2023, with total notional amounts of 33.511.0 Bcf, for which we paid premiums of $10.9$16.2 million, and which had ano fair value of $6.9 million.value. At December 31, 2016,2021, we held purchased natural gas call options for the heating season ended March 31, 2017,2022, with total notional amounts of 14.313.2 Bcf, for which we paid premiums of $5.4$9.5 million,, and which had a fair value of $6.5 million. The premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs in current regulatory assets as these$2.3 million. These contracts are included in, and recoverable through, theour purchased-gas cost adjustment mechanisms. Additionally, premiums paid, changes in fair value and any settlements received associated with these contracts are deferred as part of our unrecovered purchased-gas costs in our Balance Sheets.consolidated balance sheets. Our natural gas call options are classified as Level 1, as fair value amounts are based on unadjusted quoted prices in active markets including NYMEX-settled prices.settled prices on the New York Mercantile Exchange. There were no0 transfers between levels for the three and nine months ended September 30, 2017 and 2016.periods presented.
Other Financial Instruments -The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1. At June 30, 2022 and December 31, 2021, our other current and noncurrent assets included $6.9 million of corporate bonds and $3.5 million of United States treasury notes. The fair value of corporate bonds and United States treasury notes approximate carrying value, and are classified as Level 2 and Level 1, respectively.
Short-term notes payable and commercialCommercial paper areis due upon demand and, therefore, the carrying amounts approximate fair value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $1.2$3.7 billion at both SeptemberJune 30, 20172022 and December 31, 2016.2021. The estimated fair value of our long-term debt, including current maturities, was $1.3$3.5 billion and $1.2$3.9 billion at SeptemberJune 30, 20172022 and December 31, 2016,2021, respectively. The estimated fair value of our
Senior Notes at September 30, 2017 and December 31, 2016, long-term debt was determined using quoted market prices, and areis classified as Level 2.
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ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to theConsolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and ninesix months ended SeptemberJune 30, 2017,2022 are not necessarily indicative of the results that may be expected for a 12-month period.
RECENT DEVELOPMENTS
DividendWinter Storm Uri - In October 2017,February 2021, the U.S. experienced Winter Storm Uri, a historic winter weather event impacting supply, market pricing and demand for natural gas in a number of states, including our service territories of Oklahoma, Kansas, and Texas. During this time, the governors of Oklahoma, Kansas, and Texas each declared a state of emergency, and certain regulatory agencies issued emergency orders that impacted the utility and natural gas industries, including statewide utility curtailment programs and orders requiring jurisdictional natural gas and electric utilities to do all things possible and necessary to ensure that natural gas and electricity utility services continued to be provided to their customers. Due to the historic nature of this winter weather event, we experienced unforeseeable and unprecedented market pricing for gas costs in our Oklahoma, Kansas, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month of February 2021 of approximately $2.1 billion.
On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri.
In March 2021, we issued $1.0 billion of 0.85 percent senior notes due March 2023, $700 million of 1.10 percent senior notes due March 2024, and $800 million of floating-rate senior notes due March 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year, reset quarterly for the applicable interest period (2.35 percent at June 30, 2022). The net proceeds from the issuance were used for payment of gas purchases and related costs resulting from Winter Storm Uri and general corporate purposes. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.
On September 21, 2021, we called $400 million of the floating-rate senior notes due March 2023 at par, using a combination of cash on hand and commercial paper. We did not have the right to call these senior notes prior to September 11, 2021.
Our purchased gas costs are recoverable through the tariffs in each state where we operate. Due to the higher level of gas purchase costs during Winter Storm Uri, related financing costs and other operational response costs, we are working with regulators to extend the recovery periods of such costs in order to lessen the immediate customer impact. In that regard, the OCC, KCC and the RRC each authorized certain utilities, including LDCs, to record regulatory assets to account for the extraordinary costs associated with this winter weather event, including but not limited to gas purchase costs and other costs related to the procurement and transportation of gas supply, carrying costs and other operational costs. As of June 30, 2022, we have deferred approximately $1.9 billion in costs associated with Winter Storm Uri.
In the second quarter of 2021, legislation in Oklahoma, Kansas and Texas was approved that permits utilities to pursue securitization to finance extraordinary expenses, such as fuel costs, incurred during extreme weather events. We have received or are currently seeking approval from our regulators to utilize the securitization legislation in each state to repay or refinance the debt we incurred to finance the extraordinary costs associated with Winter Storm Uri.
See “Regulatory Activities,” “Liquidity and Capital Resources,” and Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the effects of Winter Storm Uri on us.
ONE Gas Credit Agreement - On March 16, 2022, we entered into the first amendment to the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the maturity date of the ONE Gas Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changes the benchmark rate defined in the ONE Gas Credit Agreement to SOFR as administered by the Federal Reserve Bank of New York. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.
In connection with the second amendment and restatement of the ONE Gas Credit Agreement on March 16, 2021, all commitments under our ONE Gas 364-day Credit Agreement, dated as of April 7, 2020, were terminated and all obligations under the ONE Gas 364-day Credit Agreement were paid in full and discharged.
ONE Gas Commercial Paper Program - On June 22, 2021, we increased the size of our commercial paper program to permit the issuance of commercial paper to fund short-term borrowing needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time.
COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and communities.
We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At June 30, 2022, no regulatory assets have been recorded. In Oklahoma, the test period for our recently completed rate case included the impacts of COVID-19 on our cost of service in determining new rates that became effective in November 2021. In addition, annual PBRC filings, including the PBRC filing made in March 2022, allow us to include any impacts from COVID-19 in our test period cost of service to determine the impact on our rates. In Kansas and Texas, we continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.
See Notes 3 and 12 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion regarding the effects of COVID-19 on us.
Dividend - In July 2022, we declared a dividend of $0.42$0.62 per share ($1.682.48 per share on an annualized basis) for shareholders of record as of November 13, 2017,August 15, 2022, payable Decemberon September 1, 2017.2022.
REGULATORY ACTIVITIES
Oklahoma - In March 2017,April 2021, Oklahoma Natural Gas filed its first annual PBRC followingsubmitted an initial application requesting a financing order pursuant to newly enacted securitization legislation in Oklahoma. On January 25, 2022, the general rate caseOCC approved the financing order that was approvedreflected the terms of a settlement agreement reached in January 2016. This filing was based onNovember 2021, which includes an agreement that all extreme gas purchase and extraordinary costs incurred as a calendar test yearresult of 2016.Winter Storm Uri were reasonable and prudent and a financing order should be issued to recover these costs through securitization over a 25-year period. Following the issuance of the financing order, no parties to our application appealed the financing order to the Oklahoma Supreme Court during the 30-day appeal period. The PBRC filing demonstrated thatsecuritization legislation allows the ODFA 24 months to complete the process to issue the securitized bonds; however, the financing order requests the ODFA to issue bonds and provide the net proceeds to Oklahoma Natural Gas as soon as feasible, but no later than December 31, 2022. Pursuant to the securitization statute in Oklahoma, the Oklahoma Supreme Court must validate that the bond issuance proposed by the ODFA complies with the securitization statute and the laws of Oklahoma. The ODFA received a hearing before the Oklahoma Supreme Court on April 13, 2022, seeking validation of the bond issuance. On May 24, 2022, validation was earning withinreceived from the allowed return on equity rangeOklahoma Supreme Court. On July 15, 2022, the ODFA began the marketing process for the bonds. Bonds are expected to be issued and proceeds received in the third quarter of 9.0 to 10.0 percent. Therefore,2022. At June 30, 2022, Oklahoma Natural Gas did not seek a modificationhas deferred approximately $1.3 billion in extraordinary costs attributable to base rates. The filing also requested an energy efficiency program true-up and utility incentive adjustment of approximately $1.9 million. A joint stipulation and settlement agreement was approved by the OCC in August 2017. Winter Storm Uri.
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, 2027. On March 15, 2022, Oklahoma Natural Gas filed its required PBRC application for a calendar year 2021 basedtest year. The filed request includes a $19.7 million base rate revenue increase, $2.3 million energy efficiency incentive, and $9.1 million of estimated EDIT to be credited to customers in 2023. On May 27, 2022, the Public Utility Division (“PUD”) of the OCC filed responsive testimony supporting an increase of $19.6 million. On May 31, 2022, the Office of the Attorney General filed a statement of position supporting PUD’s position. Pursuant to its tariff, Oklahoma Natural Gas placed new rates into effect on July 13, 2022, reflecting a base rate revenue increase of $19.6 million. These rates are subject to refund until approved by the OCC. We expect a hearing to be scheduled in September 2022.
As required by OCC rule, on April 6, 2022, Oklahoma Natural Gas filed a request for approval of a demand portfolio of conservation and energy efficiency programs for calendar years 2023-2025. The request includes an annual portfolio of program costs of $17.4 million with an estimated annual utility incentive of $2.6 million.
In May 2021, Oklahoma Natural Gas filed a general rate case. In October 2021, a joint stipulation and settlement agreement was signed by all parties to the rate case. In November 2021, the OCC issued an order approving the joint stipulation and settlement agreement. Upon approval of the order, Oklahoma Natural Gas’ base rates increased by $15.3 million. Premised on a calendar test yearreturn on equity of 2020.9.4 percent and a common equity ratio of 58.55 percent, the order also includes the continuation of the PBRC tariff that was established in 2009. The approved order also states that Oklahoma Natural Gas may recover commodity costs of no more than $5.0 million annually for the purchase of RNG and that Oklahoma Natural Gas shall file an application on or before December 31, 2022, requesting approval of an RNG pilot program including an “opt-in” tariff allowing Oklahoma Natural Gas to allocate costs and benefits of RNG to those customers who choose RNG for their fuel source.
In May 2021, a bill amending the Oklahoma state income tax code was signed into law that reduced the state income tax rate to four percent from six percent beginning January 1, 2022. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $29.3 million was recorded as a regulatory liability. The impact of the change in the state income tax rate on Oklahoma Natural Gas’ rates, as well as the timing and amount of the impact on the annual crediting mechanism for the EDIT regulatory liability, is included in the March 15, 2022 PBRC filing, which is pending approval by the OCC.
Kansas - In March 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific dockets to accept each utility’s filing of financial impact compliance reports and permit the KCC staff to conduct a review of the utility’s compliance report and its actions during Winter Storm Uri.
In May 2021, Kansas Gas Service filed a motion in its company-specific docket opened by the KCC, requesting a limited waiver of the penalty provisions of its tariff to eliminate the multipliers in the penalty calculation when calculating the penalties to assess on marketers and individually-balanced transportation customers for their unauthorized natural gas usage during Winter Storm Uri. In October 2021, a nonunanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. Prior to a hearing on the amended settlement in January 2022, all parties reached a unanimous settlement, which was filed with a motion requesting approval of the unanimous settlement. Under the terms of the unanimous settlement, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. On March 3, 2022, the KCC issued an order approving the settlement, which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties will reduce the regulatory asset for the winter weather event, up to $52.6 million. Through June 30, 2022, we collected $48.3 million of these penalties.
In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from its customers over a period of either 5, 7, or 10 years. The KCC issued an order approving a unanimous settlement agreement on February 8, 2022, that allows Kansas Gas Service to recover extraordinary costs as of October 31, 2021, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs calculated at two percent, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds.
On March 31, 2022, Kansas Gas Service submitted its application for a financing order to the KCC as contemplated by the unanimous settlement agreement, requesting approval to issue securitized bonds to recover extraordinary costs resulting from Winter Storm Uri and flexibility to recover the costs over 5, 7, 10 or 12 years. On July 14, 2022, Kansas Gas Service, the KCC Staff and the Citizens’ Utility Ratepayer Board reached a settlement agreement for the issuance of a financing order allowing the Company to issue securitized utility tariff bonds in the amount of approximately $328.0 million plus issuance fees. The final amount to be securitized will be provided in the final Issuance Advice Letter. The agreement provides for the issuance of bonds with a scheduled final maturity of between 7 and 10 years with flexibility within that range, if necessary, to achieve a AAA rating. The KCC has until September 27, 2022, to issue a financing order if it deems the issuance of the securitized bonds to be appropriate. If the KCC approves the financing order, we can begin the process to issue the securitized bonds. At June 30, 2022, Kansas Gas Service has deferred approximately $337.7 million in extraordinary costs, net of penalties billed, attributable to Winter Storm Uri. The amount deferred at June 30, 2022, in excess of the amount to be securitized, primarily includes accrued costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. These amounts will be recovered through our purchased gas cost mechanisms or other regulatory filings and may be adjusted as the differences are resolved.
In August 2017,2021, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.9$7.6 million related to its GSRS. AnThe KCC issued an order fromin November 2021, and the new surcharge became effective on December 1, 2021.
In May 2020, a bill amending the Kansas state income tax code was signed into law that exempts public utilities regulated by the KCC is expectedfrom paying Kansas state income taxes beginning January 1, 2021, and authorizes the KCC to adjust utility rates for the elimination of Kansas state income tax beginning January 1, 2021. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $84.2 million was recorded as a regulatory liability and will be refunded to our customers. This adjustment had no latermaterial impact on our income tax expense and no impact on our cash flows for the six months ended June 30, 2022. The bill stipulates that, if requested by the utility, this EDIT will be returned to Kansas customers over a period of no less than 30 years, with the exact timing to be determined in our next general rate proceeding. In August 2020, Kansas Gas Service submitted an application to the KCC to reduce its base rates to reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2017, with new rates2020, the KCC approved the reduction, effective January 1, 2018.2021.
Texas -Pursuant to securitization legislation enacted in Texas as a result of Winter Storm Uri and a June 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC on July 30, 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.
In April 2017, Kansas Gas Service filed an application withNovember 2021, the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, its 12 MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filedRRC approved a unanimous settlement agreement withbetween Texas Gas Service, the KCC. If approved,other natural gas utilities in Texas participating in the securitization process, the staff of the RRC and all intervenors. The settlement agreement will allow Kansasprovides that all costs incurred by Texas Gas Service to defer MGPpurchase natural gas during Winter Storm Uri were reasonable, necessary and prudently incurred. Texas Gas Service agreed to reduce its regulatory asset amount to be securitized by the amount of extraordinary costs (costs that are necessary for investigation and remediation atattributable to the 12 former MGP sites) incurred after January 1, 2017, up toWest Texas service area, which will be recovered through a cap of $15.0 million, net of any related insurance recoveries. Costs approved in a future rate proceeding would then be amortizedseparate surcharge over a 15-yearthree-year period.
On February 8, 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The unamortized amounts will not be included in rate base or accumulate carrying charges. AtTPFA formed the time future investigationTexas Natural Gas Securitization Finance Corporation, a new independent public authority, for purposes of issuing the securitized bonds and remediation work, net of any related insurance recoveries, ishas begun the process to issue the securitized bonds, which are expected to exceed $15.0 million, Kansasbe issued in the fourth quarter of 2022. At June 30, 2022, Texas Gas Service will be requiredhas deferred approximately $246.7 million in extraordinary costs associated with Winter Storm Uri, which includes $48.5 million attributable to file an application with the KCC for approvalWest Texas service area. Pursuant to increase the $15.0 million cap. The KCC is expected to issue anapproved settlement order, no later than earlyin January 2018. If the agreement is approved, we expect to record a regulatory asset of approximately $5.9 million for estimated costs that have been accrued at January 1, 2017.
In May 2016, Kansas2022, Texas Gas Service filed a requestbegan collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the KCC for an increase in base rates, reflecting system investments and operating costs necessary to maintain the safety and reliability of its natural gas distribution system. In October 2016, Kansas Gas Service reached a unanimous settlement agreement with all parties for a net increase in base rates of approximately $8.1 million. Including the GSRS of approximately $7.4 million, the total base rate increase was $15.5 million. The agreement was a “black-box settlement,” meaning the parties agreed to a specific revenue number but no specific return on equity or determination with respect to other contested issues. Additionally, the agreement modified the weather normalization clause to accrue the variation in net margin resultingWest Texas service area from the difference in actual weather relative to normal weather over 12 months, rather than five months. The KCC approved the new rates effective January 1, 2017.those customers.
Texas - West Texas Service Area -In March 2017,2022, Texas Gas Service made GRIP filings for all customers in the West Texas service area. The RRC and the cities approved anarea, requesting a $5.0 million increase of $4.3 million for the customers in the service area, and new rates becameto be effective in July 2017.2022. On June 23, 2022, the city of El Paso denied the requested increase and assessed fees associated with its review of the filing. Texas Gas Service appealed the city’s action to the RRC. All other municipalities, and the RRC, approved the new rates or allowed them to take effect with no action. Texas Gas Service implemented the new rates in July 2022, pending the outcome of the appeal.
In March 2016,On June 30, 2022, Texas Gas Service filed a rate case seeking to consolidate its West Texas, North Texas and Borger/Skellytown service areas into a single West-North service area and requesting a rate increase of $13.0 million. If approved, new rates are expected to take effect in the first quarter of 2023.
In March 2021, Texas Gas Service made GRIP filings for itsall customers in the West Texas service area, requesting an increase of $9.7 million to be effective in July 2021. On June 21, 2021, the city of El Paso Dell Cityapproved a motion which found the GRIP filing to be in compliance with the GRIP statute. The city subsequently denied the requested increase and Permian service areas, as well as consolidationassessed fees associated with its review of these three areas. In September 2016,the filing. On July 2, 2021, Texas Gas Service appealed the city’s action to the RRC. The RRC granted and approved the appeal, and new rates were effective on August 3, 2021. All other municipalities, and the RRC, approved the consolidation and a base rate increase of $8.8 million, which was based on a 9.5 percent return on equity and a 60.1 percent common equity ratio. In October 2016, new rates went intoor allowed them to take effect with no action.
Central-Gulf Service Area - In February 2022, Texas Gas Service made GRIP filings for all customers except for those in the citiesCentral-Gulf service area, requesting a $9.1 million increase effective in June 2022. All municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.
In February 2021, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting an increase of $10.7 million to be effective in June 2021. All municipalities, and the former Permian service area.RRC, approved the new rates or allowed them to take effect with no action.
Other Texas Service Areas - In April 2022, Texas Gas Service filed its annual COSA filings for these new
rates for customers in the citiesincorporated area of the former Permian service area in October 2016, and the rates became effective in December 2016.
Rio Grande Valley Service Area - service area, requesting an increase of $2.9 million. In October 2017,July 2022, the municipalities approved an increase of $2.5 million, and new rates will become effective in August 2022.
In April 2021, Texas Gas Service filed a rate case requesting an increase in revenues of $0.5 millionmade its annual COSA filings for its unincorporatedthe incorporated areas of the Rio Grande Valley service area. If approved, new rates are expected to be effective inarea and the fourth quarter of 2017.
In June 2017,North Texas Gas Service filed a rate case for customers in its Rio Grande Valley service area. In October 2017, Texas Gas Service andJuly 2021, the citiesmunicipalities in the Rio Grande Valley and North Texas service areaareas agreed to an increaseincreases of $3.6$3.5 million and new$1.4 million, respectively. New rates became effective in October 2017.August 2021.
Central Texas Service Area - In March 2017, Texas Gas Service made GRIP filings for customers of the consolidated Central Texas service area. The cities and the RRC approved an increase of $4.9 million, and new rates became effective in June 2017.
In June 2016, Texas Gas Service filed a rate case for its Central Texas and South Texas service areas. The filing included a request to consolidate the South Texas service area with the Central Texas service area. Texas Gas Service filed this rate case directly with the cities of the Central Texas service area, which includes the city of Austin, and the RRC for the unincorporated areas. In October 2016, all parties to the filing reached a unanimous settlement agreement for an increase in revenues of $6.8 million for the new consolidated service area. New rates were effective in November 2016, for customers in the cities of the former Central Texas service area. RRC approval was received in November 2016 and new rates became effective for customers in the unincorporated areas of the new consolidated Central Texas service area the same month. Texas Gas Service received approval for the same rates in the incorporated areas of the former South Texas service area, with new rates effective in January 2017.
Gulf Coast Service Area - In December 2015, Texas Gas Service filed a rate case for its Galveston and South Jefferson County service areas, which included a request to consolidate these two service areas into a new Gulf Coast service area. Texas Gas Service filed this rate case directly with the incorporated cities and the RRC for the unincorporated areas. Texas Gas Service reached a unanimous settlement agreement with representatives of the cities and the staff of the RRC, on behalf of the unincorporated areas for an increase in revenues of $2.3 million. Following RRC approval, new rates became effective in May 2016.
Other Texas Service Areas - 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. AnnualFor the six months ended June 30, 2022, no annual rate increases associated with these filings have been approved filings totaled $1.4and $0.4 million for the nine months ended September 30, 2017, and $2.0 millionwere approved for the year ended 2016.December 31, 2021.
OTHERWinter Storm Uri Deferred Costs - In accordance with regulatory orders associated with this winter weather event, we have deferred approximately $1.9 billion in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs. The amounts deferred at June 30, 2022, include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. In addition, as a result of Winter Storm Uri, we were assessed penalties as a result of over- or under-deliveries of natural gas during periods that operational flow orders were imposed on us. Additionally, Kansas Gas Service assessed penalties under the modified penalty provisions of its tariff on marketers and individually-balanced transportation customers, or their agents, as approved by the KCC in March 2022. Amounts recorded reflect management’s best estimate of the amounts we may pay or receive and may be adjusted in future periods as the disposition of disputed invoices and the collectability of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments to the amounts we have deferred are not expected to have a material impact on earnings.
In October 2017, we filed and received approval from the Oklahoma Insurance Department to form a wholly-owned captive insurance company.
FINANCIAL RESULTS AND OPERATING INFORMATION
We operate in one reportable and operating business segment: regulated public utilities that deliver natural gas to residential, commercial industrial, wholesale, public authority and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to theConsolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on operatingnet income.
Selected Financial Results - For the three months ended SeptemberJune 30, 2017,2022, net income was $18.8$32.1 million, or $0.36$0.59 per diluted share, compared with $12.7$30.1 million, or $0.24$0.56 per diluted share, in the same period last year. For the ninesix months ended SeptemberJune 30, 2017,2022, net income was $115.9$131.0 million, or $2.19$2.42 per diluted share, compared with $97.8$125.7 million, or $1.85$2.35 per diluted share, in the same period last year. Our prospective adoption of ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” resulted in favorable impacts to income tax expense and our net income from recording $5.2 million of excess tax benefits as a reduction to income tax expense in the first quarter 2017.
The following table sets forth certain selected financial results for our operations for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended | | Three Months | | Six Months |
| | June 30, | | June 30, | | 2022 vs. 2021 | | 2022 vs. 2021 |
| Financial Results | 2022 | | 2021 | | 2022 | | 2021 | | Increase (Decrease) | | Increase (Decrease) |
| | (Millions of dollars, except percentages) |
| Natural gas sales | $ | 393.2 | | | $ | 282.6 | | | $ | 1,320.2 | | | $ | 865.4 | | | $ | 110.6 | | | 39 | % | | $ | 454.8 | | | 53 | % |
| Transportation revenues | 28.0 | | | 26.3 | | | 64.8 | | | 62.5 | | | 1.7 | | | 6 | % | | 2.3 | | | 4 | % |
| Other revenues | 7.8 | | | 6.7 | | | 15.4 | | | 13 | | | 1.1 | | | 16 | % | | 2.4 | | | 18 | % |
| Total revenues | 429.0 | | | 315.6 | | | 1,400.4 | | | 940.9 | | | 113.4 | | | 36 | % | | 459.5 | | | 49 | % |
| Cost of natural gas | 188.3 | | | 93.7 | | | 828.2 | | | 407.8 | | | 94.6 | | | 101 | % | | 420.4 | | | 103 | % |
| Operating costs | 127.1 | | | 120.0 | | | 260.7 | | | 248.6 | | | 7.1 | | | 6 | % | | 12.1 | | | 5 | % |
| Depreciation and amortization | 55.0 | | | 50.8 | | | 112.2 | | | 103.1 | | | 4.2 | | | 8 | % | | 9.1 | | | 9 | % |
| Operating income | $ | 58.6 | | | $ | 51.1 | | | $ | 199.3 | | | $ | 181.4 | | | $ | 7.5 | | | 15 | % | | $ | 17.9 | | | 10 | % |
| Capital expenditures and asset removal costs | $ | 149.1 | | | $ | 129.4 | | | $ | 272.0 | | | $ | 238.4 | | | $ | 19.7 | | | 15 | % | | $ | 33.6 | | | 14 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended | | Three Months | | Nine Months |
| | September 30, | | September 30, | | 2017 vs. 2016 | | 2017 vs. 2016 |
| Financial Results | 2017 | | 2016 | | 2017 | | 2016 | | Increase (Decrease) | | Increase (Decrease) |
| | (Millions of dollars, except percentages) |
| Natural gas sales | $ | 218.7 |
| | $ | 204.3 |
| | $ | 981.9 |
| | $ | 892.9 |
| | $ | 14.4 |
| | 7 | % | | $ | 89.0 |
| | 10 | % |
| Transportation revenues | 21.5 |
| | 21.2 |
| | 73.1 |
| | 72.2 |
| | 0.3 |
| | 1 | % | | 0.9 |
| | 1 | % |
| Cost of natural gas | 58.8 |
| | 52.2 |
| | 404.5 |
| | 344.4 |
| | 6.6 |
| | 13 | % | | 60.1 |
| | 17 | % |
| Net margin, excluding other revenues | 181.4 |
| | 173.3 |
| | 650.5 |
| | 620.7 |
| | 8.1 |
| | 5 | % | | 29.8 |
| | 5 | % |
| Other revenues | 6.9 |
| | 6.6 |
| | 22.2 |
| | 21.3 |
| | 0.3 |
| | 5 | % | | 0.9 |
| | 4 | % |
| Net margin | 188.3 |
| | 179.9 |
| | 672.7 |
| | 642.0 |
| | 8.4 |
| | 5 | % | | 30.7 |
| | 5 | % |
| Operating costs | 109.1 |
| | 112.7 |
| | 349.4 |
| | 344.9 |
| | (3.6 | ) | | (3 | )% | | 4.5 |
| | 1 | % |
| Depreciation and amortization | 38.4 |
| | 36.3 |
| | 113.3 |
| | 106.5 |
| | 2.1 |
| | 6 | % | | 6.8 |
| | 6 | % |
| Operating income | $ | 40.8 |
| | $ | 30.9 |
| | $ | 210.0 |
| | $ | 190.6 |
| | $ | 9.9 |
| | 32 | % | | $ | 19.4 |
| | 10 | % |
| Capital expenditures | $ | 94.4 |
| | $ | 86.5 |
| | $ | 249.1 |
| | $ | 231.3 |
| | $ | 7.9 |
| | 9 | % | | $ | 17.8 |
| | 8 | % |
Net margin is comprisedNatural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariffs and rates approved by the regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales. Additionally, natural gas sales includes the recovery of total revenues lessour cost of natural gas.
Our natural gas sales include fixed and variable charges related to the delivery of natural gas and gas costs that are passed through to our customers in accordance with our cost of natural gas regulatory mechanisms. Fixed charges reflect the portion of our natural gas sales attributable to the monthly fixed customer charge component of our rates, which does not fluctuate based on customer usage in each period. Variable charges reflect the portion of our natural gas sales that fluctuate with the volumes delivered and billed and the effects of weather normalization.
Transportation revenues represent revenue from contracts with customers through implied contracts established by our tariffs and rates approved by the regulatory authorities, as well as tariff-based negotiated contracts.
Other revenues include primarily miscellaneous service charges which represent implied contracts with customers established by our tariffs and rates approved by the regulatory authorities and other revenues from regulatory mechanisms.
Cost of natural gas includes commodity purchases, fuel, storage, transportation, the cost ofhedging costs and settlement proceeds for natural gas component of bad debtsprice volatility mitigation programs approved by our regulators and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms during the periods presented and does not include an allocation of general operating costs or depreciation and amortization. Our cost of natural gasThese 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 recover, net marginpass-through to our customers, operating income is not affected by fluctuations in the cost of natural gas.
The following table sets forth our net margin, excluding other revenues, by type of customer, for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended | | Three Months | | Nine Months |
| Net Margin, Excluding Other | September 30, | | September 30, | | 2017 vs. 2016 | | 2017 vs. 2016 |
| Revenues | 2017 | | 2016 | | 2017 | | 2016 | | Increase (Decrease) | | Increase (Decrease) |
| Natural gas sales | (Millions of dollars, except percentages) |
| Residential | $ | 133.4 |
| | $ | 126.9 |
| | $ | 481.2 |
| | $ | 454.4 |
| | $ | 6.5 |
| | 5 | % | | $ | 26.8 |
| | 6 | % |
| Commercial and industrial | 25.4 |
| | 24.1 |
| | 91.9 |
| | 89.6 |
| | 1.3 |
| | 5 | % | | 2.3 |
| | 3 | % |
| Wholesale and public authority | 1.1 |
| | 1.1 |
| | 4.3 |
| | 4.5 |
| | — |
| | — | % | | (0.2 | ) | | (4 | )% |
| Net margin on natural gas sales | 159.9 |
| | 152.1 |
| | 577.4 |
| | 548.5 |
| | 7.8 |
| | 5 | % | | 28.9 |
| | 5 | % |
| Transportation revenues | 21.5 |
| | 21.2 |
| | 73.1 |
| | 72.2 |
| | 0.3 |
| | 1 | % | | 0.9 |
| | 1 | % |
| Net margin, excluding other revenues | $ | 181.4 |
| | $ | 173.3 |
| | $ | 650.5 |
| | $ | 620.7 |
| | $ | 8.1 |
| | 5 | % | | $ | 29.8 |
| | 5 | % |
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. We believe that the combination of the significant residential component of our customer base, the fixed charge component of our sales margin and our regulatory rate mechanisms that we have in place result in a stable cash flow profile. The following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended | | Three Months | | Nine Months |
| | September 30, | | September 30, | | 2017 vs. 2016 | | 2017 vs. 2016 |
| Net Margin on Natural Gas Sales | 2017 | | 2016 | | 2017 | | 2016 | | Increase (Decrease) | | Increase (Decrease) |
| Net margin on natural gas sales | (Millions of dollars, except percentages) | | | | |
| Fixed margin | $ | 142.0 |
| | $ | 137.0 |
| | $ | 422.7 |
| | $ | 418.8 |
| | $ | 5.0 |
| | 4 | % | | $ | 3.9 |
| | 1 | % |
| Variable margin | 17.9 |
| | 15.1 |
| | 154.7 |
| | 129.7 |
| | 2.8 |
| | 19 | % | | 25.0 |
| | 19 | % |
| Net margin on natural gas sales | $ | 159.9 |
| | $ | 152.1 |
| | $ | 577.4 |
| | $ | 548.5 |
| | $ | 7.8 |
| | 5 | % | | $ | 28.9 |
| | 5 | % |
Net marginOperating income increased $8.4$7.5 million for the three months ended SeptemberJune 30, 2017,2022, compared with the same period last year, due primarily to the following:
•an increase of $5.7$14.4 million from new rates in Texasrates; and Kansas;
•an increase of $1.0$1.5 million in residential sales due primarily to net customer growth in Oklahoma and Texas.
These increases were offset partially by:
•an increase of $5.8 million in outside service costs; and
•an increase of $0.7 million in employee-related costs, which reflects $3.3 million of higher labor and employee benefit costs, offset partially by a $2.7 million decrease in expenses associated with the change in our nonqualified employee benefit plan liabilities.
Operating income increased $17.9 million for the six months ended June 30, 2022, compared with the same period last year, due primarily to the following:
•an increase of $29.5 million from new rates;
•an increase of $4.1 million in residential sales due primarily to net customer growth in Oklahoma and Texas;
•a decrease of $3.0 million in bad debt expense; and
•an increase of $0.9$1.2 million fromin late payment, reconnect and collection fees.
These increases were offset partially by:
•an increase of $9.5 million in outside service costs;
•an increase of $9.1 million in depreciation expense due to additional capital expenditures being placed in service; and
•an increase of $2.9 million in employee-related costs, which reflects $5.4 million of higher labor and employee benefit costs, offset partially by a $2.5 million decrease in expenses associated with the impact of the modified weather-normalization mechanismchange in Kansas.our nonqualified employee benefit plan liabilities.
Other Factors Affecting Net margin increased $30.7 millionIncome - Other factors that affected net income for the ninethree months ended SeptemberJune 30, 2017,2022, compared with the same period last year, include an increase of $4.4 million in other expense, net, due primarily to a $6.5 million decrease in the following:market value of investments associated with our nonqualified employee benefit plans, offset partially by a $2.4 million decrease in net periodic benefit costs other than service costs.
an increase of $20.0 million from new rates in Texas and Kansas;
an increase of $5.5 million from the impact of weather-normalization mechanisms, which offset warmer weather in 2017 compared with the same period in 2016;
an increase of $2.7 million in residential sales due primarily toOther factors that affected net customer growth in Oklahoma and Texas; and
an increase of $1.7 million due primarily to higher transportation volumes from customers in Oklahoma and Kansas.
Operating costs decreased $3.6 millionincome for the threesix months ended SeptemberJune 30, 2017,2022, compared with the same period last year, include an increase of $8.2 million in other expense, net, due primarily to a $10.0 million decrease in the following:
a decreasemarket value of $1.6 million in costsinvestments associated with pipeline maintenance activities; and
a decrease of $1.3 million in legal-related costs.
Operating costs increased $4.5 million for the nine months ended September 30, 2017, compared with the same period last year, due primarily to the following:
an increase of $2.4 million from the deferral in the first quarter of 2016 of certain information technology costs incurred as a result of our separation from ONEOK in 2014, which was approved in Oklahoma as a regulatory asset;
an increase of $1.7 million in information technology costs;
an increase of $1.5 million in employee-related costs;
an increase of $1.0 million in bad debt expense; and
an increase of $0.8 million in costs associated with pipeline maintenance activities;nonqualified employee benefit plans, offset partially by
a $2.6 million decrease of $3.1 million in legal-relatednet periodic benefit costs other than service costs.
Depreciation andEDIT - Income tax expense reflects credits for the amortization expense increased $2.1of the regulatory liability associated with EDIT that was returned to customers of $3.0 million and $6.8$2.6 million for the three and nine months ended SeptemberJune 30, 2017,2022 and 2021, respectively, compared with the same periods last year, due primarily to an increase in depreciation from our capital expenditures being placed in service, offset by decreasesand credits of $0.6$10.9 million and $1.7$10.7 million respectively, in amortization expense associated primarily with other postemployment benefit deferrals in Kansas.for the six months ended June 30, 2022 and 2021, respectively.
Capital Expenditures and Asset Removal Costs - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements, automated meter reading, government-mandated pipeline relocations, fleet, facilities, IT assets and information technology assets.cybersecurity. It is our practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations. Asset removal costs include expenditures associated with the replacement or retirement of long-lived assets that result from the construction, development and/or normal use of our assets, primarily our pipeline assets. While we have not experienced a significant impact to our capital expenditures program in the six months ended June 30, 2022, our capital expenditure activity for the remainder of the year could experience a delay if economic conditions worsen, impacting our supply chain for contract labor, materials and supplies.
Capital expenditures increased $7.9and asset removal costs were $19.7 million and $17.8$33.6 million higher for the three and ninesix months ended SeptemberJune 30, 2017,2022, respectively, compared with the same periodsperiod last year, due primarily to increasedexpenditures for system integrity activities and extendingextension of service to new areas.areas. Our full-year capital expenditures and asset removal costs are expected to be approximately $650 million for 2022.
Selected Operating Information - The following tables set forth certain selected operating information for the periods indicated:
| | | | | Three Months Ended | Variances | | Three Months Ended | Variances |
| | | September 30, | 2017 vs. 2016 | | | June 30, | 2022 vs. 2021 |
| (in thousands) | | 2017 | 2016 | Increase (Decrease) | (in thousands) | | 2022 | 2021 | Increase (Decrease) |
| Average Number of Customers | | OK | KS | TX | Total | OK | KS | TX | Total | OK | KS | TX | Total | Average Number of Customers | | OK | KS | TX | Total | OK | KS | TX | Total | OK | KS | TX | Total |
| Residential | | 788 |
| 577 |
| 618 |
| 1,983 |
| 782 |
| 576 |
| 612 |
| 1,970 |
| 6 |
| 1 |
| 6 |
| 13 |
| Residential | | 833 | | 593 | | 658 | | 2,084 | | 826 | | 593 | | 651 | | 2,070 | | 7 | | — | | 7 | | 14 | |
| Commercial and industrial | | 72 |
| 50 |
| 34 |
| 156 |
| 71 |
| 50 |
| 34 |
| 155 |
| 1 |
| — |
| — |
| 1 |
| Commercial and industrial | | 77 | | 51 | | 35 | | 163 | | 76 | | 50 | | 35 | | 161 | | 1 | | 1 | | — | | 2 | |
| Wholesale and public authority | | — |
| — |
| 3 |
| 3 |
| — |
| — |
| 3 |
| 3 |
| — |
| — |
| — |
| — |
| |
| Other | | Other | | — | | — | | 3 | | 3 | | — | | — | | 3 | | 3 | | — | | — | | — | | — | |
| Transportation | | 5 |
| 6 |
| 1 |
| 12 |
| 6 |
| 6 |
| 1 |
| 13 |
| (1 | ) | — |
| — |
| (1 | ) | Transportation | | 5 | | 6 | | 1 | | 12 | | 5 | | 6 | | 1 | | 12 | | — | | — | | — | | — | |
| Total customers | | 865 |
| 633 |
| 656 |
| 2,154 |
| 859 |
| 632 |
| 650 |
| 2,141 |
| 6 |
| 1 |
| 6 |
| 13 |
| Total customers | | 915 | | 650 | | 697 | | 2,262 | | 907 | | 649 | | 690 | | 2,246 | | 8 | | 1 | | 7 | | 16 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended | Variances |
| | | June 30, | 2022 vs. 2021 |
| (in thousands) | | 2022 | 2021 | Increase (Decrease) |
| Average Number of Customers | | OK | KS | TX | Total | OK | KS | TX | Total | OK | KS | TX | Total |
| Residential | | 834 | | 595 | | 656 | | 2,085 | | 826 | | 594 | | 649 | | 2,069 | | 8 | | 1 | | 7 | | 16 | |
| Commercial and industrial | | 77 | | 51 | | 36 | | 164 | | 77 | | 50 | | 35 | | 162 | | — | | 1 | | 1 | | 2 | |
| Other | | — | | — | | 3 | | 3 | | — | | — | | 3 | | 3 | | — | | — | | — | | — | |
| Transportation | | 5 | | 6 | | 1 | | 12 | | 5 | | 6 | | 1 | | 12 | | — | | — | | — | | — | |
| Total customers | | 916 | | 652 | | 696 | | 2,264 | | 908 | | 650 | | 688 | | 2,246 | | 8 | | 2 | | 8 | | 18 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended | Variances |
| | | September 30, | 2017 vs. 2016 |
| (in thousands) | | 2017 | 2016 | Increase (Decrease) |
| Average Number of Customers | | OK | KS | TX | Total | OK | KS | TX | Total | OK | KS | TX | Total |
| Residential | | 793 |
| 583 |
| 618 |
| 1,994 |
| 788 |
| 582 |
| 612 |
| 1,982 |
| 5 |
| 1 |
| 6 |
| 12 |
|
| Commercial and industrial | | 73 |
| 50 |
| 35 |
| 158 |
| 73 |
| 50 |
| 35 |
| 158 |
| — |
| — |
| — |
| — |
|
| Wholesale and public authority | | — |
| — |
| 3 |
| 3 |
| — |
| — |
| 3 |
| 3 |
| — |
| — |
| — |
| — |
|
| Transportation | | 6 |
| 6 |
| 1 |
| 13 |
| 5 |
| 6 |
| 1 |
| 12 |
| 1 |
| — |
| — |
| 1 |
|
| Total customers | | 872 |
| 639 |
| 657 |
| 2,168 |
| 866 |
| 638 |
| 651 |
| 2,155 |
| 6 |
| 1 |
| 6 |
| 13 |
|
|
| | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
Volumes (MMcf) | | 2017 | | 2016 | | 2017 | | 2016 |
| Natural gas sales | | | | | | | | |
| Residential | | 7,449 |
| | 7,425 |
| | 69,578 |
| | 69,687 |
|
| Commercial and industrial | | 3,808 |
| | 3,590 |
| | 22,993 |
| | 22,408 |
|
| Wholesale and public authority | | 223 |
| | 261 |
| | 1,211 |
| | 1,542 |
|
| Total volumes sold | | 11,480 |
| | 11,276 |
| | 93,782 |
| | 93,637 |
|
| Transportation | | 46,412 |
| | 46,036 |
| | 156,589 |
| | 154,857 |
|
| Total volumes delivered | | 57,892 |
| | 57,312 |
| | 250,371 |
| | 248,494 |
|
Total volumes sold increased slightlyThe increase in the average number of customers for the periods presented, is due primarily to the connection of new customers resulting from the extension and expansion of our system in our service areas. For the three months ended SeptemberJune 30, 2017,2022, our average customer count includes approximately 5,700 new customer connections during the period compared withto approximately 5,400 for the same period last year. For the six months ended June 30, 2022, our average customer count includes approximately 12,400 new customer connections during the period compared to approximately 11,300 for the same period last year. For the year ended December 31, 2021, our average customer count included approximately 24,900 new customer connections.
The following table reflects total volumes delivered, excluding the effects of WNA mechanisms on sales volumes:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | | June 30, | | June 30, |
Volumes (MMcf) | | 2022 | | 2021 | | 2022 | | 2021 |
| Natural gas sales | | | | | | | | |
| Residential | | 13,790 | | | 14,802 | | | 74,440 | | | 77,781 | |
| Commercial and industrial | | 6,188 | | | 5,617 | | | 25,557 | | | 24,106 | |
| Other | | 564 | | | 421 | | | 1,675 | | | 1,502 | |
| Total sales volumes delivered | | 20,542 | | | 20,840 | | | 101,672 | | | 103,389 | |
| Transportation | | 53,392 | | | 52,457 | | | 120,463 | | | 116,776 | |
| Total volumes delivered | | 73,934 | | | 73,297 | | | 222,135 | | | 220,165 | |
The impact of weather on residential and commercial net marginnatural gas sales is mitigated by weather-normalizationWNA mechanisms in all jurisdictions.
Wholesale sales represent contracted natural gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. The impact to net margin from changes in volumes associated with these customers is minimal.
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended |
| | | September 30, |
| | | 2017 | | 2016 | | 2017 vs. 2016 | | 2017 | | 2016 |
| Heating Degree Days | | Actual | | Normal | | Actual | | Normal | | Actual Variance | | Actual as a percent of Normal |
| Oklahoma | | 3 |
| | 2 |
| | 3 |
| | 2 |
| | — | % | | 150 | % | | 150 | % |
| Kansas | | 13 |
| | 58 |
| | 19 |
| | 52 |
| | (32 | )% | | 22 | % | | 37 | % |
| Texas | | 1 |
| | 1 |
| | 2 |
| | 1 |
| | (50 | )% | | 100 | % | | 200 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended |
| | June 30, |
| | 2022 | | 2021 | | 2022 vs. 2021 | | 2022 | | 2021 |
| Heating Degree Days | | Actual | | Normal | | Actual | | Normal | | Actual Variance | | Actual as a percent of Normal |
| Oklahoma | | 219 | | | 228 | | | 274 | | | 191 | | | (20) | % | | 96 | % | | 143 | % |
| Kansas | | 399 | | | 394 | | | 415 | | | 394 | | | (4) | % | | 101 | % | | 105 | % |
| Texas | | 17 | | | 50 | | | 62 | | | 50 | | | (73) | % | | 34 | % | | 124 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended |
| | June 30, |
| | 2022 | | 2021 | | 2022 vs. 2021 | | 2022 | | 2021 |
| Heating Degree Days | | Actual | | Normal | | Actual | | Normal | | Actual Variance | | Actual as a percent of Normal |
| Oklahoma | | 2,204 | | | 2,020 | | | 2,319 | | | 1,966 | | | (5) | % | | 109 | % | | 118 | % |
| Kansas | | 2,931 | | | 2,855 | | | 2,905 | | | 2,855 | | | 1 | % | | 103 | % | | 102 | % |
| Texas | | 1,199 | | | 1,049 | | | 1,127 | | | 1,050 | | | 6 | % | | 114 | % | | 107 | % |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended |
| | | September 30, |
| | | 2017 | | 2016 | | 2017 vs. 2016 | | 2017 | | 2016 |
| Heating Degree Days | | Actual | | Normal | | Actual | | Normal | | Actual Variance | | Actual as a percent of Normal |
| Oklahoma | | 1,577 |
| | 1,968 |
| | 1,730 |
| | 1,968 |
| | (9 | )% | | 80 | % | | 88 | % |
| Kansas | | 2,344 |
| | 2,980 |
| | 2,459 |
| | 2,965 |
| | (5 | )% | | 79 | % | | 83 | % |
| Texas | | 659 |
| | 1,063 |
| | 899 |
| | 1,034 |
| | (27 | )% | | 62 | % | | 87 | % |
Normal HDDs are established through rate proceedings in each of our rate jurisdictions for use primarily in weather-normalizationweather normalization billing calculations. See further discussion on weather normalization in our Regulatory Overview section in Part 1, Item 1, “Business,” of our Annual Report. Normal HDDs disclosed above are based on:
•Oklahoma - For years 2021 through the current period, 10-year weighted average HDDs as of December 31, 2014, for years 2005-2014,June 30, 2021, as calculated using 11 weather stations across Oklahoma and weighted on average customer count for Oklahoma;count.
•Kansas - For April 2019 and forward, a 30-year rolling average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as1988-2017 calculated using 4three weather stations across Kansas and weighted on HDDs by weather station and customers for Kansas; andcustomers.
an•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 jurisdiction for Texas.service area.
Actual HDDs are based on the quarter-to-date and year-to-date, weighted average of:
•11 weather stations and customers by month for Oklahoma;
4•3 weather stations and customers by month for Kansas; and
•9 weather stations and natural gas distribution sales volumes by service area for Texas.
Through March 31, 2017, Kansas Gas Services’ WNA clause required it to accrue the variation in net margin resulting from actual weather differing from normal weather occurring from November through March. Beginning in April 2017, Kansas Gas Services’ WNA clause requires an accrual each month of the year.
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 final outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.
LIQUIDITY AND CAPITAL RESOURCES
General - We have relied primarily on operating cash flow and commercial paper for our liquidity and capital resource requirements. We fund operating expenses, working capital requirements, including purchases of natural gas other than the extraordinary gas purchases during Winter Storm Uri, and capital expenditures, primarily with cash from operations and commercial paper. Natural gas prices have increased during the six months ended June 30, 2022, which impacts our investment in natural gas in storage as well as working capital for receivables and payables.
We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales net marginrevenues and our regulatory rate mechanisms that we have in place result in a stable cash flow profile. Because the energy consumption of residential customers is less volatile compared with commercialprofile and industrial customers, our business historically has generated stable and predictable net margin and cash flows.earnings. Additionally, we have several regulatory rate mechanisms in place toin our jurisdictions that reduce the lag in earning
a return on our capital expenditures.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, and our financial condition and credit ratings. We believe that stronger credit ratings will provide a significant advantage to our business. By maintaining a conservative financial profile and stable revenue base, we believeexpect to maintain credit ratings at a level that we will be able to maintain
an investment-grade credit rating, which we believe will provide ussupports our access to diverse sources of capital at favorable rates in orderfor capital investments and expenses.
Short-term Debt - On March 16, 2022, we entered into the first amendment to finance our infrastructure investments.
Short-term Financing - In October 2017, wethe second amended and restated our credit agreement. ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the maturity date of the ONE Gas Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changes the benchmark rate defined in the ONE Gas Credit Agreement to SOFR as administered by the Federal Reserve Bank of New York. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.
The ONE Gas Credit Agreement remainsprovides for a $700.0 million$1.0 billion revolving unsecured credit facility and includes a $20.0$20 million letter of credit subfacility and a $60.0$60 million swingline subfacility. We will also be able tocan request an increase in commitments of up to an additional $500.0
$500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2022, 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 contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At SeptemberJune 30, 2017,2022, our total debt-to-capital ratio was 4163 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.
We have aIn June 2021, we increased the size of our commercial paper program under which we may issue unsecuredto permit the issuance of commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs.needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time. The maturities of the commercial paper notes may vary but may not exceed 270 days from the date of issue. The commercialCommercial paper notes areis generally sold at par less a discount representing an interest factor.
The ONE Gas Credit Agreement is available to repay the At June 30, 2022, we had $490.1 million of commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement. outstanding.
At SeptemberJune 30, 2017,2022, we had $174.0 million in short-term borrowings and $1.8$1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement. At September 30, 2017, we had approximately $6.9 million of cash and cash equivalents and $524.2Agreement, with $998.8 million of remaining credit, which is available to repay any of our commercial paper borrowings.
In connection with the second amendment and restatement of the ONE Gas Credit Agreement on March 16, 2021, all commitments under our ONE Gas 364-day Credit Agreement, dated as of April 7, 2020, were terminated and all obligations under the ONE Gas 364-day Credit Agreement. The total amount of short-term borrowings authorized by ONE Gas’ Board of Directors is $1.2 billion.Agreement were paid in full and discharged.
Long-TermLong-term Debt - In March 2021, we issued $1.0 billion of 0.85 percent senior notes due March 2023, $700 million of 1.10 percent senior notes due March 2024, and $800 million of floating-rate senior notes due March 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year, reset quarterly for the applicable interest period (2.35 percent at June 30, 2022).
In the event LIBOR is not available, and such circumstances are unlikely to be temporary, we or our designee may establish an alternative interest rate for our floating-rate senior notes due 2023 by replacing LIBOR with one or more secured financing-based rates or another alternate benchmark rate. The net proceeds from the issuance were used for payment of gas purchases and related costs resulting from Winter Storm Uri and general corporate purposes.
In September 2021, we called $400 million of the floating-rate senior notes due 2023 at par, using a combination of cash on hand and commercial paper. We did not have the right to call these senior notes prior to September 11, 2021. We expect to use the proceeds from the issuance of securitized bonds in each state, as discussed in Note 3 of the Notes to Consolidated Financials
Statements in this Quarterly Report, to call the outstanding senior notes due March 2023 and a portion of the senior notes due March 2024.
The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.
In February 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.
At SeptemberJune 30, 2017,2022, our long-term debt-to-capital ratio was 3860 percent.
Credit Ratings- Our credit ratings as of SeptemberJune 30, 2017,2022, were:
|
| | | | | | | |
| Rating Agency | Rating | Outlook |
| Moody’s | A2A3 | Stable |
| S&P | ABBB+ | StablePositive |
Our commercial paper is currently rated Prime-1Prime-2 by Moody’s and A-1A-2 by S&P. We intend to maintain strong credit metrics while we pursueat a level that supports our balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be competitive with our peer group.
At-the-Market Equity Program - In February 2020, we initiated an at-the-market equity program by entering into an equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $250 million (including any shares of common stock that may be sold pursuant to the master forward sale confirmation entered into in connection with the equity distribution agreement and the related supplemental confirmations). Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. For the six months ended June 30, 2022 and 2021, respectively, we issued and sold 403,792 shares and 198,438 shares of our common stock for $35.0 million and $15.3 million, generating proceeds, net of issuance costs, of $34.7 million and $15.1 million.
For the six months ended June 30, 2022, we executed forward sale agreements for 591,736 shares of our common stock, which must be settled on or before January 2, 2024. No shares of common stock have been settled under the forward sale agreements. Had we settled all shares under the forward agreements as of June 30, 2022, we would have generated net proceeds of $48.3 million, or $81.54 per share.
EDIT - The return of EDIT to our customers is not expected to have a material impact on earnings, as any reduction or credit in rates is largely offset by a noncash reduction in income tax expense. However, as a result, cash flows for the three months ended June 30, 2022 and 2021, were reduced by approximately $3.0 million and $2.6 million, respectively, for EDIT returned to customers. Cash flows for the six months ended June 30, 2022 and 2021, were reduced by approximately $10.9 million and $10.7 million, respectively, for EDIT returned to customers.
Pension and Other Postemployment Benefit Plans- In 2022, our contributions are expected to be $1.5 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans. We use a December 31 measurement date for our plans. On April 30, 2022, we amended our defined benefit pension plans to change the variable cost of living adjustment for eligible participants, to a fixed rate. Therefore, our pension plans were remeasured as of April 30, 2022, resulting in an adjustment of approximately $7.2 million to our pension expense, net of capitalization and regulatory deferrals, for the year ending December 31, 2022, beginning May 1, 2022.
Information about our pension and other postemployment benefits plans, including anticipated contributions, is included under Note 1114 of the ONE Gas Notes to theConsolidated Financial Statements in our Annual Report. See Note 89 of the Notes to theConsolidated Financial Statements in this Quarterly Report for additional information.
CASH FLOW ANALYSIS
We use the indirect method to prepare our Statementsconsolidated statements of Cash Flows.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:
| | | | | | | | | | | | | | | | | |
| Six Months Ended | | |
| | June 30, | | Variance |
| | 2022 | | 2021 | | 2022 vs. 2021 |
| | (Millions of dollars) |
| Total cash provided by (used in): | | | | | |
| Operating activities | $ | 286.7 | | | $ | (1,577.3) | | | $ | 1,864.0 | |
| Investing activities | (251.5) | | | (219.1) | | | (32.4) | |
| Financing activities | (36.7) | | | 1,997.6 | | | (2,034.3) | |
| Change in cash and cash equivalents | (1.5) | | | 201.2 | | | (202.7) | |
| Cash and cash equivalents at beginning of period | 8.9 | | | 8.0 | | | 0.9 | |
| Cash and cash equivalents at end of period | $ | 7.4 | | | $ | 209.2 | | | $ | (201.8) | |
|
| | | | | | | | | | | |
| | Nine Months Ended | | |
| | September 30, | | Variance |
| | 2017 | | 2016 | | 2017 vs. 2016 |
| | (Millions of dollars) |
| Total cash provided by (used in): | | | | | |
| Operating activities | $ | 302.4 |
| | $ | 290.4 |
| | $ | 12.0 |
|
| Investing activities | (248.4 | ) | | (230.8 | ) | | (17.6 | ) |
| Financing activities | (61.8 | ) | | (57.5 | ) | | (4.3 | ) |
| Change in cash and cash equivalents | (7.8 | ) | | 2.1 |
| | (9.9 | ) |
| Cash and cash equivalents at beginning of period | 14.7 |
| | 2.4 |
| | 12.3 |
|
| Cash and cash equivalents at end of period | $ | 6.9 |
| | $ | 4.5 |
| | $ | 2.4 |
|
Operating Cash Flows-Changes in cash flows from operating activities are due primarily to changes in net marginsales revenues, natural gas costs and operating expenses discussed in Financial Results and Operating Information.Information, the effects of Winter Storm Uri and tax reform discussed in Regulatory Activities and changes in working capital. Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions, variations in weather not mitigated by WNAs, changes in supply or increased competition from other service providers, could affect our earnings and operating cash flows.Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.
Operating cash flows were higher for the ninesix months ended SeptemberJune 30, 2017,2022, compared with the sameprior period, in 2016, due primarily to an increase in net income, offset partially by cash flows from operating asset and liability changes. Working capital changes related to accounts payable andthe increased natural gas in storage were impacted by higher costs of natural gaspurchases in the first nine months of 2017, compared with the sameprior period resulting from Winter Storm Uri, which were deferred and included in 2016. Changes in accounts receivable were impacted by a higher cost of natural gas delivered in the fourth quarter of 2016 collected in the nine months ended September 30, 2017, compared with the same period in 2015 collected in the nine months ended September 30, 2016. Additionally, we collected a tax receivable in 2016 related to the extensionregulatory assets. See Note 3 of the IRS rulesNotes to Consolidated Financial Statements in this Quarterly Report for bonus depreciation in late 2015.additional information.
Investing Cash Flows-Cash used in investing activities increased for the ninesix months ended SeptemberJune 30, 2017,2022, due primarily to an increase in capital expenditures for system integrity and extension of service to new areas.
Financing Cash Flows-Cash provided by financing activities decreased for the six months ended June 30, 2022, compared with the prior period, due primarily to an increase in capital expenditures related to increased system integrity activities and extending service to new areas during the nine months ended September 30, 2017.
Financing Cash Flows-Cash used in financing activities increased for the nine months ended September 30, 2017, compared with the prior period due primarilyborrowings to an increase in the dividend rate of seven cents compared with the same period in 2016, offset by the purchase of fewer shares of treasury stock.finance natural gas purchases resulting from Winter Storm Uri.
ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS
COVID-19 - See “Recent Developments,” as well as Notes 3 and 12 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion regarding the effects of COVID-19 on us.
Environmental Matters - We are subject to multiple historical, wildlife preservationlaws and environmental laws and/or regulations thatregarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air ActCAA and other similar federal and state laws could require unexpected capital expenditures. We
cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and ninesix months ended SeptemberJune 30, 20172022 and 2016.2021.
We own or retain legal responsibility for thecertain 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.
We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites, and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. Regulatory closure has been achieved at threefive of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs. During 2016, we completed a site assessment at the twelfth site where no active soil remediation has occurred.
We have submitted a work plan to the KDHE for approval to address a source of contamination and associated contaminated soil on a portion of this site. We are also conducting a study of the feasibility of various options to address the remainder of the site. Costs associated with the remediation at this site are not expected to be material to our results of operations or financial position.
With regard to one of our former MGP sites, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. Additional testing and work plan development is underway in 2017 to determine a remediation work plan to present to the KDHE for approval, which could impact our estimates of the cost of remediation at this site. In the fourth quarter of 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded a reserve of $4.0 million for this site in the fourth quarter of 2016.
In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, its 12 MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC. If approved, the agreement will allowthat allows Kansas Gas Service to defer MGPand seek recovery of costs (costs that are necessary for investigation and remediation at, theand nearby, these 12 former MGP sites)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. At the timeFollowing 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, is expected to exceed $15.0 million, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC is expectedAt June 30, 2022, we have deferred $29.9 million for accrued investigation and remediation costs pursuant to issueour AAO. Kansas Gas Service expects to file an orderapplication as soon as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2023.
We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at seven of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no later than early January 2018. Ifactive soil remediation had previously occurred. A remediation plan concerning this site was submitted to the agreement is approved,KDHE in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan for an additional site that we expect to recordsubmit to the KDHE in 2023.
We also own or retain legal responsibility for certain environmental conditions at a regulatory assetformer MGP site in Texas. At the request of approximately $5.9 million forthe TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. On April 14, 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. At June 30, 2022, estimated costs that have been accrued at January 1, 2017.associated with expected remediation activities for this site are not material.
Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and ninesix months ended SeptemberJune 30, 20172022 and 2016. A number2021. The reserve for remediation of environmentalour MGP sites was $17.8 million and $22.8 million at June 30, 2022 and December 31, 2021, respectively. Environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.
We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and those costs may adversely affect our financial condition, results of operations and cash flows. 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,regulation under federal pipeline safety statutes and any analogous state regulations. These include safety requirements for the design, construction, operation, and maintenance of pipelines, including integrity-management regulations.transmission and distribution pipelines. At the federal level, we are regulated by PHMSA. PHMSA regulations require the following for certain pipelines: inspection and maintenance plans; integrity management programs, including the determination of pipeline companies operating high-pressure transmission pipelines to perform integrity risks and periodic assessments on certain pipeline segmentssegments; an operator qualification program, which includes certain trainings; a public awareness program that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, the Pipeline Safety, Regulatory Certaintyprovides certain information; and Job Creation Act was signed into law. The law increased maximum penalties for violating federala control room management plan.
As part of regulating 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 high-consequence areas;
a verification of records for pipelinesPHMSA promulgates various regulations. For example, in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.
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 includeincluded changes to pipeline integrity management requirements and other safety-related requirements. TheSubsequently, PHMSA announced they would split this NPRM comment period ended July 7, 2016,into three separate final rulemakings:
•the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and comments are under review by PHMSA. As partJob Creation Act and is called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;
•the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the comment review process,NPRM (except for gas gathering pipelines); and
•the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.
On October 1, 2019, PHMSA is being advised bypublished the Technical Pipeline Safety Standards Committee, informally known by first of the three final rules referenced above, which addressed the 2011 congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline, and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP within 15 years. The first final rule became effective July 1, 2020. Our estimated capital and operating expenditures associated with compliance with the first final rulemaking were not material.
PHMSA ashas not yet issued 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.second final rule. The potential capital and operating expenditures associated with compliance with the proposedthis rule are currently being evaluated and could be significant depending on the final regulations.regulation. We do not expect to be impacted by the third final rule, as we do not own gas gathering pipelines.
Separately, as part of the Consolidated Appropriations Act, 2021, the PIPES Act of 2020 reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. To the extent such rulemakings impose more stringent requirements on our facilities, we may be required to incur expenditures that may be material.
Air and Water Emissions - The Clean Air Act,CAA, the Clean Water Act, and analogous state laws and/or regulations promulgated thereunder, impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Failure to comply with these requirements may result in substantial fines or other penalties, including (in certain cases) the revocation of necessary permits. Under the Clean Air Act,CAA, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air-pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. We doSuch expenditures have not expect that these expenditures will havehad a material impact on our respective results of operations, financial position or cash flows.flows; however, we cannot predict the impacts of any future requirements. The Clean Water Act imposes substantial potential liability for the removaldischarge of pollutants discharged tointo waters of the United States, andincluding the potential for fines, civil enforcement, or orders to perform remediation of waters affected by such discharge.
Climate – The threat of climate change continues to attract considerable attention. International, federal, regional and/or state legislative and/or regulatory initiatives may attemptbe proposed in the future to regulate greenhouse gas emissions. For example, President Biden has announced that climate change will be a focus of his administration and has signed several executive orders on the subject. For more information, see our risk factor titled “Carbon neutral, energy-efficiency or other legislation or regulations intended to address climate change could increase our operating costs or restrict our market opportunities, adversely affecting our financial results, growth, cash flows and results of operations” in our Annual Report. We monitor relevant legislation and regulatory initiatives to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual greenhouse gas emissions reporting as carbon dioxide equivalents from affected facilities and
for the natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own emissions. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has been enacted for natural gas distribution that assesses any costs, fees or expenses on any of these emissions.
CERCLAOur operations may also be indirectly impacted by regulations attempting to limit or control climate impacts. For example, there is a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an executive order calling for the development of a climate finance plan and, separately, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.
Waste and Hazardous Substances - During the course of our operations, we may use or generate hazardous substances and wastes, including hazardous wastes. The generation, use, storage, transportation, handling, and disposal of such materials may be subject to federal, state, and local laws. For example, the Resource Conservation and Recovery Act regulates both solid and hazardous wastes, including the imposition of detailed requirements for the handling, storage, treatment, and disposal of hazardous wastes. Separately, CERCLA, also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) 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
Pipeline Security - In May and July 2021, TSA issued security directives which included several new cybersecurity requirements for critical pipeline owners and operators. The first security directive requires critical pipeline owners and operators to (1) report confirmed and potential cybersecurity incidents to the CISA; (2) designate a cybersecurity coordinator to be available 24 hours a day, seven days a week; (3) review current practices; and (4) identify any gaps and related remediation measures to address cyber-related risks and report the results to TSA and CISA within 30 days. The second security directive requires owners and operators of TSA-designated critical pipelines to implement specific mitigation measures to protect against ransomware and other known threats to information technology and operational technology systems, develop and implement a cybersecurity contingency and recovery plan, and conduct a cybersecurity architecture design review. Compliance with these measures has not expect that our responsibilities under CERCLA will havehad a material impact on our resultsoperations. We continue to evaluate the potential effect of these directives on our operations financial positionand facilities, as well as the potential cost of implementation, and will continue to monitor for any clarifications or cash flows.amendments to these directives.
Pipeline Security - The U.S. Department of Homeland Security’s Transportation Security Administration issued updated pipeline security guidelines in April 2012. 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 according to current rules issued by the EPA; (2) monitoring and improving the integrity of our various pipelines; (3) following developing technologies for emission control; (4) promoting end-use conservation through programs that incentivize the use of high-efficiency equipment; and (4) utilizing practices to reduce(5) reducing the loss of methane from our facilities. In addition, we are considering potential avenues to incorporate RNG and hydrogen into our operations. RNG and hydrogen technologies offer potential opportunities to secure new natural gas supply sources that could be transported on our pipeline system and potentially reduce greenhouse gas emissions.
We participate in several programs to voluntarily reduce methane emissions including the EPA’s Natural Gas STAR Program, the EPA’s Natural Gas STAR Methane Challenge Program, and Our Nation’s Energy Future (ONE Future). By joining these programs, we committed to: 1) evaluate our methane emission reduction opportunities; 2) implement practices to voluntarily reduce methane emissions.emissions where feasible; and 3) annually report our methane emissions and/or our methane reduction activities. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. Additionally, in March 2016, we were oneAs part 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 commitmentwe have committed to annually replace or rehabilitate at least two percent of our combined inventory of cast iron and noncathodically-protected steel pipe, which aligns with our planned system integrity expenditures for infrastructure replacements. We exceeded our goal by achieving an overall replacement rate greater than two percent annually every year from 2016 through 2021 and anticipate reporting on our 2022 progress in 2018 our calendar year 2017 performance relative2023.
We continue to assess various opportunities for emission reductions and other potential improvements to our commitment.environmental footprint. However, we cannot guarantee that we will be able to implement any of the opportunities that we may review or
explore. For any such opportunities that we do choose to implement, we cannot guarantee that we will be able to implement them within a specific timeframe or across all operational assets.
In September 2020, we announced membership in ONE Future, a group of natural gas companies working together to voluntarily reduce methane emissions across the natural gas value chain to one percent or less by 2025. We submitted our 2020 data, which ONE Future aggregates with peer members. In its most recent report, ONE Future stated that its members registered a 2020 methane intensity of 0.424 percent, which surpassed the 2025 goal of 1.0 percent. The intensity for the distribution sector, which includes us, was 0.118 percent, beating the goal of 0.225 percent by 46 percent. Participating distribution companies represented 40 percent of the natural gas delivered in the U.S. in 2020.
Additional information about our environmental matters is included in the section entitled “Environmental Matters” in Note 912 of the Notes to theConsolidated Financial Statements in this Quarterly Report. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation, and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows for the three and six months ended June 30, 2022 and 2021.
Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See additional information regarding our regulatory initiatives in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of new accounting standards, if any, is included in Note 1 of the Notes to theConsolidated 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 revenuerevenues and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.
Information about our estimates and critical accounting policies is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Estimates and Critical Accounting Policies,” in our Annual Report.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, liquidity, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Forward-looking and other statements in this Quarterly Report regarding our environmental, social and other sustainability plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future.
Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,
“guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” “likely,” and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Quarterly Report. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, costs, liquidity, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
•our ability to recover costs (including operating costs and increased commodity costs related to Winter Storm Uri in February 2021), income taxes and amounts equivalent to income taxes, coststhe cost of property, plant and equipment, and regulatory assets and our allowed rate of return in our regulated rates;rates or other recovery mechanisms;
•cyber-attacks, which, according to experts, have increased in volume and sophistication since the beginning of the COVID-19 pandemic, or breaches of technology systems that could disrupt our operations or result in the loss or exposure of confidential or sensitive customer, employee or Company information; further, increased remote working arrangements as a result of the pandemic have required enhancements and modifications to our IT infrastructure (e.g. Internet, Virtual Private Network, remote collaboration systems, etc.), and any failures of the technologies, including third-party service providers, that facilitate working remotely could limit our ability to conduct ordinary operations or expose us to increased risk or effect of an attack;
•our ability to manage our operations and maintenance costs;
•the concentration of our operations in Kansas, Oklahoma, and Texas;
•changes in regulation of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;
•the economic climate and, particularly, its effect on the natural gas requirements of our residential and
commercial industrial customers;
•the length and severity of a pandemic or other health crisis, such as the outbreak of COVID-19, including the impact to our operations, customers, contractors, vendors and employees, the effectiveness of vaccine campaigns (including the COVID-19 vaccine campaign) on our workforce and customers and the effect of other measures or mandates that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address the pandemic or other health crisis, which could (as with COVID-19) precipitate or exacerbate one or more of the above-mentioned and/or other risks, and significantly disrupt or prevent us from operating our business in the ordinary course for an extended period;
•competition from alternative forms of energy, including, but not limited to, electricity, solar power, wind power, geothermal energy and biofuels;
conservation efforts of our customers;
•adverse weather conditions and variations in weather, including seasonal effects on demand and/or supply, the occurrence of severe storms and disasters,in the territories in which we operate, and climate change;change, and the related effects on supply, demand, and costs;
•indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantage compared with competitors;
•our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of existing supply and transportation and storage arrangements that are not replaced with contracts with similar terms and pricing;
the•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 integrity of facilities operated;hazards or interruptions;
operational hazards and unforeseen operational interruptions;
•adverse labor relations;
•the effectiveness of our strategies to reduce earnings lag, marginrevenue protection strategies and risk mitigation strategies;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 generate sufficientobtain capital on commercially reasonable terms, or on terms acceptable to us, or at all;
•limitations on our operating flexibility, earnings and cash flows due to meetrestrictions in our financing arrangements;
•cross-default provisions in our borrowing arrangements, which may lead to our inability to satisfy all of our cash needs;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;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;customers, including those related to Winter Storm Uri and any related financing required to support our purchase of natural gas supply, including the securitized financings currently contemplated in each of our jurisdictions;
•impact of potential impairment charges;
•volatility and changes in markets for natural gas;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;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 rules and regulations to which we and our subsidiaries are subject;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;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;serve, and economic conditions in these areas’ housing markets;
•acts of nature and the potential effects of threatened or actual terrorism and war, including war;recent events in Europe;
cyber attacks or breaches of technology systems or information, affecting us, our customers or vendors;
•the sufficiency of insurance coverage to cover losses;
•the effects of our strategies to reduce tax payments;
•the outcomes, timing and effects of litigation and regulatory investigations, proceedings, including our rate cases, or inquiries;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•existence of material weaknesses in our internal controls;
•our ability to comply with all covenants in our indentures and the ONE Gas Credit Agreement, a violation of which, if not cured in a timely manner, could trigger a default of our obligations;
•our ability to attract and retain talented employees, management and directors;directors, or a shortage of skilled labor;
•unexpected increases in the costs of providing health care benefits, along with pension and postemployment health care benefits, as well as declines in the discount rates on, declines in the market value of the debt and equity securities of, and increases in funding requirements for, our defined benefit plans; and
the•our ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;divestiture.
the final resolutions or outcomes with respect to our contingent and other corporate liabilities related to the natural gas distribution business and any related actions for indemnification made pursuant to the Separation and Distribution Agreement with ONEOK; and
the costs associated with increased regulation and enhanced disclosure and corporate governance requirements pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.
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.
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ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.mechanisms through which we pass-through natural gas costs to our customers without profit. We may use
derivative instruments to economically hedge the cost of a portion of our anticipated natural gas purchases during the winter heating months to reduce the impact on our customers of upward market price volatility of natural gas. Additionally, we inject natural gas into storage during the summer months, when natural gas prices are typically lower, and withdraw the natural gas during the winter heating season. Pursuant to programs that are approved by our regulatory authorities, we use derivative instruments to mitigate the volatility of natural gas prices for anticipated natural gas purchases during the winter heating months. Premiums paid and any cash settlements receivedGains or losses associated with these derivative instruments and storage activities are included in, and recoverable through our purchased-gas cost adjustment mechanisms.mechanisms, which are subject to review by regulatory authorities.
Interest-Rate Risk
We would beare exposed to interest-rate risk primarily associated with anycommercial paper borrowings and new debt financing.financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt. We are able tomay 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.appropriate and allowed by tariff. With more than 2approximately 2.3 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain a provision for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current credit environment and other information. In Oklahoma, Kansas and most jurisdictions we serve in Texas, weWe are able to recover the natural gas cost componentfuel-related portion of our uncollectible accountsbad debts through our purchased-gas cost adjustment mechanisms.
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ITEM 4.
| CONTROLS AND PROCEDURES |
ITEM 4.CONTROLS AND PROCEDURES
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 thirdsecond quarter ended SeptemberJune 30, 2017,2022, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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 final outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.
ITEM 1A. RISK FACTORS
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.
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ITEM 2.
| UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Not applicable.
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ITEM 3. | DEFAULTS UPON SENIOR SECURITIES |
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not applicable.
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ITEM 4. | MINE SAFETY DISCLOSURES |
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
Not applicable.
ITEM 6.EXHIBITS
Readers of this report should not rely on or assume the accuracy of any representation or warranty or the validity of any opinion contained in any agreement filed as an exhibit to this Quarterly Report, because such representation, warranty or opinion may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent an allocation of risk between parties in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes, or may no longer continue to be true as of any given date. All exhibits attached to this Quarterly Report are included for the purpose of complying with requirements of the SEC. Other than the certifications made by our officers pursuant to the Sarbanes-Oxley Act of 2002 included as exhibits to this Quarterly Report, all exhibits are included only to provide information to investors regarding their respective terms and should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.
The following exhibits are filed as part of this Quarterly Report:
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| Exhibit No. | Exhibit Description |
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| 10.13.1 | Credit Agreement, dated asAmended Certificate of October 5, 2017, amongIncorporation of ONE Gas, Inc., Bank of America, N.A., as administrative agent, swingline lender and a letter of credit issuer, and the other lenders and letter of credit issuers parties theretodated May 24, 2018 (incorporated by reference to Exhibit 10.13.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed October 6, 2017on May 30, 2018 (File No. 1-36108)). |
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| 31.13.2 | |
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| 31.1 | |
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| 31.2 | |
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| 32.1 | |
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| 32.2 | |
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| 101.INS | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
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| 101.INS101.SCH | XBRL Instance Document. |
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| 101.SCH | XBRL Schema Document. |
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| 101.CAL | XBRL Calculation Linkbase Document. |
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| 101.LAB | XBRL Label Linkbase Document. |
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| 101. PRE101.PRE | XBRL Presentation Linkbase Document. |
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| 101.DEF | XBRL Extension Definition Linkbase Document. |
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| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document and contained in Exhibit 101). |
Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and ninesix months ended Septembermonths ended June 30, 20172022 and 2016;2021; (iii) Consolidated Statements of Comprehensive Income for the three and ninesix months ended Septembermonths ended June 30, 20172022 and 2016;2021; (iv) Consolidated Balance Sheets at SeptemberJune 30, 20172022 and December 31, 2016;2021; (v) Consolidated Statements of Cash Flows for the ninesix months ended SeptemberJune 30, 20172022 and 2016;2021; (vi) StatementConsolidated Statements of Equity for the ninethree and six months ended Septembermonths ended June 30, 2017;2022 and 2021; and (vii) Notes to theConsolidated Financial Statements.
We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.
SIGNATURE
Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| Date: August 2, 2022 | | ONE Gas, Inc. |
| | Registrant |
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Date: October 31, 2017 | By: | ONE Gas, Inc./s/ Caron A. Lawhorn |
| | RegistrantCaron A. Lawhorn |
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| By: | /s/ Curtis L. Dinan |
| | Curtis L. Dinan |
| | Senior Vice President and |
| | Chief Financial Officer and Treasurer |
| | (Principal Financial Officer) |