Oklahoma | 46-3561936 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
15 East Fifth Street, Tulsa, OK | 74103 |
(Address of principal executive offices) | (Zip Code) |
Large accelerated filer X | Accelerated filer __ |
Non-accelerated filer __ | (Do not check if a smaller reporting company) |
Smaller reporting company__ | |
Emerging growth company__ |
Financial Information | Page No. | |
Consolidated Financial Statements (Unaudited) | ||
Consolidated Statements of Income - Three and Six Months Ended June 30, 2018 and 2017 | ||
Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2018 and 2017 | ||
Consolidated Balance Sheets - June 30, 2018 and December 31, 2017 | ||
Consolidated Statements of Cash Flows - Six Months Ended June 30, 2018 and 2017 | ||
Consolidated Statement of Equity - Six Months Ended June 30, 2018 | ||
Notes to the Consolidated Financial Statements | ||
AAO | Accounting Authority Order |
ADIT | Accumulated deferred income tax |
Annual Report | Annual Report on Form 10-K for the year ended December 31, 2017 |
ASU | Accounting Standards Update |
Bcf | Billion cubic feet |
CERCLA | Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended |
Clean Air Act | Federal Clean Air Act, as amended |
Clean Water Act | Federal Water Pollution Control Amendments of 1972, as amended |
Code | Internal Revenue Code of 1986, as amended |
COSA | Cost-of-Service Adjustment |
DOT | United States Department of Transportation |
EPA | United States Environmental Protection Agency |
EPS | Earnings per share |
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 |
GPAC | 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 |
KCC | Kansas Corporation Commission |
KDHE | Kansas Department of Health and Environment |
LDC | Local distribution company |
MGP | Manufactured Gas Plant |
MMcf | Million cubic feet |
Moody’s | Moody’s Investors Service, Inc. |
NOL | Net operating loss |
NPRM | Notice of Proposed Rulemaking |
NYMEX | New York Mercantile Exchange |
OCC | Oklahoma Corporation Commission |
ONE Gas | ONE Gas, Inc. |
ONE Gas Credit Agreement | ONE Gas’ $700 million amended and restated revolving credit agreement, which expires on October 5, 2022 |
ONEOK | 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 |
RRC | Railroad Commission of Texas |
S&P | Standard & Poor’s Ratings Services |
SAB | Staff Accounting Bulletin |
SEC | Securities and Exchange Commission |
Securities Act | Securities Act of 1933, as amended |
Senior Notes | ONE Gas’ registered notes consisting of $300 million of 2.07 percent senior notes due 2019, $300 million of 3.61 percent senior notes due 2024 and $600 million of 4.658 percent notes due 2044 |
Separation and Distribution Agreement | Separation and Distribution Agreement dated January 14, 2014, between ONEOK and ONE Gas |
WNA | Weather-normalization adjustments |
XBRL | eXtensible Business Reporting Language |
ONE Gas, Inc. | ||||||||||||||||
CONSOLIDATED STATEMENTS OF INCOME | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(Unaudited) | 2018 | 2017 | 2018 | 2017 | ||||||||||||
(Thousands of dollars, except per share amounts) | ||||||||||||||||
Revenues | ||||||||||||||||
Revenues from contracts with customers | $ | 291,168 | $ | 274,033 | $ | 926,405 | $ | 810,193 | ||||||||
Other revenues | 1,353 | 5,656 | 4,580 | 19,904 | ||||||||||||
Total revenues | 292,521 | 279,689 | 930,985 | 830,097 | ||||||||||||
Cost of natural gas | 94,159 | 82,572 | 444,578 | 345,726 | ||||||||||||
Net margin | 198,362 | 197,117 | 486,407 | 484,371 | ||||||||||||
Operating expenses | ||||||||||||||||
Operations and maintenance | 102,995 | 96,928 | 205,660 | 201,972 | ||||||||||||
Depreciation and amortization | 39,757 | 37,851 | 78,647 | 74,870 | ||||||||||||
General taxes | 14,567 | 13,973 | 30,767 | 29,719 | ||||||||||||
Total operating expenses | 157,319 | 148,752 | 315,074 | 306,561 | ||||||||||||
Operating income | 41,043 | 48,365 | 171,333 | 177,810 | ||||||||||||
Other expense, net | (2,194 | ) | (3,900 | ) | (4,358 | ) | (7,307 | ) | ||||||||
Interest expense, net | (12,003 | ) | (11,305 | ) | (24,355 | ) | (22,786 | ) | ||||||||
Income before income taxes | 26,846 | 33,160 | 142,620 | 147,717 | ||||||||||||
Income taxes | (6,427 | ) | (12,537 | ) | (31,366 | ) | (50,638 | ) | ||||||||
Net income | $ | 20,419 | $ | 20,623 | $ | 111,254 | $ | 97,079 | ||||||||
Earnings per share | ||||||||||||||||
Basic | $ | 0.39 | $ | 0.39 | $ | 2.11 | $ | 1.85 | ||||||||
Diluted | $ | 0.39 | $ | 0.39 | $ | 2.10 | $ | 1.83 | ||||||||
Average shares (thousands) | ||||||||||||||||
Basic | 52,692 | 52,553 | 52,648 | 52,565 | ||||||||||||
Diluted | 52,899 | 52,969 | 52,898 | 53,012 | ||||||||||||
Dividends declared per share of stock | $ | 0.46 | $ | 0.42 | $ | 0.92 | $ | 0.84 |
ONE Gas, Inc. | |||||||||||||||
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
(Unaudited) | 2018 | 2017 | 2018 | 2017 | |||||||||||
(Thousands of dollars) | |||||||||||||||
Net income | $ | 20,419 | $ | 20,623 | $ | 111,254 | $ | 97,079 | |||||||
Other comprehensive income (loss), net of tax | |||||||||||||||
Change in pension and other postemployment benefit plan liability, net of tax of $(68), $(81), $(419) and $(161), respectively | 203 | 129 | 123 | 258 | |||||||||||
Total other comprehensive income (loss), net of tax | 203 | 129 | 123 | 258 | |||||||||||
Comprehensive income | $ | 20,622 | $ | 20,752 | $ | 111,377 | $ | 97,337 |
ONE Gas, Inc. | ||||||||
CONSOLIDATED BALANCE SHEETS | ||||||||
June 30, | December 31, | |||||||
(Unaudited) | 2018 | 2017 | ||||||
Assets | (Thousands of dollars) | |||||||
Property, plant and equipment | ||||||||
Property, plant and equipment | $ | 5,870,814 | $ | 5,713,912 | ||||
Accumulated depreciation and amortization | 1,745,124 | 1,706,327 | ||||||
Net property, plant and equipment | 4,125,690 | 4,007,585 | ||||||
Current assets | ||||||||
Cash and cash equivalents | 12,580 | 14,413 | ||||||
Accounts receivable, net | 163,967 | 298,768 | ||||||
Materials and supplies | 36,124 | 39,672 | ||||||
Natural gas in storage | 80,482 | 130,154 | ||||||
Regulatory assets | 39,402 | 88,180 | ||||||
Other current assets | 18,154 | 17,807 | ||||||
Total current assets | 350,709 | 588,994 | ||||||
Goodwill and other assets | ||||||||
Regulatory assets | 385,564 | 405,189 | ||||||
Goodwill | 157,953 | 157,953 | ||||||
Other assets | 48,003 | 47,157 | ||||||
Total goodwill and other assets | 591,520 | 610,299 | ||||||
Total assets | $ | 5,067,919 | $ | 5,206,878 |
ONE Gas, Inc. | ||||||||
CONSOLIDATED BALANCE SHEETS | ||||||||
(Continued) | ||||||||
June 30, | December 31, | |||||||
(Unaudited) | 2018 | 2017 | ||||||
Equity and Liabilities | (Thousands of dollars) | |||||||
Equity and long-term debt | ||||||||
Common stock, $0.01 par value: authorized 250,000,000 shares; issued 52,598,005 shares and outstanding 52,516,828 shares at June 30, 2018; issued 52,598,005 and outstanding 52,312,516 shares at December 31, 2017 | $ | 526 | $ | 526 | ||||
Paid-in capital | 1,723,795 | 1,737,551 | ||||||
Retained earnings | 308,652 | 246,121 | ||||||
Accumulated other comprehensive income (loss) | (5,370 | ) | (5,493 | ) | ||||
Treasury stock, at cost: 81,177 shares at June 30, 2018 and 285,489 shares at December 31, 2017 | (5,259 | ) | (18,496 | ) | ||||
Total equity | 2,022,344 | 1,960,209 | ||||||
Long-term debt, excluding current maturities, and net of issuance costs of $7,614 and $8,033, respectively | 893,671 | 1,193,257 | ||||||
Total equity and long-term debt | 2,916,015 | 3,153,466 | ||||||
Current liabilities | ||||||||
Current maturities of long-term debt | 300,008 | 8 | ||||||
Notes payable | 185,000 | 357,215 | ||||||
Accounts payable | 70,429 | 143,681 | ||||||
Accrued interest | 19,028 | 18,776 | ||||||
Accrued taxes other than income | 34,931 | 41,324 | ||||||
Accrued liabilities | 20,724 | 30,058 | ||||||
Regulatory liabilities | 47,867 | 9,438 | ||||||
Customer deposits | 61,249 | 60,811 | ||||||
Other current liabilities | 10,102 | 12,019 | ||||||
Total current liabilities | 749,338 | 673,330 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes | 628,532 | 599,945 | ||||||
Regulatory liabilities | 521,717 | 519,421 | ||||||
Employee benefit obligations | 160,382 | 172,938 | ||||||
Other deferred credits | 91,935 | 87,778 | ||||||
Total deferred credits and other liabilities | 1,402,566 | 1,380,082 | ||||||
Commitments and contingencies | ||||||||
Total liabilities and equity | $ | 5,067,919 | $ | 5,206,878 |
ONE Gas, Inc. | ||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||
Six Months Ended | ||||||||
June 30, | ||||||||
(Unaudited) | 2018 | 2017 | ||||||
(Thousands of dollars) | ||||||||
Operating activities | ||||||||
Net income | $ | 111,254 | $ | 97,079 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 78,647 | 74,870 | ||||||
Deferred income taxes | 30,546 | 50,308 | ||||||
Share-based compensation expense | 4,080 | 4,951 | ||||||
Provision for doubtful accounts | 4,071 | 3,501 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 130,730 | 135,165 | ||||||
Materials and supplies | 3,548 | (2,792 | ) | |||||
Natural gas in storage | 49,672 | 10,436 | ||||||
Asset removal costs | (25,774 | ) | (22,837 | ) | ||||
Accounts payable | (68,428 | ) | (68,992 | ) | ||||
Accrued interest | 252 | 104 | ||||||
Accrued taxes other than income | (6,393 | ) | (9,009 | ) | ||||
Accrued liabilities | (9,334 | ) | (6,729 | ) | ||||
Customer deposits | 438 | (686 | ) | |||||
Regulatory assets and liabilities | 105,967 | 19,782 | ||||||
Other assets and liabilities | (9,319 | ) | (5,880 | ) | ||||
Cash provided by operating activities | 399,957 | 279,271 | ||||||
Investing activities | ||||||||
Capital expenditures | (175,834 | ) | (154,666 | ) | ||||
Other | — | 477 | ||||||
Cash used in investing activities | (175,834 | ) | (154,189 | ) | ||||
Financing activities | ||||||||
Repayments of notes payable, net | (172,215 | ) | (66,000 | ) | ||||
Repurchase of common stock | — | (17,512 | ) | |||||
Issuance of common stock | 2,390 | 2,208 | ||||||
Dividends paid | (48,272 | ) | (44,042 | ) | ||||
Tax withholdings related to net share settlements of stock compensation | (7,859 | ) | (9,286 | ) | ||||
Cash used in financing activities | (225,956 | ) | (134,632 | ) | ||||
Change in cash and cash equivalents | (1,833 | ) | (9,550 | ) | ||||
Cash and cash equivalents at beginning of period | 14,413 | 14,663 | ||||||
Cash and cash equivalents at end of period | $ | 12,580 | $ | 5,113 |
ONE Gas, Inc. | |||||||||
CONSOLIDATED STATEMENT OF EQUITY | |||||||||
(Unaudited) | Common Stock Issued | Common Stock | Paid-in Capital | ||||||
(Shares) | (Thousands of dollars) | ||||||||
January 1, 2018 | 52,598,005 | $ | 526 | $ | 1,737,551 | ||||
Net income | — | — | — | ||||||
Other comprehensive income | — | — | — | ||||||
Common stock issued and other | — | — | (14,207 | ) | |||||
Common stock dividends - $0.92 per share | — | — | 451 | ||||||
June 30, 2018 | 52,598,005 | $ | 526 | $ | 1,723,795 |
ONE Gas, Inc. | |||||||||||||
CONSOLIDATED STATEMENT OF EQUITY | |||||||||||||
(Continued) | |||||||||||||
(Unaudited) | Retained Earnings | Treasury Stock | Accumulated Other Comprehensive Income (Loss) | Total Equity | |||||||||
(Thousands of dollars) | |||||||||||||
January 1, 2018 | $ | 246,121 | $ | (18,496 | ) | $ | (5,493 | ) | $ | 1,960,209 | |||
Net income | 111,254 | — | — | 111,254 | |||||||||
Other comprehensive income | — | — | 123 | 123 | |||||||||
Common stock issued and other | — | 13,237 | — | (970 | ) | ||||||||
Common stock dividends - $0.92 per share | (48,723 | ) | — | — | (48,272 | ) | |||||||
June 30, 2018 | $ | 308,652 | $ | (5,259 | ) | $ | (5,370 | ) | $ | 2,022,344 |
1. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
2. | REVENUE |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
(Thousands of dollars) | ||||||||||||||||
Natural gas sales to customers | $ | 261,347 | $ | 247,494 | $ | 856,273 | $ | 747,663 | ||||||||
Transportation revenues | 24,062 | 21,343 | 57,605 | 51,549 | ||||||||||||
Miscellaneous revenues | 5,759 | 5,196 | 12,527 | 10,981 | ||||||||||||
Total revenues from contracts with customers | 291,168 | 274,033 | 926,405 | 810,193 | ||||||||||||
Other revenues - natural gas sales related | (1,108 | ) | 3,377 | (78 | ) | 15,540 | ||||||||||
Other revenues | 2,461 | 2,279 | 4,658 | 4,364 | ||||||||||||
Total other revenues | 1,353 | 5,656 | 4,580 | 19,904 | ||||||||||||
Total revenues | $ | 292,521 | $ | 279,689 | $ | 930,985 | $ | 830,097 |
3. | REGULATORY ASSETS AND LIABILITIES |
June 30, 2018 | ||||||||||||||
Current | Noncurrent | Total | ||||||||||||
(Thousands of dollars) | ||||||||||||||
Under-recovered purchased-gas costs | $ | 6,741 | $ | — | $ | 6,741 | ||||||||
Pension and postemployment benefit costs | 25,109 | 367,751 | 392,860 | |||||||||||
Reacquired debt costs | 812 | 6,892 | 7,704 | |||||||||||
MGP remediation costs | — | 7,724 | 7,724 | |||||||||||
Ad valorem tax | 662 | — | 662 | |||||||||||
Other | 6,078 | 3,197 | 9,275 | |||||||||||
Total regulatory assets, net of amortization | 39,402 | 385,564 | 424,966 | |||||||||||
Federal income tax rate changes (a) | (16,183 | ) | (521,717 | ) | (537,900 | ) | ||||||||
Over-recovered purchased-gas costs | (31,457 | ) | — | (31,457 | ) | |||||||||
Weather normalization | (227 | ) | — | (227 | ) | |||||||||
Total regulatory liabilities | (47,867 | ) | (521,717 | ) | (569,584 | ) | ||||||||
Net regulatory assets (liabilities) | $ | (8,465 | ) | $ | (136,153 | ) | $ | (144,618 | ) |
December 31, 2017 | ||||||||||||||
Current | Noncurrent | Total | ||||||||||||
(Thousands of dollars) | ||||||||||||||
Under-recovered purchased-gas costs | $ | 41,238 | $ | — | $ | 41,238 | ||||||||
Pension and postemployment benefit costs | 25,156 | 387,582 | 412,738 | |||||||||||
Weather normalization | 17,461 | — | 17,461 | |||||||||||
Reacquired debt costs | 812 | 7,298 | 8,110 | |||||||||||
MGP remediation costs | — | 6,104 | 6,104 | |||||||||||
Other | 3,513 | 4,205 | 7,718 | |||||||||||
Total regulatory assets, net of amortization | 88,180 | 405,189 | 493,369 | |||||||||||
Federal income tax rate changes (a) | — | (519,421 | ) | (519,421 | ) | |||||||||
Over-recovered purchased-gas costs | (9,434 | ) | — | (9,434 | ) | |||||||||
Ad valorem tax | (4 | ) | — | (4 | ) | |||||||||
Total regulatory liabilities | (9,438 | ) | (519,421 | ) | (528,859 | ) | ||||||||
Net regulatory assets (liabilities) | $ | 78,742 | $ | (114,232 | ) | $ | (35,490 | ) |
4. | CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE |
5. | LONG-TERM DEBT |
6. | EQUITY |
7. | ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) |
Three Months Ended | Six Months Ended | Affected Line Item in the | ||||||||||||||
Details about Accumulated Other | June 30, | June 30, | Consolidated Statements | |||||||||||||
Comprehensive Income (Loss) Components | 2018 | 2017 | 2018 | 2017 | of Income | |||||||||||
(Thousands of dollars) | ||||||||||||||||
Pension and other postemployment benefit plan obligations (a) | ||||||||||||||||
Amortization of net loss | $ | 10,950 | $ | 10,648 | $ | 21,900 | $ | 21,296 | ||||||||
Amortization of unrecognized prior service cost | (1,142 | ) | (1,149 | ) | (2,284 | ) | (2,298 | ) | ||||||||
9,808 | 9,499 | 19,616 | 18,998 | |||||||||||||
Regulatory adjustments (b) | (9,537 | ) | (9,289 | ) | (19,074 | ) | (18,579 | ) | ||||||||
271 | 210 | 542 | 419 | Income before income taxes | ||||||||||||
(68 | ) | (81 | ) | (419 | ) | (161 | ) | Income tax expense | ||||||||
Total reclassifications for the period | $ | 203 | $ | 129 | $ | 123 | $ | 258 | Net income |
8. | EARNINGS PER SHARE |
Three Months Ended June 30, 2018 | ||||||||||
Income | Shares | Per Share Amount | ||||||||
(Thousands, except per share amounts) | ||||||||||
Basic EPS Calculation | ||||||||||
Net income available for common stock | $ | 20,419 | 52,692 | $ | 0.39 | |||||
Diluted EPS Calculation | ||||||||||
Effect of dilutive securities | — | 207 | ||||||||
Net income available for common stock and common stock equivalents | $ | 20,419 | 52,899 | $ | 0.39 |
Three Months Ended June 30, 2017 | ||||||||||
Income | Shares | Per Share Amount | ||||||||
(Thousands, except per share amounts) | ||||||||||
Basic EPS Calculation | ||||||||||
Net income available for common stock | $ | 20,623 | 52,553 | $ | 0.39 | |||||
Diluted EPS Calculation | ||||||||||
Effect of dilutive securities | — | 416 | ||||||||
Net income available for common stock and common stock equivalents | $ | 20,623 | 52,969 | $ | 0.39 |
Six Months Ended June 30, 2018 | ||||||||||
Income | Shares | Per Share Amount | ||||||||
(Thousands, except per share amounts) | ||||||||||
Basic EPS Calculation | ||||||||||
Net income available for common stock | $ | 111,254 | 52,648 | $ | 2.11 | |||||
Diluted EPS Calculation | ||||||||||
Effect of dilutive securities | — | 250 | ||||||||
Net income available for common stock and common stock equivalents | $ | 111,254 | 52,898 | $ | 2.10 |
Six Months Ended June 30, 2017 | ||||||||||
Income | Shares | Per Share Amount | ||||||||
(Thousands, except per share amounts) | ||||||||||
Basic EPS Calculation | ||||||||||
Net income available for common stock | $ | 97,079 | 52,565 | $ | 1.85 | |||||
Diluted EPS Calculation | ||||||||||
Effect of dilutive securities | — | 447 | ||||||||
Net income available for common stock and common stock equivalents | $ | 97,079 | 53,012 | $ | 1.83 |
9. | EMPLOYEE BENEFIT PLANS |
Pension Benefits | |||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||
June 30, | June 30, | ||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||
(Thousands of dollars) | |||||||||||||
Components of net periodic benefit cost | |||||||||||||
Service cost | $ | 3,230 | $ | 3,044 | $ | 6,460 | $ | 6,088 | |||||
Interest cost (a) | 9,200 | 10,113 | 18,400 | 20,226 | |||||||||
Expected return on assets (a) | (15,145 | ) | (14,624 | ) | (30,290 | ) | (29,248 | ) | |||||
Amortization of net loss (a) | 9,978 | 9,027 | 19,956 | 18,054 | |||||||||
Net periodic benefit cost | $ | 7,263 | $ | 7,560 | $ | 14,526 | $ | 15,120 |
Other Postemployment Benefits | |||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||
June 30, | June 30, | ||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||
(Thousands of dollars) | |||||||||||||
Components of net periodic benefit (credit) cost | |||||||||||||
Service cost | $ | 589 | $ | 627 | $ | 1,178 | $ | 1,254 | |||||
Interest cost (a) | 2,279 | 2,472 | 4,558 | 4,944 | |||||||||
Expected return on assets (a) | (3,571 | ) | (3,147 | ) | (7,142 | ) | (6,294 | ) | |||||
Amortization of unrecognized prior service cost (a) | (1,142 | ) | (1,149 | ) | (2,284 | ) | (2,298 | ) | |||||
Amortization of net loss (a) | 972 | 1,621 | 1,944 | 3,242 | |||||||||
Net periodic benefit (credit) cost | $ | (873 | ) | $ | 424 | $ | (1,746 | ) | $ | 848 |
10. | INCOME TAXES |
11. | OTHER INCOME AND OTHER EXPENSE |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
(Thousands of dollars) | ||||||||||||||||
Net periodic benefit cost other than service cost | $ | (2,403 | ) | $ | (4,313 | ) | $ | (4,137 | ) | $ | (8,626 | ) | ||||
Other, net | 209 | 413 | (221 | ) | 1,319 | |||||||||||
Total other income (expense), net | $ | (2,194 | ) | $ | (3,900 | ) | $ | (4,358 | ) | $ | (7,307 | ) |
12. | COMMITMENTS AND CONTINGENCIES |
• | an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas; |
• | a verification of records for pipelines 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. |
• | the first final rule will address the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation Act and will be called the Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments; |
• | the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering); and |
• | the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering. |
13. | DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS |
Recognition and Measurement | ||||
Accounting Treatment | Balance Sheet | Income Statement | ||
Normal purchases and normal sales | - | Recorded at historical cost | - | 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 |
• | 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. |
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Three Months Ended | Six Months Ended | Three Months | Six Months | ||||||||||||||||||||||||||
June 30, | June 30, | 2018 vs. 2017 | 2018 vs. 2017 | ||||||||||||||||||||||||||
Financial Results | 2018 | 2017 | 2018 | 2017 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||||
(Millions of dollars, except percentages) | |||||||||||||||||||||||||||||
Natural gas sales to customers | $ | 260.2 | $ | 250.9 | $ | 856.2 | $ | 763.2 | $ | 9.3 | 4 | % | $ | 93.0 | 12 | % | |||||||||||||
Transportation revenues | 24.1 | 21.4 | 57.6 | 51.6 | 2.7 | 13 | % | 6.0 | 12 | % | |||||||||||||||||||
Cost of natural gas | 94.2 | 82.5 | 444.6 | 345.7 | 11.7 | 14 | % | 98.9 | 29 | % | |||||||||||||||||||
Net margin, excluding other revenues | 190.1 | 189.8 | 469.2 | 469.1 | 0.3 | — | % | 0.1 | — | % | |||||||||||||||||||
Other utility revenues | 8.3 | 7.4 | 17.2 | 15.3 | 0.9 | 12 | % | 1.9 | 12 | % | |||||||||||||||||||
Net margin | 198.4 | 197.2 | 486.4 | 484.4 | 1.2 | 1 | % | 2.0 | — | % | |||||||||||||||||||
Operating costs | 117.6 | 110.9 | 236.4 | 231.7 | 6.7 | 6 | % | 4.7 | 2 | % | |||||||||||||||||||
Depreciation and amortization | 39.8 | 37.9 | 78.7 | 74.9 | 1.9 | 5 | % | 3.8 | 5 | % | |||||||||||||||||||
Operating income | $ | 41.0 | $ | 48.4 | $ | 171.3 | $ | 177.8 | $ | (7.4 | ) | (15 | )% | $ | (6.5 | ) | (4 | )% | |||||||||||
Capital expenditures | $ | 89.2 | $ | 84.2 | $ | 175.8 | $ | 154.7 | $ | 5.0 | 6 | % | $ | 21.1 | 14 | % |
Three Months Ended | Six Months Ended | Three Months | Six Months | ||||||||||||||||||||||||||
Net Margin, Excluding Other | June 30, | June 30, | 2018 vs. 2017 | 2018 vs. 2017 | |||||||||||||||||||||||||
Revenues | 2018 | 2017 | 2018 | 2017 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||||
Natural gas sales | (Millions of dollars, except percentages) | ||||||||||||||||||||||||||||
Residential | $ | 137.1 | $ | 139.7 | $ | 341.2 | $ | 347.9 | $ | (2.6 | ) | (2 | )% | $ | (6.7 | ) | (2 | )% | |||||||||||
Commercial and industrial | 27.5 | 27.5 | 67.2 | 66.4 | — | — | % | 0.8 | 1 | % | |||||||||||||||||||
Wholesale and public authority | 1.4 | 1.2 | 3.2 | 3.2 | 0.2 | 17 | % | — | — | % | |||||||||||||||||||
Net margin on natural gas sales | 166.0 | 168.4 | 411.6 | 417.5 | (2.4 | ) | (1 | )% | (5.9 | ) | (1 | )% | |||||||||||||||||
Transportation revenues | 24.1 | 21.4 | 57.6 | 51.6 | 2.7 | 13 | % | 6.0 | 12 | % | |||||||||||||||||||
Net margin, excluding other revenues | $ | 190.1 | $ | 189.8 | $ | 469.2 | $ | 469.1 | $ | 0.3 | — | % | $ | 0.1 | — | % |
Three Months Ended | Six Months Ended | Three Months | Six Months | ||||||||||||||||||||||||||
June 30, | June 30, | 2018 vs. 2017 | 2018 vs. 2017 | ||||||||||||||||||||||||||
Net Margin on Natural Gas Sales | 2018 | 2017 | 2018 | 2017 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||||
Net margin on natural gas sales | (Millions of dollars, except percentages) | ||||||||||||||||||||||||||||
Fixed margin | $ | 137.7 | $ | 141.5 | $ | 274.1 | $ | 280.7 | $ | (3.8 | ) | (3 | )% | $ | (6.6 | ) | (2 | )% | |||||||||||
Variable margin | 28.3 | 26.9 | 137.5 | 136.8 | 1.4 | 5 | % | 0.7 | 1 | % | |||||||||||||||||||
Net margin on natural gas sales | $ | 166.0 | $ | 168.4 | $ | 411.6 | $ | 417.5 | $ | (2.4 | ) | (1 | )% | $ | (5.9 | ) | (1 | )% |
• | an increase of $3.8 million from new rates in Texas and Kansas; |
• | an increase of $2.4 million due to higher sales volumes, net of weather normalization, primarily from colder weather in 2018 compared with 2017; |
• | an increase of $2.1 million due primarily to higher transportation volumes; and |
• | an increase of $1.1 million in residential sales due primarily to net customer growth in Oklahoma and Texas; offset by |
• | a decrease of $9.2 million related to the deferral of potential refund obligations associated with the Tax Cuts and Jobs Act of 2017. |
• | an increase of $8.9 million from new rates in Texas and Kansas; |
• | an increase of $4.8 million due to higher sales volumes, net of weather normalization, primarily from colder weather in 2018 compared with 2017; |
• | an increase of $4.6 million due primarily to higher transportation volumes; |
• | an increase of $2.4 million in residential sales due primarily to net customer growth in Oklahoma and Texas; |
• | an increase of $1.1 million in rider and surcharge recoveries due to higher ad-valorem surcharge in Kansas, offset by higher regulatory amortization in depreciation and amortization expense below; and |
• | an increase of $0.9 million due to the benefit of the retroactive 2017 compressed natural gas federal excise tax credit enacted in February 2018; offset by |
• | a decrease of $21.5 million related to the deferral of potential refund obligations associated with the Tax Cuts and Jobs Act of 2017. |
• | an increase of $7.9 million in employee-related costs; offset by |
• | a decrease of $1.3 million in outside service costs associated with pipeline maintenance activities. |
• | an increase of $7.9 million in employee-related costs; offset by |
• | a decrease of $2.4 million in outside service costs associated with pipeline maintenance activities. |
Three Months Ended | Variances | ||||||||||||||||||||||||
June 30, | 2018 vs. 2017 | ||||||||||||||||||||||||
(in thousands) | 2018 | 2017 | Increase (Decrease) | ||||||||||||||||||||||
Average Number of Customers | OK | KS | TX | Total | OK | KS | TX | Total | OK | KS | TX | Total | |||||||||||||
Residential | 798 | 586 | 624 | 2,008 | 794 | 584 | 619 | 1,997 | 4 | 2 | 5 | 11 | |||||||||||||
Commercial and industrial | 74 | 50 | 35 | 159 | 73 | 50 | 35 | 158 | 1 | — | — | 1 | |||||||||||||
Wholesale and public authority | — | — | 3 | 3 | — | — | 3 | 3 | — | — | — | — | |||||||||||||
Transportation | 5 | 6 | 1 | 12 | 5 | 6 | 1 | 12 | — | — | — | — | |||||||||||||
Total customers | 877 | 642 | 663 | 2,182 | 872 | 640 | 658 | 2,170 | 5 | 2 | 5 | 12 |
Six Months Ended | Variances | ||||||||||||||||||||||||
June 30, | 2018 vs. 2017 | ||||||||||||||||||||||||
(in thousands) | 2018 | 2017 | Increase (Decrease) | ||||||||||||||||||||||
Average Number of Customers | OK | KS | TX | Total | OK | KS | TX | Total | OK | KS | TX | Total | |||||||||||||
Residential | 801 | 588 | 624 | 2,013 | 796 | 587 | 618 | 2,001 | 5 | 1 | 6 | 12 | |||||||||||||
Commercial and industrial | 74 | 50 | 35 | 159 | 74 | 50 | 35 | 159 | — | — | — | — | |||||||||||||
Wholesale and public authority | — | — | 3 | 3 | — | — | 3 | 3 | — | — | — | — | |||||||||||||
Transportation | 5 | 6 | 1 | 12 | 5 | 6 | 1 | 12 | — | — | — | — | |||||||||||||
Total customers | 880 | 644 | 663 | 2,187 | 875 | 643 | 657 | 2,175 | 5 | 1 | 6 | 12 |
Three Months Ended | Six Months Ended | |||||||||||
June 30, | June 30, | |||||||||||
Volumes (MMcf) | 2018 | 2017 | 2018 | 2017 | ||||||||
Natural gas sales | ||||||||||||
Residential | 15,605 | 11,704 | 76,590 | 55,891 | ||||||||
Commercial and industrial | 5,881 | 4,895 | 23,871 | 17,776 | ||||||||
Wholesale and public authority | 355 | 334 | 1,222 | 994 | ||||||||
Total sales volumes delivered | 21,841 | 16,933 | 101,683 | 74,661 | ||||||||
Transportation | 51,770 | 49,087 | 116,686 | 110,177 | ||||||||
Total volumes delivered | 73,611 | 66,020 | 218,369 | 184,838 |
Three Months Ended | |||||||||||||||||||||
June 30, | |||||||||||||||||||||
2018 | 2017 | 2018 vs. 2017 | 2018 | 2017 | |||||||||||||||||
Heating Degree Days | Actual | Normal | Actual | Normal | Actual Variance | Actual as a percent of Normal | |||||||||||||||
Oklahoma | 337 | 191 | 182 | 191 | 85 | % | 176 | % | 95 | % | |||||||||||
Kansas | 486 | 419 | 345 | 419 | 41 | % | 116 | % | 82 | % | |||||||||||
Texas | 35 | 54 | 29 | 53 | 21 | % | 65 | % | 55 | % |
Six Months Ended | |||||||||||||||||||||
June 30, | |||||||||||||||||||||
2018 | 2017 | 2018 vs. 2017 | 2018 | 2017 | |||||||||||||||||
Heating Degree Days | Actual | Normal | Actual | Normal | Actual Variance | Actual as a percent of Normal | |||||||||||||||
Oklahoma | 2,207 | 1,966 | 1,574 | 1,966 | 40 | % | 112 | % | 80 | % | |||||||||||
Kansas | 2,975 | 2,947 | 2,331 | 2,922 | 28 | % | 101 | % | 80 | % | |||||||||||
Texas | 938 | 1,062 | 658 | 1,062 | 43 | % | 88 | % | 62 | % |
• | 10-year weighted average HDDs as of December 31, 2014, for years 2005-2014, as calculated using 11 weather stations across Oklahoma and weighted on average customer count for Oklahoma; |
• | 30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using 4 weather stations across Kansas and weighted on HDDs by weather station and customers for Kansas; and |
• | 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. |
• | 11 weather stations and customers by month for Oklahoma; |
• | 4 weather stations and customers by month for Kansas; and |
• | 9 weather stations and natural gas distribution sales volumes by service area for Texas. |
Rating Agency | Rating | Outlook |
Moody’s | A2 | Negative |
S&P | A | Stable |
Six Months Ended | |||||||||||
June 30, | Variance | ||||||||||
2018 | 2017 | 2018 vs. 2017 | |||||||||
(Millions of dollars) | |||||||||||
Total cash provided by (used in): | |||||||||||
Operating activities | $ | 400.0 | $ | 279.3 | $ | 120.7 | |||||
Investing activities | (175.8 | ) | (154.3 | ) | (21.5 | ) | |||||
Financing activities | (226.0 | ) | (134.6 | ) | (91.4 | ) | |||||
Change in cash and cash equivalents | (1.8 | ) | (9.6 | ) | 7.8 | ||||||
Cash and cash equivalents at beginning of period | 14.4 | 14.7 | (0.3 | ) | |||||||
Cash and cash equivalents at end of period | $ | 12.6 | $ | 5.1 | $ | 7.5 |
• | an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas; |
• | a verification of records for pipelines 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. |
• | the first final rule will address the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation Act and will be called the Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments; |
• | the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering); and |
• | the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering. |
• | our ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our regulated rates; |
• | our ability to manage our operations and maintenance costs; |
• | 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 |
• | competition from alternative forms of energy, including, but not limited to, electricity, solar power, wind power, geothermal energy and biofuels; |
• | conservation and energy storage efforts of our customers; |
• | variations in weather, including seasonal effects on demand, the occurrence of storms and disasters, and climate change; |
• | indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantage compared with competitors; |
• | our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of existing supply, and transportation and storage arrangements that are not replaced with contracts with similar terms and pricing; |
• | the mechanical integrity of facilities operated; |
• | operational hazards and unforeseen operational interruptions; |
• | adverse labor relations; |
• | the effectiveness of our strategies to reduce earnings lag, margin protection strategies and risk mitigation strategies, which may be affected by risks beyond our control such as commodity price volatility and counterparty creditworthiness; |
• | our ability to generate sufficient cash flows to meet all our liquidity needs; |
• | 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; |
• | 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; |
• | impact of potential impairment charges; |
• | volatility and changes in markets for natural gas; |
• | 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; |
• | changes in existing or the addition of new environmental, safety, tax and other laws to which we and our subsidiaries are subject; |
• | the uncertainty of estimates, including accruals and costs of environmental remediation; |
• | advances in technology; |
• | population growth rates and changes in the demographic patterns of the markets we serve; |
• | acts of nature and the potential effects of threatened or actual terrorism and war; |
• | cyber attacks 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; |
• | the sufficiency of insurance coverage to cover losses; |
• | the effects of our strategies to reduce tax payments; |
• | the effects of litigation and regulatory investigations, proceedings, including our rate cases, or inquiries and the requirements of our regulators as a result of the Tax Cuts and Jobs Act of 2017; |
• | changes in accounting standards; |
• | changes in corporate governance standards; |
• | discovery of material weaknesses in our internal controls; |
• | our ability to comply with all covenants in our indentures 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; |
• | 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; |
• | the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture; |
• | 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. |
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ITEM 4. | CONTROLS AND PROCEDURES |
ITEM 1. | LEGAL PROCEEDINGS |
ITEM 1A. | RISK FACTORS |
ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
ITEM 3. | DEFAULTS UPON SENIOR SECURITIES |
ITEM 4. | MINE SAFETY DISCLOSURES |
ITEM 5. | OTHER INFORMATION |
ITEM 6. | EXHIBITS |
Exhibit No. | Exhibit Description | |
3.1 | ||
3.2 | ||
10.1 | ||
31.1 | ||
31.2 | ||
32.1 | ||
32.2 |
101.INS | XBRL Instance Document. | |
101.SCH | XBRL Schema Document. | |
101.CAL | XBRL Calculation Linkbase Document. | |
101.LAB | XBRL Label Linkbase Document. | |
101. PRE | XBRL Presentation Linkbase Document. | |
101.DEF | XBRL Extension Definition Linkbase Document. |
Date: August 1, 2018 | ONE Gas, Inc. | |
Registrant | ||
By: | /s/ Curtis L. Dinan | |
Curtis L. Dinan | ||
Senior Vice President and | ||
Chief Financial Officer | ||
(Principal Financial Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Pierce H. Norton II | |
Pierce H. Norton II | |
Chief Executive Officer |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Curtis L. Dinan | |
Curtis L. Dinan | |
Chief Financial Officer |
(1) | the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
(1) | the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
Document And Entity Information - shares |
6 Months Ended | |
---|---|---|
Jun. 30, 2018 |
Jul. 24, 2018 |
|
Document Information [Line Items] | ||
Entity Registrant Name | ONE Gas, Inc. | |
Entity Central Index Key | 0001587732 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 52,517,758 | |
Document Fiscal Year Focus | 2018 | |
Document Fiscal Period Focus | Q2 | |
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2018 |
STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Gross Margin | ||||
Revenues from contracts with customers | $ 291,168 | $ 274,033 | $ 926,405 | $ 810,193 |
Other revenue | 1,353 | 5,656 | 4,580 | 19,904 |
Regulated Operating Revenue | 292,521 | 279,689 | 930,985 | 830,097 |
Cost of natural gas | 94,159 | 82,572 | 444,578 | 345,726 |
Net margin | 198,362 | 197,117 | 486,407 | 484,371 |
Operating expenses | ||||
Operations and maintenance | 102,995 | 96,928 | 205,660 | 201,972 |
Depreciation and amortization | 39,757 | 37,851 | 78,647 | 74,870 |
General taxes | 14,567 | 13,973 | 30,767 | 29,719 |
Total operating expenses | 157,319 | 148,752 | 315,074 | 306,561 |
Operating income | 41,043 | 48,365 | 171,333 | 177,810 |
Other expense, net | (2,194) | (3,900) | (4,358) | (7,307) |
Interest expense, net | (12,003) | (11,305) | (24,355) | (22,786) |
Income before income taxes | 26,846 | 33,160 | 142,620 | 147,717 |
Income taxes | (6,427) | (12,537) | (31,366) | (50,638) |
Net income | $ 20,419 | $ 20,623 | $ 111,254 | $ 97,079 |
Earnings per share | ||||
Basic | $ 0.39 | $ 0.39 | $ 2.11 | $ 1.85 |
Diluted | $ 0.39 | $ 0.39 | $ 2.10 | $ 1.83 |
Average shares (thousands) | ||||
Basic | 52,692 | 52,553 | 52,648 | 52,565 |
Diluted | 52,899 | 52,969 | 52,898 | 53,012 |
Dividends declared per share of stock | $ 0.46 | $ 0.42 | $ 0.92 | $ 0.84 |
STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
STATEMENTS OF COMPREHENSIVE INCOME Parenthetical [Abstract] | ||||
Pension and other postemployment benefit plans, tax | $ (68) | $ (81) | $ (419) | $ (161) |
STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Net income | $ 20,419 | $ 20,623 | $ 111,254 | $ 97,079 |
Other comprehensive income (loss), net of tax | ||||
Change in pension and postemployment benefit plan liability, net of tax of $(68), $(81), (419) and (161), respectively | 203 | 129 | 123 | 258 |
Other comprehensive income, net of tax | 203 | 129 | 123 | 258 |
Comprehensive income | $ 20,622 | $ 20,752 | $ 111,377 | $ 97,337 |
BALANCE SHEETS BALANCE SHEETS Parenthetical - USD ($) $ in Thousands |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Common stock, par value per share | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 250,000,000 | 250,000,000 |
Common stock, shares issued | 52,598,005 | 52,598,005 |
Common stock, shares outstanding | 52,516,828 | 52,312,516 |
Treasury stock, shares | 81,177 | 285,489 |
Debt issuance costs | $ 7,614 | $ 8,033 |
STATEMENT OF CHANGES IN EQUITY - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands |
Total |
Common Stock [Member] |
Paid-in Capital [Member] |
Retained Earnings [Member] |
Treasury Stock [Member] |
Accumulated Other Comprehensive Income (Loss) [Member] |
---|---|---|---|---|---|---|
Shares issued, beginning balance at Dec. 31, 2017 | 52,598,005 | 52,598,005 | ||||
Equity, beginning balance at Dec. 31, 2017 | $ 1,960,209 | $ 526 | $ 1,737,551 | $ 246,121 | $ (18,496) | $ (5,493) |
Net income | 111,254 | 0 | 0 | 111,254 | 0 | 0 |
Other comprehensive income | 123 | $ 0 | 0 | 0 | 123 | |
Common stock issued, shares | 0 | |||||
Common stock issued, value | (970) | $ 0 | (14,207) | 0 | 13,237 | 0 |
Common stock dividends - $0.92 per share | $ (48,272) | $ 0 | 451 | (48,723) | 0 | 0 |
Shares issued, ending balance at Jun. 30, 2018 | 52,598,005 | 52,598,005 | ||||
Equity, ending balance at Jun. 30, 2018 | $ 2,022,344 | $ 526 | $ 1,723,795 | $ 308,652 | $ (5,259) | $ (5,370) |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes) |
6 Months Ended | ||||
---|---|---|---|---|---|
Jun. 30, 2018 | |||||
Significant Accounting Policies [Line Items] | |||||
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 2017 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 the Consolidated Financial Statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2018, 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 2 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We 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. In 2017, we formed a wholly-owned captive insurance company in the state of Oklahoma to provide insurance to our divisions. 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 revenues and expenses 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, provision for doubtful accounts, 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 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 to us. Segments - 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 those described in Note 1 of our Notes to the Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and six months ended June 30, 2018, and 2017, we had no single external customer from which we received 10 percent or more of our gross revenues. Recently Issued Accounting Standards Update - In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118,” which updates the FASB’s Accounting Standards Codification to reflect the guidance in SAB 118, which adds Section EE, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” to SAB Topic 5, “Miscellaneous Accounting.” SAB 118 also provides guidance on applying ASC 740, Income Taxes, if the accounting for certain income tax effects of the Tax Cuts and Jobs Act of 2017 is incomplete when the financial statements are issued for a reporting period. See Note 10 for additional discussion regarding SAB 118. In February 2018, the FASB issued ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” which allows a reclassification from accumulated other comprehensive income (loss) to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted. We are currently assessing the timing and impacts of adopting this standard, but do not expect a material impact to our consolidated financial statements. In March 2017, 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 of 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 for GAAP, when applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate regulated entities. We adopted this guidance in the first quarter of 2018. The presentation changes required for net periodic benefit costs did not impact previously reported net income; however, the reclassification of the other components of benefits costs resulted in an increase in operating income and an increase in other expenses of $2.4 million and $4.3 million for the three months ended June 30, 2018 and 2017, respectively, and an increase in operating income and other expenses of $4.1 million and $8.6 million for the six months ended June 30, 2018 and 2017, respectively. We elected the practical expedient to use the retroactive presentation of the amounts disclosed for the various components of net benefit cost in our Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we updated our information 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 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 early adoption is permitted for fiscal years beginning after December 15, 2018. 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 2020. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements. A modified retrospective transition approach is required for leases existing at the time of adoption. The FASB has issued multiple practical expedients that may be elected, but must be elected as a package and applied consistently to all leases. These practical expedients allow lessees and lessors to (1) not reassess expired or existing contracts to determine whether they are subject to lease accounting guidance, (2) not reconsider lease classification at transition, and (3) not evaluate previously capitalized initial direct costs under the revised requirements. The FASB has also issued several practical expedients that may be elected separately or in conjunction with the previously mentioned practical expedients. These practical expedients allow (1) lessees to not separate nonlease components from lease components and instead account for each separate lease component and the nonlease components associated with that lease component as a single lease component and (2) lessees and lessors to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets. These expedients are only for leases in place at the transition date and cannot be applied to leases that are modified. At this time, we are evaluating these expedients. In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842)” to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements to provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current lease guidance in Topic 840. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easement and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption. In July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842) Targeted Improvements” which provides entities with an additional transition method in which an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The amendment also provides a practical expedient for lessors. At this time, we are evaluating these expedients. We are continuing to evaluate our population of leases, analyze lease agreements, and hold meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operations and the transition approach we will utilize. While we are currently evaluating the full impact of the standard, we expect to recognize additional assets and liabilities arising from current operating leases to our financial position upon adoption. We will adopt this new guidance 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. We have evaluated all of our sources of revenue to determine the effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We adopted this new guidance in the first quarter 2018, using the modified retrospective method. Our adoption did not result in a cumulative adjustment to our opening retained earnings. Our adoption resulted in a reclassification of certain revenues associated with certain regulatory mechanisms that do not meet the requirements under ASC 606 as revenue from contracts with customers, but will continue to be reflected as other revenues in determining total revenues. The reclassified revenues relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we reflect variations in weather in our rates billed to customers. 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 delivered and simultaneously consumed. The majority of our revenues that meet the requirements under ASC 606 are considered implied contracts, as established by our tariff rates approved by regulatory authorities. Our sources of revenue are disaggregated by natural gas sales (including sales to residential, commercial, industrial, wholesale and public authority customers), transportation revenues, and other utility revenues, which are primarily one-time service fees, that meet the requirements under ASC 606. The reclassification of certain revenues that do not meet the requirements under ASC 606 have been classified as other revenues on the Consolidated Income Statement and in our Notes to Consolidated Financial Statements. Additionally, for our natural gas sales and transportation revenues, our customers receive the benefits of our performance when the commodity is delivered to the customer and the performance obligation is satisfied over time as the customer receives and consumes the natural gas. For our other utility revenues, the performance obligation of one-time services are satisfied at a point in time when services are rendered to the customer. In addition, we use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice. See Note 2 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information. |
REVENUE (Notes) |
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Revenue Recognition, Policy [Policy Text Block] |
The following table sets forth our revenues disaggregated by source for the periods indicated:
Our natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities and includes residential, commercial, industrial, wholesale and public authority customers. For natural gas sales, the customer receives the benefits of our performance when the commodity is received and simultaneously consumed by the customer. The performance obligation is satisfied over time as the customer consumes the natural gas. Our transportation revenues represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities and tariff-based negotiated contracts. The customer receives the benefits of our performance when the commodity is delivered to the customer and the performance obligation is satisfied over time as the customer receives the natural gas. Our miscellaneous revenues from contracts with customers represent implied contracts established by our tariff rates approved by the regulatory authorities and includes miscellaneous service charges with the performance obligation satisfied at a point in time when services are rendered to the customer. Total other revenues consist of revenues associated with regulatory mechanisms that do not meet the requirements under ASC 606 as revenue from contracts with customers, but authorize us to accrue revenues earned based on tariffs approved by the regulatory authorities. Total other revenues primarily reflect our natural gas sales related weather normalization mechanism in Kansas. This mechanism adjusts our revenues earned for the variance between actual and normal HDDs. This mechanism can have either positive (warmer than normal) or negative (colder than normal) effects on revenues. We have elected to use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice for our natural gas sales, transportation revenues and other utility revenues. For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenue upon the delivery of the natural gas commodity or services rendered to customers. The billing cycles for customers do not necessarily coincide with the accounting periods used for financial reporting purposes. Revenue is accrued for natural gas delivered and services rendered to customers, but not yet billed. Accrued unbilled revenue is based on a percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require management's judgment. These factors include customer consumption patterns and the impact of weather on usage. The accrued unbilled natural gas sales revenue at June 30, 2018 and December 31, 2017, were $52.0 million and $138.5 million, respectively. We collect and remit other taxes on behalf of government authorities, and we record these amounts in accrued taxes other than income in our Consolidated Balance Sheets on a net basis. Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. In addition, our cost of natural gas regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Our revenues will fluctuate with the cost of gas that we purchase. |
REGULATORY ASSETS AND LIABILITIES (Notes) |
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Schedule of Regulatory Assets and Liabilities |
The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities. Regulatory assets on our Consolidated Balance Sheets, as authorized by various regulatory authorities, are probable of recovery. Base rates 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, and we believe that we will be able to recover such costs, consistent with our historical recoveries. |
CREDIT FACILITIES (Notes) |
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Short-term Debt [Text Block] |
The ONE Gas Credit Agreement is a $700 million revolving unsecured credit facility. We are able to request an increase in commitments of up to an additional $500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement 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 June 30, 2018, our total debt-to-capital ratio was 41 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary but may not exceed 270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest factor. The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement. At June 30, 2018, we had $185.0 million of commercial paper with no borrowings and $514.2 million of remaining credit available under the ONE Gas Credit Agreement. |
LONG-TERM DEBT (Notes) |
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Long-term Debt [Text Block] |
We have senior notes consisting of $300 million of 2.07 percent senior notes due in 2019, $300 million of 3.61 percent senior notes due in 2024 and $600 million of 4.658 percent senior notes due in 2044. 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. |
EQUITY (Notes) |
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Stockholders' Equity Note Disclosure [Text Block] |
Dividends Declared - In July 2018, we declared a dividend of $0.46 per share ($1.84 per share on an annualized basis) for shareholders of record as of August 13, 2018, payable September 4, 2018. |
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Notes) |
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Comprehensive Income (Loss) Note [Text Block] |
The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Consolidated Statements of Income for the periods indicated:
(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 9 for additional detail of our net periodic benefit 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 3 for additional disclosures of regulatory assets and liabilities. |
EARNINGS PER SHARE (Notes) |
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Earnings Per Share [Text Block] |
Basic EPS is based on net income and is calculated based upon the daily weighted-average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have not yet been issued as common stock. Diluted EPS includes 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:
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EMPLOYEE BENEFIT PLANS (Notes) |
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EMPLOYEE BENEFIT PLANS |
The following tables set forth the components of net periodic benefit cost for our pension and other postemployment benefit plans for the periods indicated:
(a) Upon adoption of ASU 2017-07 on January 1, 2018, these amounts are recognized as other income (expense) in the Consolidated Statements of Income. See Note 11 for additional detail of our other income (expense).
(a) Upon adoption of ASU 2017-07 on January 1, 2018, these amounts are recognized as other income (expense) in the Consolidated Statements of Income. See Note 11 for additional detail of our other income (expense). 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. Regulatory deferrals related to net periodic benefit cost were not material for the three and six months ended June 30, 2018. Upon adoption of ASU 2017-07 on January 1, 2018, we continue to capitalize all eligible service cost and non-service cost components under the accounting requirements of Topic 980 (Regulated Operations) for rate regulated entities. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset. See Note 3 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information. |
INCOME TAXES (Notes) |
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Income Tax Disclosure |
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. Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date. Tax Reform - In December 2017, the Tax Cuts and Jobs Act of 2017 was signed into law. Substantially all of the provisions of the new law are effective for taxable years beginning after December 31, 2017. The new law includes significant changes to the Code, including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated utilities. The more significant changes that impact us include reductions in the corporate federal statutory income tax rate to 21 percent from 35 percent, and several technical provisions including, among others, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, the continuation of certain rate normalization requirements for accelerated depreciation benefits and the general allowance for the continued deductibility of interest expense. Additionally, the new law limits the utilization of NOLs arising after December 31, 2017, to 80 percent of taxable income with an indefinite carryforward. The staff of the SEC issued guidance in SAB 118 which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete and provides for up to a one-year period in which to complete the required analyses and accounting. We have completed or made a reasonable estimate for the measurement and accounting of the effects of the Tax Cuts and Jobs Act of 2017, which were reflected in our December 31, 2017, consolidated financial statements. We are still analyzing certain aspects of the Tax Cuts and Jobs Act of 2017, refining our calculations and expect additional guidance from the U.S. Department of the Treasury and the Internal Revenue Service. Any additional issued guidance or future actions of our regulators could potentially affect the final determination of the accounting effects arising from the implementation of the Tax Cuts and Jobs Act of 2017. Reductions in our ADIT balances to reflect the reduced corporate income tax rate of 21 percent will result in amounts previously collected from our customers for these deferred income taxes to be refunded to our customers. The Tax Cuts and Jobs Act of 2017 retains the provisions of the Code that stipulate how these excess deferred income taxes are to be refunded, as well as the timing of any such refunds, to customers for certain accelerated tax depreciation benefits. Potential refunds of these and other deferred income taxes will be determined by our regulators. At June 30, 2018, the regulatory liability associated with the remeasurement of our ADIT totaled $521.7 million. We are working with our regulators in Oklahoma, Kansas and Texas to address the impact of the Tax Cuts and Jobs Act of 2017 on our rates. In each state, we have received accounting orders requiring us to refund the remeasurement of our ADIT and to establish a separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35 percent federal statutory income tax rate and the new 21 percent federal statutory income tax rate effective in January 2018. The establishment of this separate regulatory liability associated with the change in tax rates collected in our rates resulted in a reduction to our revenues of $9.2 million and $21.5 million for the three and six months ended June 30, 2018, respectively. The amount, period and timing of the return of these regulatory liabilities to our customers will be determined by the regulators in each of our jurisdictions. |
OTHER INCOME AND OTHER EXPENSE (Notes) |
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Other Income and Other Expense Disclosure [Text Block] |
The following table sets forth the components of other income and other expense for the periods indicated:
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COMMITMENTS AND CONTINGENCIES (Notes) |
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COMMITMENTS AND CONTINGENCIES |
Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and six months ended June 30, 2018 and 2017. We own or retain legal responsibility for certain environmental conditions at 12 former MGP sites in Kansas. These sites contain contaminants generally associated with MGP sites and are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE governs all environmental investigation and remediation work at these sites. The terms of the consent agreement require us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. 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 three 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. In 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. Additional testing and work plan development continued 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 second quarter of 2018, we revised our estimate of the potential costs associated with additional investigation and remediation to be in the range of $5.6 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 an adjustment to the reserve of $1.6 million for this site in the second quarter of 2018, which also increased our regulatory asset pursuant to our AAO in Kansas. 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, the 12 former MGP sites which we own or retain responsibility for certain environmental conditions. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC. The agreement allows Kansas Gas Service to defer and seek recovery of costs that are necessary for investigation and remediation at the 12 former MGP sites incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved 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 time future investigation and remediation work, 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 issued an order approving the settlement agreement in November 2017. A regulatory asset of approximately $5.9 million was recorded for estimated costs that have been accrued at January 1, 2017. Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and six months ended June 30, 2018 and 2017. A number of environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows. We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and those costs may adversely affect our financial condition, results of operations and cash flows. We do not expect expenditures for these matters to have a material adverse effect on our financial condition, results of operations or cash flows. Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act was signed into law. The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and the Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following:
In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines. The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal. The GPAC has met five times since January 2017 to review public comments and make recommendations to PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering. The next GPAC meeting, scheduled for September 2018, will focus on gas gathering. In addition to reviewing public and committee comments, PHMSA announced they will split this NPRM into three separate final rulemakings:
A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas transmission and gathering pipelines. The timing of each final rule being published is unknown, but the first and second final rules are expected to be published during 2019. The potential capital and operating expenditures associated with compliance with the proposed rules are currently being evaluated and could be significant depending on the final regulations. 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. |
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Notes) |
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Fair Value Disclosures |
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 require 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. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
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 - 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:
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 June 30, 2018, we held purchased natural gas call options for the heating season ending March 31, 2019, with total notional amounts of 15.1 Bcf, for which we paid premiums of $3.6 million, and had a fair value of $3.8 million. At December 31, 2017, we held purchased natural gas call options for the heating season ended March 31, 2018, with total notional amounts of 14.1 Bcf, for which we paid premiums of $5.5 million, and had a fair value of $1.1 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 contracts are included in, and recoverable through, the purchased-gas cost adjustment mechanisms. Additionally, changes in fair value associated with these contracts are deferred as part of our unrecovered purchased-gas costs in our 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. There were no transfers between levels for the three and six months ended June 30, 2018 and 2017. 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. Short-term notes payable and commercial paper are 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 billion at both June 30, 2018 and December 31, 2017. The estimated fair value of our long-term debt, including current maturities, was $1.2 billion and 1.3 billion at June 30, 2018 and December 31, 2017, respectively. The estimated fair value of our Senior Notes at June 30, 2018 and December 31, 2017, was determined using quoted market prices, and are classified as Level 2. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) |
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Significant Accounting Policies [Line Items] | |
Use of Estimates | 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 revenues and expenses 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, provision for doubtful accounts, 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 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 to us. |
Segments | Segments - 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 those described in Note 1 of our Notes to the Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and six months ended June 30, 2018, and 2017, we had no single external customer from which we received 10 percent or more of our gross revenues. |
Recently Issued Accounting Standards Update | Recently Issued Accounting Standards Update - In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118,” which updates the FASB’s Accounting Standards Codification to reflect the guidance in SAB 118, which adds Section EE, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” to SAB Topic 5, “Miscellaneous Accounting.” SAB 118 also provides guidance on applying ASC 740, Income Taxes, if the accounting for certain income tax effects of the Tax Cuts and Jobs Act of 2017 is incomplete when the financial statements are issued for a reporting period. See Note 10 for additional discussion regarding SAB 118. In February 2018, the FASB issued ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” which allows a reclassification from accumulated other comprehensive income (loss) to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted. We are currently assessing the timing and impacts of adopting this standard, but do not expect a material impact to our consolidated financial statements. In March 2017, 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 of 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 for GAAP, when applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate regulated entities. We adopted this guidance in the first quarter of 2018. The presentation changes required for net periodic benefit costs did not impact previously reported net income; however, the reclassification of the other components of benefits costs resulted in an increase in operating income and an increase in other expenses of $2.4 million and $4.3 million for the three months ended June 30, 2018 and 2017, respectively, and an increase in operating income and other expenses of $4.1 million and $8.6 million for the six months ended June 30, 2018 and 2017, respectively. We elected the practical expedient to use the retroactive presentation of the amounts disclosed for the various components of net benefit cost in our Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we updated our information 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 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 early adoption is permitted for fiscal years beginning after December 15, 2018. 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 2020. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements. A modified retrospective transition approach is required for leases existing at the time of adoption. The FASB has issued multiple practical expedients that may be elected, but must be elected as a package and applied consistently to all leases. These practical expedients allow lessees and lessors to (1) not reassess expired or existing contracts to determine whether they are subject to lease accounting guidance, (2) not reconsider lease classification at transition, and (3) not evaluate previously capitalized initial direct costs under the revised requirements. The FASB has also issued several practical expedients that may be elected separately or in conjunction with the previously mentioned practical expedients. These practical expedients allow (1) lessees to not separate nonlease components from lease components and instead account for each separate lease component and the nonlease components associated with that lease component as a single lease component and (2) lessees and lessors to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets. These expedients are only for leases in place at the transition date and cannot be applied to leases that are modified. At this time, we are evaluating these expedients. In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842)” to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements to provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current lease guidance in Topic 840. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easement and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption. In July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842) Targeted Improvements” which provides entities with an additional transition method in which an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The amendment also provides a practical expedient for lessors. At this time, we are evaluating these expedients. We are continuing to evaluate our population of leases, analyze lease agreements, and hold meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operations and the transition approach we will utilize. While we are currently evaluating the full impact of the standard, we expect to recognize additional assets and liabilities arising from current operating leases to our financial position upon adoption. We will adopt this new guidance 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. We have evaluated all of our sources of revenue to determine the effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We adopted this new guidance in the first quarter 2018, using the modified retrospective method. Our adoption did not result in a cumulative adjustment to our opening retained earnings. Our adoption resulted in a reclassification of certain revenues associated with certain regulatory mechanisms that do not meet the requirements under ASC 606 as revenue from contracts with customers, but will continue to be reflected as other revenues in determining total revenues. The reclassified revenues relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we reflect variations in weather in our rates billed to customers. 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 delivered and simultaneously consumed. The majority of our revenues that meet the requirements under ASC 606 are considered implied contracts, as established by our tariff rates approved by regulatory authorities. Our sources of revenue are disaggregated by natural gas sales (including sales to residential, commercial, industrial, wholesale and public authority customers), transportation revenues, and other utility revenues, which are primarily one-time service fees, that meet the requirements under ASC 606. The reclassification of certain revenues that do not meet the requirements under ASC 606 have been classified as other revenues on the Consolidated Income Statement and in our Notes to Consolidated Financial Statements. Additionally, for our natural gas sales and transportation revenues, our customers receive the benefits of our performance when the commodity is delivered to the customer and the performance obligation is satisfied over time as the customer receives and consumes the natural gas. For our other utility revenues, the performance obligation of one-time services are satisfied at a point in time when services are rendered to the customer. In addition, we use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice. See Note 2 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information. |
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Policies) |
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Derivatives and Fair Value Measurement [Abstract] | |||||||||||||||||||||||||||||||
Derivatives | 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 require 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. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
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. |
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Fair Value Measurement | Determining Fair Value - 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:
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. |
REVENUE (Tables) |
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Revenues Disaggregated by Source [Table] | The following table sets forth our revenues disaggregated by source for the periods indicated:
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REGULATORY ASSETS AND LIABILITIES (Tables) |
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SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SCHEDULE OF REGULATED ASSETS AND LIABILITIES | The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities. |
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables) |
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Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Consolidated Statements of Income for the periods indicated:
(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 9 for additional detail of our net periodic benefit 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 3 for additional disclosures of regulatory assets and liabilities. |
EARNINGS PER SHARE (Tables) |
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Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:
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EMPLOYEE BENEFIT PLANS (Tables) |
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Employee Benefit Plans [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | The following tables set forth the components of net periodic benefit cost for our pension and other postemployment benefit plans for the periods indicated:
(a) Upon adoption of ASU 2017-07 on January 1, 2018, these amounts are recognized as other income (expense) in the Consolidated Statements of Income. See Note 11 for additional detail of our other income (expense).
(a) Upon adoption of ASU 2017-07 on January 1, 2018, these amounts are recognized as other income (expense) in the Consolidated Statements of Income. See Note 11 for additional detail of our other income (expense). |
OTHER INCOME AND OTHER EXPENSE (Tables) |
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Other Income and Other Expense Disclosure | The following table sets forth the components of other income and other expense for the periods indicated:
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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Thousands, number in Millions |
3 Months Ended | 6 Months Ended | ||
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Jun. 30, 2018
USD ($)
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Jun. 30, 2017
USD ($)
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Jun. 30, 2018
USD ($)
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Jun. 30, 2017
USD ($)
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Significant Accounting Policies [Line Items] | ||||
Other Nonoperating Income (Expense) | $ (2,194) | $ (3,900) | $ (4,358) | $ (7,307) |
Number of natural gas distribution services customers | 2 | 2 | ||
Segment Reporting, Disclosure of Major Customers | 0 | 0 | 0 | 0 |
REVENUE (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | |||
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Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
Dec. 31, 2017 |
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Unbilled Receivables, Current | $ 52,000 | $ 52,000 | $ 138,500 | ||
Regulated Operating Revenue, Gas | 291,168 | $ 274,033 | 926,405 | $ 810,193 | |
Regulated Operating Revenue, Other | 1,353 | 5,656 | 4,580 | 19,904 | |
Regulated Operating Revenue | 292,521 | 279,689 | 930,985 | 830,097 | |
Natural gas sales to customers [Member] | |||||
Regulated Operating Revenue, Gas | 261,347 | 247,494 | 856,273 | 747,663 | |
Transportation revenues [Member] | |||||
Regulated Operating Revenue, Gas | 24,062 | 21,343 | 57,605 | 51,549 | |
Miscellaneous revenues [Member] | |||||
Regulated Operating Revenue, Gas | 5,759 | 5,196 | 12,527 | 10,981 | |
Other revenues - natural gas sales related [Member] | |||||
Other revenues - natural gas sales related | (1,108) | 3,377 | (78) | 15,540 | |
Other revenues [Member] | |||||
Regulated Operating Revenue, Other | $ 2,461 | $ 2,279 | $ 4,658 | $ 4,364 |
CREDIT FACILITIES (Details) $ in Thousands |
6 Months Ended | |
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Jun. 30, 2018
USD ($)
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Dec. 31, 2017
USD ($)
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Short-term Debt [Line Items] | ||
Line of Credit Facility Option to Increase Borrowing Capacity | $ 500,000 | |
Line of Credit Facility, Expiration Date | Oct. 01, 2022 | |
Ratio of Indebtedness to Net Capital | 0.41 | |
Commercial paper maximum borrowing capacity | $ 700,000 | |
Commercial Paper | 185,000 | $ 357,215 |
Short-term Debt | 0 | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 514,200 | |
Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Debt Instrument, Covenant Description | 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. |
LONG-TERM DEBT (Details) $ in Millions |
6 Months Ended |
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Jun. 30, 2018
USD ($)
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Note Payable Due 2019 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Covenant Description | 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. |
Long-term Debt, Gross | $ 300 |
Debt Instrument, Interest Rate, Stated Percentage | 2.07% |
Note Payable Due 2024 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Covenant Description | 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. |
Long-term Debt, Gross | $ 300 |
Debt Instrument, Interest Rate, Stated Percentage | 3.61% |
Notes Payable Due 2044 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Covenant Description | 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. |
Long-term Debt, Gross | $ 600 |
Debt Instrument, Interest Rate, Stated Percentage | 4.658% |
EQUITY (Details) - Subsequent Event [Member] |
3 Months Ended |
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Sep. 30, 2018
$ / shares
| |
Common Stock, Dividends, Per Share, Declared | $ 0.46 |
Common Stock, Dividends, Declared, Annualized Basis | $ 1.84 |
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
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Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
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Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Amortization of net loss | $ 10,950 | $ 10,648 | $ 21,900 | $ 21,296 |
Amortization of unrecognized prior service cost | (1,142) | (1,149) | (2,284) | (2,298) |
Reclassification adjustment, before tax and regulatory adjustments | 9,808 | 9,499 | 19,616 | 18,998 |
Regulatory adjustments | (9,537) | (9,289) | (19,074) | (18,579) |
Reclassification adjustment, before tax | 271 | 210 | 542 | 419 |
Reclassification adjustment, Tax | (68) | (81) | (419) | (161) |
Reclassification adjustment, net of tax | $ 203 | $ 129 | $ 123 | $ 258 |
EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands |
3 Months Ended | 6 Months Ended | ||
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Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
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Basic EPS Calculation | ||||
Net income available for common stock | $ 20,419 | $ 20,623 | $ 111,254 | $ 97,079 |
Weighted Average Number of Shares Outstanding, Basic | 52,692 | 52,553 | 52,648 | 52,565 |
Earnings Per Share, Basic | $ 0.39 | $ 0.39 | $ 2.11 | $ 1.85 |
Diluted EPS Calculation | ||||
Net income available for common stock | $ 20,419 | $ 20,623 | $ 111,254 | $ 97,079 |
Effect of dilutive securities on income | $ 0 | $ 0 | $ 0 | $ 0 |
Effect of dilutive securities on shares | 207 | 416 | 250 | 447 |
Weighted Average Number of Shares Outstanding, Diluted | 52,899 | 52,969 | 52,898 | 53,012 |
Earnings Per Share, Diluted | $ 0.39 | $ 0.39 | $ 2.10 | $ 1.83 |
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
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Components of net periodic benefit cost: | ||||
Amortization of unrecognized prior service cost | $ 1,142 | $ 1,149 | $ 2,284 | $ 2,298 |
Amortization of net loss | (10,950) | (10,648) | (21,900) | (21,296) |
ONE Gas Pension Plans [Member] | ||||
Components of net periodic benefit cost: | ||||
Service cost | 3,230 | 3,044 | 6,460 | 6,088 |
Interest cost | 9,200 | 10,113 | 18,400 | 20,226 |
Expected return on assets | (15,145) | (14,624) | (30,290) | (29,248) |
Amortization of net loss | 9,978 | 9,027 | 19,956 | 18,054 |
Net periodic benefit cost | 7,263 | 7,560 | 14,526 | 15,120 |
ONE Gas Postretirement Benefit Plans [Member] | ||||
Components of net periodic benefit cost: | ||||
Service cost | 589 | 627 | 1,178 | 1,254 |
Interest cost | 2,279 | 2,472 | 4,558 | 4,944 |
Expected return on assets | (3,571) | (3,147) | (7,142) | (6,294) |
Amortization of unrecognized prior service cost | (1,142) | (1,149) | (2,284) | (2,298) |
Amortization of net loss | 972 | 1,621 | 1,944 | 3,242 |
Net periodic benefit cost | $ (873) | $ 424 | $ (1,746) | $ 848 |
INCOME TAXES (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | 12 Months Ended |
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Jun. 30, 2018 |
Jun. 30, 2018 |
Dec. 31, 2017 |
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Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | |
NOL Limitation | 80.00% | ||
Regulatory Liability, Noncurrent | $ 521,717 | $ 521,717 | $ 519,421 |
Regulatory Liability, Current | 47,867 | 47,867 | 9,438 |
Reduction to revenues due to the change in tax rates collected in our rates | 9,200 | 21,500 | |
Federal income tax rate changes [Member] | |||
Regulatory Liability, Noncurrent | 521,717 | 521,717 | 519,421 |
Regulatory Liability, Current | $ 16,183 | $ 16,183 | $ 0 |
OTHER INCOME AND OTHER EXPENSE (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Other, net | $ (2,194) | $ (3,900) | $ (4,358) | $ (7,307) |
Net periodic cost other than service cost [Member] | ||||
Other, net | (2,403) | (4,313) | (4,137) | (8,626) |
Other, net [Member] | ||||
Other, net | $ 209 | $ 413 | $ (221) | $ 1,319 |
COMMITMENTS AND CONTINGENCIES (Details) $ in Millions |
3 Months Ended | 12 Months Ended | |
---|---|---|---|
Jun. 30, 2018 |
Dec. 31, 2017
USD ($)
|
Dec. 31, 2016 |
|
Commitments and Contingencies [Line Items] | |||
Number Of Former Manufactured Gas Sites Where We Own Or Retain Legal Responsibility For Environmental Conditions | 12 | ||
AAO associated with MGP costs requested amount, cap | $ 15.0 | ||
Regulatory asset expected to be recorded for MGP costs accrued at January 1, 2017 | $ 5.9 | ||
Number of sites where we have completed or addressed removal of the source of soil contamination according to plans approved by KDHE. | 11 | ||
Number of sites with ongoing groundwater monitoring | 8 | ||
Number of sites where regulatory closure has been achieved | 3 | ||
Environmental Reserve Estimate Range, Low | 5.6 | 4 | |
Environmental Reserve Estimate Range, High | 7 | 7 | |
Environmental Reserve Estimate, Actual | 1.6 | ||
Percentage yield of high consequence pipeline areas | 30.00% |
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