ONE GAS, INC., 10-Q filed on 10/30/2018
Quarterly Report
v3.10.0.1
Document And Entity Information - shares
9 Months Ended
Sep. 30, 2018
Oct. 23, 2018
Document Information [Line Items]    
Entity Registrant Name ONE Gas, Inc.  
Entity Central Index Key 0001587732  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Large Accelerated Filer  
Entity Common Stock, Shares Outstanding   52,526,346
Document Fiscal Year Focus 2018  
Document Fiscal Period Focus Q3  
Document Type 10-Q  
Amendment Flag false  
Document Period End Date Sep. 30, 2018  
v3.10.0.1
STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
3 Months Ended 9 Months Ended
Sep. 30, 2018
Sep. 30, 2017
Sep. 30, 2018
Sep. 30, 2017
Gross Margin        
Revenues from contracts with customers $ 235,757 $ 244,402 $ 1,162,162 $ 1,054,595
Other revenue 2,523 2,740 7,103 22,644
Regulated Operating Revenue 238,280 247,142 1,169,265 1,077,239
Cost of natural gas 51,256 58,769 495,834 404,495
Net margin 187,024 188,373 673,431 672,744
Operating expenses        
Operations and maintenance 96,443 91,058 302,103 293,030
Depreciation and amortization 40,344 38,423 118,991 113,293
General taxes 13,996 13,799 44,763 43,518
Total operating expenses 150,783 143,280 465,857 449,841
Operating income 36,241 45,093 207,574 222,903
Other expense, net (1,929) (3,715) (6,287) (11,022)
Interest expense, net (12,365) (11,495) (36,720) (34,281)
Income before income taxes 21,947 29,883 164,567 177,600
Income taxes (5,671) (11,086) (37,037) (61,724)
Net income $ 16,276 $ 18,797 $ 127,530 $ 115,876
Earnings per share        
Basic $ 0.31 $ 0.36 $ 2.42 $ 2.21
Diluted $ 0.31 $ 0.36 $ 2.41 $ 2.19
Average shares (thousands)        
Basic 52,736 52,488 52,678 52,539
Diluted 53,112 52,926 52,969 52,984
Dividends declared per share of stock $ 0.46 $ 0.42 $ 1.38 $ 1.26
v3.10.0.1
STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended
Sep. 30, 2018
Sep. 30, 2017
Sep. 30, 2018
Sep. 30, 2017
STATEMENTS OF COMPREHENSIVE INCOME Parenthetical [Abstract]        
Pension and other postemployment benefit plans, tax $ (68) $ (81) $ (419) $ (161)
v3.10.0.1
STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended
Sep. 30, 2018
Sep. 30, 2017
Sep. 30, 2018
Sep. 30, 2017
Net income $ 16,276 $ 18,797 $ 127,530 $ 115,876
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 203 128 326 386
Other comprehensive income, net of tax 203 128 326 386
Comprehensive income $ 16,479 $ 18,925 $ 127,856 $ 116,262
v3.10.0.1
BALANCE SHEETS - USD ($)
$ in Thousands
9 Months Ended
Sep. 30, 2018
Dec. 31, 2017
Document Fiscal Year Focus 2018  
Property, plant and equipment    
Property, plant and equipment $ 5,964,287 $ 5,713,912
Accumulated depreciation and amortization 1,768,381 1,706,327
Net property, plant and equipment 4,195,906 4,007,585
Current assets    
Cash and cash equivalents 12,430 14,413
Accounts receivable, net 132,436 298,768
Materials and supplies 40,363 39,672
Natural gas in storage 126,481 130,154
Regulatory assets 49,039 88,180
Other current assets 13,762 17,807
Total current assets 374,511 588,994
Goodwill and other assets    
Regulatory assets 375,059 405,189
Goodwill 157,953 157,953
Other assets 49,528 47,157
Total goodwill and other assets 582,540 610,299
Total assets 5,152,957 5,206,878
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 at December 31, 2017 526 526
Paid-in Capital 1,725,361 1,737,551
Retained earnings 300,547 246,121
Accumulated other comprehensive income (loss) (5,167) (5,493)
Treasury stock, at cost: 81,177 shares at June 30, 2018 and 285,489 shares at December 31, 2017 (4,643) (18,496)
Total equity 2,016,624 1,960,209
Long-term debt, excluding current maturities and net issuance costs of $7,614 and $8,033, respectively 893,880 1,193,257
Total equity and long-term debt 2,910,504 3,153,466
Long-term Debt, Current Maturities 300,008 8
Current liabilities    
Notes payable 276,000 357,215
Accounts payable 68,332 143,681
Accrued interest 7,867 18,776
Accrued taxes other than income 48,760 41,324
Accrued liabilities 23,968 30,058
Customer deposits 61,569 60,811
Regulatory Liability, Current 41,665 9,438
Other current liabilities 7,858 12,019
Total current liabilities 836,027 673,330
Deferred credits and other liabilities [Abstract]    
Deferred income taxes 634,650 599,945
Regulatory Liability, Noncurrent 521,717 519,421
Employee benefit obligations 155,443 172,938
Other deferred credits 94,616 87,778
Total deferred credits and other liabilities 1,406,426 1,380,082
Commitments and contingencies
Total liabilities and equity $ 5,152,957 5,206,878
Over-recovered purchased-gas costs [Member]    
Current liabilities    
Regulatory Liability, Current   9,434
Deferred credits and other liabilities [Abstract]    
Regulatory Liability, Noncurrent   $ 0
v3.10.0.1
BALANCE SHEETS BALANCE SHEETS Parenthetical - USD ($)
$ in Thousands
Sep. 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
v3.10.0.1
STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
9 Months Ended
Sep. 30, 2018
Sep. 30, 2017
Document Fiscal Year Focus 2018  
Operating activities    
Net income $ 127,530 $ 115,876
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization 118,991 113,293
Deferred income taxes 36,637 61,329
Share-based compensation expense 6,195 6,930
Provision for doubtful accounts 6,758 4,508
Changes in assets and liabilities:    
Accounts receivable 159,574 158,747
Materials and supplies (691) (4,705)
Natural gas in storage 3,673 (32,209)
Asset removal costs (39,195) (37,928)
Accounts payable (63,857) (65,983)
Accrued interest (10,909) (11,112)
Accrued taxes other than income 7,436 2,087
Accrued liabilities (6,090) (4,396)
Customer deposits 758 (1,566)
Regulatory assets and liabilities 100,268 11,448
Other assets and liabilities (10,310) (13,915)
Cash provided by operating activities 436,768 302,404
Investing activities    
Capital expenditures (279,346) (249,057)
Other 0 617
Cash used in investing activities (279,346) (248,440)
Financing activities    
Repayments of notes payable, net (81,215) 29,000
Repurchase of common stock 0 (17,512)
Issuance of common stock 2,390 2,208
Dividends paid (72,432) (65,996)
Tax withholdings related to net share settlements of stock compensation (8,148) (9,455)
Cash used in financing activities (159,405) (61,755)
Change in cash and cash equivalents (1,983) (7,791)
Cash and cash equivalents at beginning of period 14,413 14,663
Cash and cash equivalents at end of period $ 12,430 $ 6,872
v3.10.0.1
STATEMENT OF CHANGES IN EQUITY - 9 months ended Sep. 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 127,530 0 0 127,530 0 0
Other comprehensive income 326 $ 0 0 0   326
Common stock issued, shares   0        
Common stock issued, value 991 $ 0 (12,862) 0 13,853 0
Common stock dividends - $0.92 per share $ (72,432) $ 0 672 (73,104) 0 0
Shares issued, ending balance at Sep. 30, 2018 52,598,005 52,598,005        
Equity, ending balance at Sep. 30, 2018 $ 2,016,624 $ 526 $ 1,725,361 $ 300,547 $ (4,643) $ (5,167)
v3.10.0.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes)
9 Months Ended
Sep. 30, 2018
Significant Accounting Policies [Line Items]  
SIGNIFICANT ACCOUNTING POLICIES
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements also have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 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 nine months ended September 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 nine months ended September 30, 2018, and 2017, we had no single external customer from which we received 10 percent or more of our gross revenues.

Goodwill Impairment Test - We assess our goodwill for impairment at least annually as of July 1. At July 1, 2018, we assessed qualitative factors to determine whether it was more likely than not that the fair value of our reporting unit was less than its carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that no further testing was necessary.

Recently Issued Accounting Standards Update - In August 2018, the FASB issued ASU 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force)”. Under this guidance, a company should defer implementation costs that it incurs if the company would capitalize those same costs under the internal-use software guidance for an arrangement that is a software license. This standard is effective for interim and annual periods in fiscal years beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the timing and impacts of adopting this standard.

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 net periodic benefits costs resulted in an increase in operating income and an increase in other expenses of $2.3 million and $4.3 million for the three months ended September 30, 2018 and 2017, respectively, and an increase in operating income and other expenses of $6.5 million and $12.9 million for the nine months ended September 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, plant and equipment 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. We plan to utilize this package of three expedients.  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. We do not expect to utilize either of 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. We plan to utilize this expedient.
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, results of operations and the transition approach we will utilize. Our population consists primarily of office facilities and information technology leases. While we are currently evaluating the full impact of the standard on our consolidated financial statements and related disclosures, we expect to recognize additional assets and liabilities arising from current operating leases to our consolidated balance sheets upon adoption. We expect to adopt an accounting policy that exempts leases with terms of less than one year from the recognition requirements of ASC Topic 842. We do not expect a material impact to our results of operations. 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 Statements of Income 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.

Property, Plant and Equipment - Accounts payable for construction work in process and asset removal costs decreased by approximately $11.5 million for the nine months ended September 30, 2018, and increased by $2.2 million for the nine months ended September 30, 2017. Such amounts are not included in capital expenditures on our Consolidated Statements of Cash Flows.

See Note 2 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.
v3.10.0.1
REVENUE (Notes)
9 Months Ended
Sep. 30, 2018
Revenue Recognition, Policy [Policy Text Block]
2.
REVENUE
 
The following table sets forth our revenues disaggregated by source for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(Thousands of dollars)
Natural gas sales to customers
 
$
208,945

 
$
218,079

 
$
1,065,218

 
$
965,742

Transportation revenues
 
21,919

 
21,563

 
79,524

 
73,112

Miscellaneous revenues
 
4,893

 
4,760

 
17,420

 
15,741

Total revenues from contracts with customers
 
235,757

 
244,402

 
1,162,162

 
1,054,595

Other revenues - natural gas sales related
 
375

 
570

 
297

 
16,110

Other revenues
 
2,148

 
2,170

 
6,806

 
6,534

Total other revenues
 
2,523

 
2,740

 
7,103

 
22,644

Total revenues
 
$
238,280

 
$
247,142

 
$
1,169,265

 
$
1,077,239



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 September 30, 2018 and December 31, 2017, were $54.7 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; however, any fluctuations in the cost of gas do not impact net margin.
v3.10.0.1
REGULATORY ASSETS AND LIABILITIES (Notes)
9 Months Ended
Sep. 30, 2018
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]  
Schedule of Regulatory Assets and Liabilities
3.
REGULATORY ASSETS AND LIABILITIES

The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
 
 
 
 
September 30, 2018
 
 
 
 
Current
 
Noncurrent
 
Total
 
 
 
 
(Thousands of dollars)
Under-recovered purchased-gas costs
 

 
$
16,727

 
$

 
$
16,727

Pension and postemployment benefit costs
 

 
25,109

 
357,723

 
382,832

Reacquired debt costs
 

 
812

 
6,690

 
7,502

MGP remediation costs
 
 
 

 
7,724

 
7,724

Ad valorem tax
 
 
 
1,029

 

 
1,029

Other
 

 
5,362

 
2,922

 
8,284

Total regulatory assets, net of amortization
 
 
 
49,039

 
375,059

 
424,098

Federal income tax rate changes (a)
 
 
 
(19,447
)
 
(521,717
)
 
(541,164
)
Over-recovered purchased-gas costs
 
 
 
(22,218
)
 

 
(22,218
)
Total regulatory liabilities
 
 
 
(41,665
)
 
(521,717
)
 
(563,382
)
Net regulatory assets (liabilities)
 
 
 
$
7,374

 
$
(146,658
)
 
$
(139,284
)
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.
 
 
 
 
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
)
(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.
v3.10.0.1
CREDIT FACILITIES (Notes)
9 Months Ended
Sep. 30, 2018
Short-term Debt [Line Items]  
Short-term Debt [Text Block]
4.
CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

In October 2018, we exercised a one-year extension on the ONE Gas Credit Agreement. 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 2023, 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 September 30, 2018, our total debt-to-capital ratio was 42 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 September 30, 2018, we had $276.0 million of commercial paper with no borrowings and $423.2 million of remaining credit available under the ONE Gas Credit Agreement.
v3.10.0.1
LONG-TERM DEBT (Notes)
9 Months Ended
Sep. 30, 2018
Long-term Debt, Unclassified [Abstract]  
Long-term Debt [Text Block]
5.
LONG-TERM DEBT

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.
v3.10.0.1
EQUITY (Notes)
9 Months Ended
Sep. 30, 2018
Class of Stock [Line Items]  
Stockholders' Equity Note Disclosure [Text Block]
6.
EQUITY

Dividends Declared - In October 2018, we declared a dividend of $0.46 per share ($1.84 per share on an annualized basis) for shareholders of record as of November 13, 2018, payable December 3, 2018.
v3.10.0.1
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Notes)
9 Months Ended
Sep. 30, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]  
Comprehensive Income (Loss) Note [Text Block]
7.
ACCUMULATED OTHER COMPREHENSIVE INCOME

The following table sets forth the effect of reclassifications from accumulated other comprehensive income in our Consolidated Statements of Income for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
Affected Line Item in the
Details about Accumulated Other
 
September 30,
 
September 30,
 
 Consolidated Statements
Comprehensive Income 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

 
$
32,850

$
31,944

 
 
Amortization of unrecognized prior service cost
 
(1,142
)
(1,149
)
 
(3,426
)
(3,447
)
 
 
 
 
9,808

9,499

 
29,424

28,497

 
 
Regulatory adjustments (b)
 
(9,537
)
(9,290
)
 
(28,611
)
(27,869
)
 
 
 
 
271

209

 
813

628

 
Income before income taxes
 
 
(68
)
(81
)
 
(487
)
(242
)
 
Income tax expense
Total reclassifications for the period
 
$
203

$
128

 
$
326

$
386

 
Net income
(a) These components of accumulated other comprehensive income 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.
v3.10.0.1
EARNINGS PER SHARE (Notes)
9 Months Ended
Sep. 30, 2018
EARNINGS PER SHARE [Line Items]  
Earnings Per Share [Text Block]
8.
EARNINGS PER SHARE

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:
 
Three Months Ended September 30, 2018
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
16,276

 
52,736

 
$
0.31

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
376

 
 

Net income available for common stock and common stock equivalents
$
16,276

 
53,112

 
$
0.31


 
Three Months Ended September 30, 2017
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
18,797

 
52,488

 
$
0.36

Diluted EPS Calculation
 
 
 

 
 

Effect of dilutive securities

 
438

 
 

Net income available for common stock and common stock equivalents
$
18,797

 
52,926

 
$
0.36



 
Nine Months Ended September 30, 2018
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
127,530

 
52,678

 
$
2.42

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
291

 
 

Net income available for common stock and common stock equivalents
$
127,530

 
52,969

 
$
2.41


 
Nine Months Ended September 30, 2017
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
115,876

 
52,539

 
$
2.21

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
445

 
 

Net income available for common stock and common stock equivalents
$
115,876

 
52,984

 
$
2.19

v3.10.0.1
EMPLOYEE BENEFIT PLANS (Notes)
9 Months Ended
Sep. 30, 2018
Employee Benefit Plans [Line Items]  
EMPLOYEE BENEFIT PLANS
9.
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:
 
Pension Benefits
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2018
2017
 
2018
2017
 
(Thousands of dollars)
Components of net periodic benefit cost
 
 
 
 
 
Service cost
$
3,230

$
3,044

 
$
9,690

$
9,132

Interest cost (a)
9,200

10,113

 
27,600

30,339

Expected return on assets (a)
(15,145
)
(14,624
)
 
(45,435
)
(43,872
)
Amortization of net loss (a)
9,978

9,027

 
29,934

27,081

Net periodic benefit cost
$
7,263

$
7,560

 
$
21,789

$
22,680

(a) Since adoption of ASU 2017-07 on January 1, 2018, these amounts, net of any amounts capitalized as a regulatory asset, have been recognized as other income (expense) in the Consolidated Statements of Income. See Note 11 for additional detail of our other income (expense).




 
Other Postemployment Benefits
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2018
2017
 
2018
2017
 
(Thousands of dollars)
Components of net periodic benefit (credit) cost
 
 
 
 
 
Service cost
$
589

$
627

 
$
1,767

$
1,881

Interest cost (a)
2,279

2,472

 
6,837

7,416

Expected return on assets (a)
(3,571
)
(3,147
)
 
(10,713
)
(9,441
)
Amortization of unrecognized prior service cost (a)
(1,142
)
(1,149
)
 
(3,426
)
(3,447
)
Amortization of net loss (a)
972

1,621

 
2,916

4,863

Net periodic benefit (credit) cost
$
(873
)
$
424

 
$
(2,619
)
$
1,272


(a) Since adoption of ASU 2017-07 on January 1, 2018, these amounts, net of any amounts capitalized as a regulatory asset, have been 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 nine months ended September 30, 2018.

Since 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 ASC 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.
v3.10.0.1
INCOME TAXES (Notes)
9 Months Ended
Sep. 30, 2018
Income Tax Disclosure [Abstract]  
Income Tax Disclosure
10.
INCOME TAXES

We use an estimated annual effective tax rate for purposes of determining the income tax provision during interim reporting periods. In calculating our estimated annual effective tax rate, we consider forecasted annual pre-tax income and estimated permanent book versus tax differences, as well as tax credits. Adjustments to the effective tax rate and estimates will occur as information and assumptions change.

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 December 31, 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 September 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 $6.0 million and $27.5 million for the three and nine months ended September 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.
v3.10.0.1
OTHER INCOME AND OTHER EXPENSE (Notes)
9 Months Ended
Sep. 30, 2018
Other Income and Other Expense Disclosure [Text Block]
11.
OTHER INCOME AND OTHER EXPENSE

The following table sets forth the components of other income and other expense for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(Thousands of dollars)
Net periodic benefit cost other than service cost
 
$
(2,336
)
 
$
(4,313
)
 
$
(6,473
)
 
$
(12,939
)
Other, net
 
407

 
598

 
186

 
1,917

Total other income (expense), net
 
$
(1,929
)
 
$
(3,715
)
 
$
(6,287
)
 
$
(11,022
)
v3.10.0.1
COMMITMENTS AND CONTINGENCIES (Notes)
9 Months Ended
Sep. 30, 2018
Commitments and Contingencies [Line Items]  
COMMITMENTS AND CONTINGENCIES
12.
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 nine months ended September 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. 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 in the second quarter of 2018 an adjustment to the reserve of $1.6 million bringing the total to $5.6 million for this site, 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 nine months ended September 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:

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.

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 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:

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.

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.
v3.10.0.1
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Notes)
9 Months Ended
Sep. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]  
Fair Value Disclosures
13.
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it, or if regulatory rulings 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:
 
 
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

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:
Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;
Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and
Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data.

We recognize transfers into and out of the levels as of the end of each reporting period.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.

Derivative Instruments -  At September 30, 2018, we held purchased natural gas call options for the heating season ending March 31, 2019, with total notional amounts of 35.0 Bcf, for which we paid premiums of $7.6 million, and had a fair value of $8.6 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 nine months ended September 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 September 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 September 30, 2018 and December 31, 2017, respectively. The estimated fair value of our Senior Notes at September 30, 2018 and December 31, 2017, was determined using quoted market prices, and are classified as Level 2.
v3.10.0.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
9 Months Ended
Sep. 30, 2018
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 nine months ended September 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 August 2018, the FASB issued ASU 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force)”. Under this guidance, a company should defer implementation costs that it incurs if the company would capitalize those same costs under the internal-use software guidance for an arrangement that is a software license. This standard is effective for interim and annual periods in fiscal years beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the timing and impacts of adopting this standard.

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 net periodic benefits costs resulted in an increase in operating income and an increase in other expenses of $2.3 million and $4.3 million for the three months ended September 30, 2018 and 2017, respectively, and an increase in operating income and other expenses of $6.5 million and $12.9 million for the nine months ended September 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, plant and equipment 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. We plan to utilize this package of three expedients.  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. We do not expect to utilize either of 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. We plan to utilize this expedient.
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, results of operations and the transition approach we will utilize. Our population consists primarily of office facilities and information technology leases. While we are currently evaluating the full impact of the standard on our consolidated financial statements and related disclosures, we expect to recognize additional assets and liabilities arising from current operating leases to our consolidated balance sheets upon adoption. We expect to adopt an accounting policy that exempts leases with terms of less than one year from the recognition requirements of ASC Topic 842. We do not expect a material impact to our results of operations. 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 Statements of Income 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.

Property, Plant and Equipment - Accounts payable for construction work in process and asset removal costs decreased by approximately $11.5 million for the nine months ended September 30, 2018, and increased by $2.2 million for the nine months ended September 30, 2017. Such amounts are not included in capital expenditures on our Consolidated Statements of Cash Flows.

See Note 2 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.
v3.10.0.1
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Policies)
9 Months Ended
Sep. 30, 2018
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:
 
 
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

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.
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:
Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;
Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and
Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data.

We recognize transfers into and out of the levels as of the end of each reporting period.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.
v3.10.0.1
REVENUE (Tables)
9 Months Ended
Sep. 30, 2018
Revenues Disaggregated by Source [Table]
The following table sets forth our revenues disaggregated by source for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(Thousands of dollars)
Natural gas sales to customers
 
$
208,945

 
$
218,079

 
$
1,065,218

 
$
965,742

Transportation revenues
 
21,919

 
21,563

 
79,524

 
73,112

Miscellaneous revenues
 
4,893

 
4,760

 
17,420

 
15,741

Total revenues from contracts with customers
 
235,757

 
244,402

 
1,162,162

 
1,054,595

Other revenues - natural gas sales related
 
375

 
570

 
297

 
16,110

Other revenues
 
2,148

 
2,170

 
6,806

 
6,534

Total other revenues
 
2,523

 
2,740

 
7,103

 
22,644

Total revenues
 
$
238,280

 
$
247,142

 
$
1,169,265

 
$
1,077,239

v3.10.0.1
REGULATORY ASSETS AND LIABILITIES (Tables)
9 Months Ended
Sep. 30, 2018
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:
 
 
 
 
September 30, 2018
 
 
 
 
Current
 
Noncurrent
 
Total
 
 
 
 
(Thousands of dollars)
Under-recovered purchased-gas costs
 

 
$
16,727

 
$

 
$
16,727

Pension and postemployment benefit costs
 

 
25,109

 
357,723

 
382,832

Reacquired debt costs
 

 
812

 
6,690

 
7,502

MGP remediation costs
 
 
 

 
7,724

 
7,724

Ad valorem tax
 
 
 
1,029

 

 
1,029

Other
 

 
5,362

 
2,922

 
8,284

Total regulatory assets, net of amortization
 
 
 
49,039

 
375,059

 
424,098

Federal income tax rate changes (a)
 
 
 
(19,447
)
 
(521,717
)
 
(541,164
)
Over-recovered purchased-gas costs
 
 
 
(22,218
)
 

 
(22,218
)
Total regulatory liabilities
 
 
 
(41,665
)
 
(521,717
)
 
(563,382
)
Net regulatory assets (liabilities)
 
 
 
$
7,374

 
$
(146,658
)
 
$
(139,284
)
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.
 
 
 
 
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
)
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.

v3.10.0.1
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)
9 Months Ended
Sep. 30, 2018
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 in our Consolidated Statements of Income for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
Affected Line Item in the
Details about Accumulated Other
 
September 30,
 
September 30,
 
 Consolidated Statements
Comprehensive Income 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

 
$
32,850

$
31,944

 
 
Amortization of unrecognized prior service cost
 
(1,142
)
(1,149
)
 
(3,426
)
(3,447
)
 
 
 
 
9,808

9,499

 
29,424

28,497

 
 
Regulatory adjustments (b)
 
(9,537
)
(9,290
)
 
(28,611
)
(27,869
)
 
 
 
 
271

209

 
813

628

 
Income before income taxes
 
 
(68
)
(81
)
 
(487
)
(242
)
 
Income tax expense
Total reclassifications for the period
 
$
203

$
128

 
$
326

$
386

 
Net income
(a) These components of accumulated other comprehensive income 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.
v3.10.0.1
EARNINGS PER SHARE (Tables)
9 Months Ended
Sep. 30, 2018
EARNINGS PER SHARE [Line Items]  
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:
 
Three Months Ended September 30, 2018
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
16,276

 
52,736

 
$
0.31

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
376

 
 

Net income available for common stock and common stock equivalents
$
16,276

 
53,112

 
$
0.31


 
Three Months Ended September 30, 2017
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
18,797

 
52,488

 
$
0.36

Diluted EPS Calculation
 
 
 

 
 

Effect of dilutive securities

 
438

 
 

Net income available for common stock and common stock equivalents
$
18,797

 
52,926

 
$
0.36

v3.10.0.1
EMPLOYEE BENEFIT PLANS (Tables)
9 Months Ended
Sep. 30, 2018
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:
 
Pension Benefits
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2018
2017
 
2018
2017
 
(Thousands of dollars)
Components of net periodic benefit cost
 
 
 
 
 
Service cost
$
3,230

$
3,044

 
$
9,690

$
9,132

Interest cost (a)
9,200

10,113

 
27,600

30,339

Expected return on assets (a)
(15,145