Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Public Service Company of Colorado meets the conditions set forth in General Instruction H (1) H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2)H(2) to such Form 10-Q.
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
Except to the extent noted below, Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2017 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:
|
| | | | | | |
| | | Six Months Ended June 30 |
| | | 2018 | | 2017 |
| Federal statutory rate | | 21.0 | % | | 35.0 | % |
| State tax, net of federal tax effect | | 3.7 |
| | 3.0 |
|
| Increases (decreases) in tax from: | |
| |
|
Regulatory differences - ARAM (a) | | (3.2 | ) | | (0.1 | ) |
Regulatory differences - ARAM deferral (b) | | 3.0 |
| | — |
|
| Regulatory differences - other utility plant items | | (1.3 | ) | | (0.9 | ) |
| Tax credits, net of federal income tax expense | | (1.0 | ) | | (0.7 | ) |
| Other, net | | 0.3 |
| | 0.1 |
|
| Effective income tax rate | | 22.5 | % | | 36.4 | % |
| |
(a)
| The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers. |
| |
(b)
| As we receive direction from our regulatory commissions regarding the return of excess deferred taxes (to our customers resulting from the Tax Cuts and Jobs Act |
(TCJA)), the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a corresponding reduction to revenue.
Federal Audits— PSCO is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:
|
| | |
Tax Year(s) | | Expiration |
2009 - 2011 | | December 2018 |
2012 - 2014 | | October 2019 |
2015 | | September 2019 |
2016 | | September 2020 |
In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims and in 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2017 Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. PSCo did not accrue any income tax benefit related to this adjustment. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.
In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy filed a protest with the IRS. As of June 30, 2018, the case has been forwarded to Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2018, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.
Unrecognized Benefits— The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.
A reconciliation of the amount of unrecognized tax benefit is as follows:
|
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2018 | | Dec. 31, 2017 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 4.4 |
| | $ | 4.0 |
|
| Unrecognized tax benefit — Temporary tax positions | | 5.0 |
| | 6.1 |
|
| Total unrecognized tax benefit | | $ | 9.4 |
| | $ | 10.1 |
|
The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
|
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2018 | | Dec. 31, 2017 |
| NOL and tax credit carryforwards | | $ | (4.7 | ) | | $ | (4.0 | ) |
It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and the IRS and state audits resume. As the IRS Appeals progresses and the IRS audit resumes, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $8 million.
The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2018, and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2018 or Dec. 31, 2017.
Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2017 and in Note 5 to the consolidated financial statements to PSCo’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.
Tax Reform — Regulatory Proceedings
The specific impacts of the TCJA on customer rates are subject to regulatory approval. Each of the states in Xcel Energy’s service areas, including Colorado, have opened dockets to address the impacts of the TCJA.
Colorado Natural Gas — In February 2018, the administrative law judge (ALJ) approved PSCo and the Colorado Public Utilities Commission (CPUC) Staff’s TCJA settlement agreement which includes a $20 million reduction to provisional rates effective March 1, 2018. A final true-up would provide customers the full net benefit of the TCJA retroactive to January 2018.
Colorado Electric— In April 2018, PSCo, the CPUC Staff and the Office of Consumer Counsel (OCC) filed a TCJA settlement agreement that recommended a customer refund of $42 million in 2018, with the remainder of $59 million be used to accelerate the amortization of an existing prepaid pension asset. In June 2018, the CPUC approved the customer refund of $42 million, effective June 1, 2018. The CPUC set the decision regarding the remainder of the $59 million for hearing before an ALJ. Revisions to the TCJA settlement will be addressed in a future electric rate case.
Pending Regulatory Proceedings — CPUC
Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years. The request was based on forecast test years (FTY), a 10.0 percent return on equity (ROE) and an equity ratio of 55.25 percent. Interim rates, subject to refund and interest, were to be effective on June 1, 2018.
|
| | | | | | | | | | | | | | | | | | | | |
| Revenue Request (Millions of Dollars) | | 2018 | | 2019 | | 2020 | | 2021 | | Total |
| Revenue request | | $ | 74 |
| | $ | 75 |
| | $ | 60 |
| | $ | 36 |
| | $ | 245 |
|
| Clean Air Clean Jobs Act (CACJA) rider conversion to base rates | | 90 |
| | — |
| | — |
| | — |
| | 90 |
|
| Transmission Cost Adjustment (TCA) rider conversion to base rates | | 43 |
| | — |
| | — |
| | — |
| | 43 |
|
| Total | | $ | 207 |
| | $ | 75 |
| | $ | 60 |
| | $ | 36 |
| | $ | 378 |
|
| | | | | | | | | | | |
| Expected year-end rate base (billions of dollars) | | $ | 6.8 |
| | $ | 7.1 |
| | $ | 7.3 |
| | $ | 7.4 |
| | |
In March 2018, PSCo, CPUC Staff and OCC reached a settlement and filed a motion with the CPUC requesting changes to the procedural schedule and scope of the electric case, which included delaying the implementation of provisional rates from June 2018 to January 2019 and requiring PSCo to file updated test year information for 2019 through 2021 which included the impacts of TCJA. In April 2018, the CPUC denied the motion on procedural grounds and dismissed the electric rate case.
Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years. The request, detailed below, was based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent. |
| | | | | | | | | | | | | | | | |
| Revenue Request (Millions of Dollars) | | 2018 | | 2019 | | 2020 | | Total |
| Revenue request | | $ | 63 |
| | $ | 33 |
| | $ | 43 |
| | $ | 139 |
|
Pipeline System Integrity Adjustment (PSIA) rider conversion to base rates (a) | | — |
| | 94 |
| | — |
| | 94 |
|
| Total | | $ | 63 |
| | $ | 127 |
| | $ | 43 |
| | $ | 233 |
|
| | | | | | | | | |
Expected year-end rate base (billions of dollars) (b) | | $ | 1.5 |
| | $ | 2.3 |
| | $ | 2.4 |
| | |
| |
(a)
| The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. |
| |
(b)
| The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. |
In February 2018, the administrative law judge (ALJ) approved a TCJA settlement agreement between PSCo and the CPUC Staff, which reduced provisional rates by $20 million, based on a preliminary TCJA estimate of $29 million. The settlement remains subject to CPUC approval. The impact of the TCJA will be trued-up later in 2018. Annualized provisional rates of approximately $43 million were effective March 1, 2018.
In May 2018, the ALJ issued an interim recommended decision which would result in a 2018 overall rate increase of approximately $46 million, prior to the impact of the TCJA. The estimated rate increase reflects a 2016 HTY with a 13-month average rate base of $1.6 billion, a ROE of 9.35 percent and an equity ratio of 54.2 percent.
On July 12, 2018, the CPUC deliberated and approved several of the ALJ’s recommendations including application of a 2016 HTY, with a 13-month average rate base, and an ROE of 9.35 percent. The CPUC adjusted the equity ratio to 54.6 percent and provided no return on the prepaid pension and retiree medical asset. With these adjustments the total rate increase, prior to TCJA impacts, would be $47 million.
The estimated impact of the CPUC’s decision is presented below: |
| | | | |
| (Millions of Dollars) | | Estimated Impact of the CPUC’s Decision |
| Filed 2018 revenue request based on a FTY | | $ | 63 |
|
| Impact of the change in test year | | 5 |
|
| PSCo’s deficiency based on a 2016 HTY - year-end rate base | | 68 |
|
| | | |
| Adjustments: | | |
| ROE at 9.35 percent | | (9 | ) |
| Equity ratio of 54.6 percent | | (2 | ) |
| Change in amortization period for certain regulatory assets, including a debt return | | (6 | ) |
| Loss of return on prepaid pension and retiree medical | | (4 | ) |
| Change from 2016 year-end to average rate base | | (5 | ) |
| Other, net | | 5 |
|
| Total adjustments | | (21 | ) |
| | | |
Total rate increase, prior to the TCJA impacts | | $ | 47 |
|
The CPUC is expected to issue its order on the natural gas rate case in the third quarter of 2018. The CPUC is expected to issue a final decision with the impacts of the TCJA, later in 2018.
Provisional rates, subject to refund, were implemented on Jan. 1, 2018. A current liability which represents PSCo’s best estimate of a refund obligation associated with provisional rates was recorded as of June 30, 2018.
PSIA Rider
In June 2018, PSCo filed for an extension to the PSIA rider through 2020. PSCo requested an expedited decision by Nov. 15, 2018. PSCo also requested authorization to roll-in recovery of costs in the current PSIA rider into base rates effective Jan. 1, 2019, if the CPUC rejects the proposed PSIA extension or fails to rule on the request by the end of 2018.
Additionally, PSCo reduced PSIA revenues by approximately $8 million for 2018 for the impact of the TCJA, effective May 1, 2018. PSIA revenues are subject to the CPUC approved PSIA rider true-up process.
| |
6. | Commitments and Contingencies |
Except to the extent noted below and in Note 5 to the consolidated financial statements, the circumstances set forth in Notes 11 and 12 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2017 and in Notes 5 and 6 to PSCo’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.
PPAs
PSCo purchases power from independent power producing entities that own natural gas fueled power plants for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.
PSCo had approximately 1,571 Megawatts (MW) of capacity under long-term PPAs as of June 30, 2018 and Dec. 31, 2017, with entities that have been determined to be variable interest entities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have various expiration dates through 2032.
Environmental Contingencies
Manufactured Gas Plant (MGP), Landfill or Disposal Sites — PSCo is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. PSCo has identified four sites where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities. PSCo anticipates that these investigation or remediation activities will continue through at least 2018. PSCo accrued $2 million as of June 30, 2018 and an immaterial amount as of Dec. 31, 2017, for these sites. There may be insurance recovery and/or recovery from other potentially responsible parties that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers.
Environmental Requirements
Air
Revisions to the National Ambient Air Quality Standard (NAAQS) for Ozone - In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. PSCo meets the 2015 ozone standard in all areas where its generating units operate, except for the Denver Metropolitan Area. PSCo’s retirement of its coal fired plants in the Denver non-attainment area helped Colorado’s plan to mitigate non-attainment. In June 2018, the EPA designated the parts of the Denver Metropolitan Area that currently do not attain the 2008 ozone standards as also not attaining the more stringent 2015 ozone standard. Colorado will continue to consider further reductions that are available in the non-attainment area as it develops plans to meet the ozone standards. The gas plants that operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or implement enhanced emissions monitoring as part of future Colorado state plans.
Legal Contingencies
PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Employment, Tort and Commercial Litigation
Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involved claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so. This claim is substantially similar to the arguments previously raised by DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals. It is uncertain when a decision will be rendered regarding this appeal.
PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.
| |
7. | Borrowings and Other Financing Instruments |
Short-Term Borrowings
PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for PSCo were as follows:
|
| | | | | | | | |
| (Amounts in Millions, Except Interest Rates) | | Three Months Ended June 30, 2019 | | Year Ended Dec. 31, 2018 |
| Borrowing limit | | $ | 250 |
| | $ | 250 |
|
| Amount outstanding at period end | | 50 |
| | — |
|
| Average amount outstanding | | 3 |
| | 25 |
|
| Maximum amount outstanding | | 50 |
| | 156 |
|
| Weighted average interest rate, computed on a daily basis | | 2.41 | % | | 1.93 | % |
| Weighted average interest rate at period end | | 2.41 |
| | N/A |
|
|
| | | | | | | | |
| (Amounts in Millions, Except Interest Rates) | | Three Months Ended June 30, 2018 | | Year Ended Dec. 31, 2017 |
| Borrowing limit | | $ | 250 |
| | $ | 250 |
|
| Amount outstanding at period end | | — |
| | — |
|
| Average amount outstanding | | 60 |
| | — |
|
| Maximum amount outstanding | | 156 |
| | 20 |
|
| Weighted average interest rate, computed on a daily basis | | 1.84 | % | | 0.92 | % |
| Weighted average interest rate at period end | | N/A |
| | N/A |
|
Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool. Commercial paper outstanding for PSCo was as follows:
|
| | | | | | | | |
| (Amounts in Millions, Except Interest Rates) | | Three Months Ended June 30, 2019 | | Year Ended Dec. 31, 2018 |
| Borrowing limit | | $ | 700 |
| | $ | 700 |
|
| Amount outstanding at period end | | 221 |
| | 307 |
|
| Average amount outstanding | | 244 |
| | 55 |
|
| Maximum amount outstanding | | 432 |
| | 309 |
|
| Weighted average interest rate, computed on a daily basis | | 2.65 | % | | 2.28 | % |
| Weighted average interest rate at period end | | 2.59 |
| | 2.95 |
|
|
| | | | | | | | |
| (Amounts in Millions, Except Interest Rates) | | Three Months Ended June 30, 2018 | | Year Ended Dec. 31, 2017 |
| Borrowing limit | | $ | 700 |
| | $ | 700 |
|
| Amount outstanding at period end | | — |
| | — |
|
| Average amount outstanding | | 84 |
| | 54 |
|
| Maximum amount outstanding | | 257 |
| | 268 |
|
| Weighted average interest rate, computed on a daily basis | | 2.17 | % | | 1.08 | % |
| Weighted average interest rate at period end | | N/A |
| | N/A |
|
Letters of Credit— PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2018 and Dec. 31, 2017, thereThere were $4$10 million and $3 million, respectively, of letters of credit outstanding under the credit facility.facility at June 30, 2019 and Dec. 31, 2018. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
At June 30, 2018,2019, PSCo had the following committed credit facility available (in millions of dollars):
| | Credit Facility (a) | Credit Facility (a) | | Drawn (b) | | Available | Credit Facility (a) | | Outstanding (b) | | Available |
| $ | 700 |
| | $ | 4 |
| | $ | 696 |
| 700 |
| | $ | 231 |
| | $ | 469 |
|
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
|
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2019 | | Dec. 31, 2018 |
| NOL and tax credit carryforwards | | $ | (6.1 | ) | | $ | (5.6 | ) |
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $2.6 million and $2.0 million for June 30, 2019 and Dec. 31, 2018, respectively.
As the IRS Appeals and federal audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $8.7 million in the next 12 months.
Payables for interest related to unrecognized tax benefits were not material and no amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2019 or Dec. 31, 2018.
| |
| 7. | Fair Value of Financial Assets and Liabilities |
Fair Value Measurements
The accounting guidance for fair value measurements and disclosures provides a single definition of fair value, hierarchical framework for measuring assets and liabilities and requires certain disclosuresdisclosure about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include the following:include:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset value.
Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options generally utilize observable forward prices and volatilities, as well as observable pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to delivery locations for which pricing is relatively unobservable, or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilitiesinputs on a valuation is evaluated, and may result in Level 3 classification.
Derivative Instruments Fair Value Measurements
PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
At June 30, 2018,2019, accumulated other comprehensive lossesloss related to interest rate derivatives included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.
Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas relatedgas-related instruments, including derivatives. PSCo’s risk management policy allows managementPSCo is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made upcomprised of management personnel not directly involved in the activities governed by this policy.
Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel.
PSCo entersmay enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded inas other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
As of June 30, 2019, PSCo had no income related to the ineffectiveness ofcommodity contracts designated as cash flow hedges for the three and six months ended June 30, 2018 and 2017.hedges.
Additionally, PSCo also enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
The following table details the grossGross notional amounts of commodity forwards and options at June 30, 2018 and Dec. 31, 2017:options:
| | (Amounts in Thousands) (a)(b) | | June 30, 2018 | | Dec. 31, 2017 | |
(Amounts in Millions) (a)(b) | | | June 30, 2019 | | Dec. 31, 2018 |
| Megawatt hours of electricity | | 20,813 |
| | 22,260 |
| | 16.3 |
| | 24.4 |
|
| Million British thermal units of natural gas | | 18,798 |
| | 13,410 |
| | 51.3 |
| | 48.4 |
|
| |
(a) | Amounts are not reflective of net positions in the underlying commodities. |
| |
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The following tables detail the impact of derivative activity duringcredit risk was immaterial to the three months ended June 30, 2018fair value of unsettled commodity derivatives presented in the consolidated balance sheets. PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and 2017 on accumulated other comprehensive loss, regulatory assets and liabilities, and income:non-trading commodity activities.
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, 2018 | |
| | | Pre-Tax Fair Value Losses Recognized During the Period in: | | Pre-Tax Losses Reclassified into Income During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Gains Recognized During the Period in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 402 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | — |
| | $ | — |
| | $ | 402 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 200 |
| (b) |
| Natural gas commodity | | — |
| | (249 | ) | | — |
| | — |
| | — |
| (c) |
| Total | | $ | — |
| | $ | (249 | ) | | $ | — |
| | $ | — |
| | $ | 200 |
| |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2018 | |
| | | Pre-Tax Fair Value Losses Recognized During the Period in: | | Pre-Tax Losses Reclassified into Income During the Period from: | | Pre-Tax (Gains) Losses Recognized During the Period in Income | |
| (Thousands of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 800 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | — |
| | $ | — |
| | $ | 800 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | |
| | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 724 |
| (b) |
| Natural gas commodity | | — |
| | (420 | ) | | — |
| | 2,749 |
| (c) | (1,581 | ) | (c) |
| Total | | $ | — |
| | $ | (420 | ) | | $ | — |
| | $ | 2,749 |
| | $ | (857 | ) | |
At June 30, 2019, six of PSCo’s 10 most significant counterparties for these activities, comprising $33.0 million or 49% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Three of the 10 most significant counterparties, comprising $7.7 million or 11% of this credit exposure, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising $8.4 million or 12% of this credit exposure, had credit quality less than investment grade, based on external analysis. Seven of these significant counterparties are municipal or cooperative electric entities, or other utilities.
Impact of derivative activity:
|
| | | | | | | | |
| | | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
| (Millions of Dollars) | | Accumulated Other
Comprehensive Loss | | Regulatory(Assets) and Liabilities |
| Three Months Ended June 30, 2019 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (1.5 | ) |
| Total | | $ | — |
| | $ | (1.5 | ) |
| | | | | |
| Six Months Ended June 30, 2019 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (1.5 | ) |
| Total | | $ | — |
| | $ | (1.5 | ) |
| | | | | |
| Three Months Ended June 30, 2018 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (0.2 | ) |
| Total | | $ | — |
| | $ | (0.2 | ) |
| | | | | |
| Six Months Ended June 30, 2018 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (0.4 | ) |
| Total | | $ | — |
| | $ | (0.4 | ) |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, 2017 | |
| | | Pre-Tax Fair Value Losses Recognized During the Period in: | | Pre-Tax Losses Reclassified into Income During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Losses Recognized During the Period in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 403 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | — |
| | $ | — |
| | $ | 403 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (192 | ) | (b) |
| Natural gas commodity | | — |
| | (1,621 | ) | | — |
| | — |
| | — |
| (c) |
| Total | | $ | — |
| | $ | (1,621 | ) | | $ | — |
| | $ | — |
| | $ | (192 | ) | |
|
| | | | | | | | | | | | |
| | Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: | | Pre-Tax Gains (Losses) Recognized
During the Period in Income | |
| (Millions of Dollars) | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | |
| Three Months Ended June 30, 2019 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 0.4 |
| (a) | $ | — |
| | $ | — |
| |
| Total | $ | 0.4 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — |
| | $ | — |
| | $ | 3.3 |
| (b) |
| Total | $ | — |
| | $ | — |
| | $ | 3.3 |
| |
| | | | | | | |
| Six Months Ended June 30, 2019 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 0.8 |
| (a) | $ | — |
| | $ | — |
| |
| Total | $ | 0.8 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — |
| | $ | — |
| | $ | 4.7 |
| (b) |
| Natural gas commodity | — |
| | (1.3 | ) | (c) | (2.0 | ) | (c) |
| Total | $ | — |
| | $ | (1.3 | ) | | $ | 2.7 |
| |
| | | | | | | |
| Three Months Ended June 30, 2018 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 0.4 |
| (a) | $ | — |
| | $ | — |
| |
| Total | $ | 0.4 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — |
| | $ | — |
| | $ | 0.2 |
| (b) |
| Total | $ | — |
| | $ | — |
| | $ | 0.2 |
| |
| | | | | | | |
| Six Months Ended June 30, 2018 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 0.8 |
| (a) | $ | — |
| | $ | — |
| |
| Total | $ | 0.8 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — |
| | $ | — |
| | $ | 0.7 |
| (b) |
| Natural gas commodity | — |
| | 2.7 |
| (c) | (1.6 | ) | (c) |
| Total | $ | — |
| | $ | 2.7 |
| | $ | (0.9 | ) | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2017 | |
| | | Pre-Tax Fair Value Losses Recognized During the Period in: | | Pre-Tax Losses Reclassified into Income During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized During the Period in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 801 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | — |
| | $ | — |
| | $ | 801 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 187 |
| (b) |
| Natural gas commodity | | — |
| | (7,008 | ) | | — |
| | 282 |
| (c) | (2,990 | ) | (c) |
| Total | | $ | — |
| | $ | (7,008 | ) | | $ | — |
| | $ | 282 |
| | $ | (2,803 | ) | |
| |
(a) | Amounts are recorded to interest charges. |
| |
(b) | Amounts are recorded to interest charges. Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue as appropriate. |
| |
(c) | CertainAmounts for both the three and six months ended June 30, 2019 included no settlement gain or losses on derivatives are utilizedentered to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three and six months ended June 30, 2018 included no such settlement gains or losses and $1.2 million of such settlement losses, respectively. AmountsRemaining derivative settlement losses for the three and six months ended June 30, 2017 included no settlement gains or losses2019 and $0.9 million of settlement gains, respectively. The remaining derivative settlement gains and losses for the six months ended June 30, 2018 and 2017 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
PSCo had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 20182019 and 2017. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.2018.
Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of derivative liabilities, the impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.
PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.
PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At June 30, 2018, four of PSCo’s 10 most significant counterparties for these activities, comprising $27.6 million or 47 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the 10 most significant counterparties, comprising $12.2 million or 21 percent of this credit exposure, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. The one remaining significant counterparty, comprising $5.2 million or 9 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Nine of these significant counterparties are municipal or cooperative electric entities, or other utilities.
Credit Related Contingent Features—Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheet,sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. At June 30, 20182019 and Dec. 31, 2017,2018, there were no derivative instruments in a material liability position with such underlying contract provisions.provisions with no offsetting positions or posted collateral.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 20182019 and Dec. 31, 2017.2018.
Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at June 30, 2018:basis: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2019 | | Dec. 31, 2018 |
| | | Fair Value | | Fair Value
Total | | Netting (a) | | | | Fair Value | | Fair Value
Total | | Netting (a) | | |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | | Total | | Level 1 | | Level 2 | | Level 3 | | | | Total |
| Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 5.4 |
| | $ | 33.3 |
| | $ | 0.2 |
| | $ | 38.9 |
| | $ | (20.9 | ) | | $ | 18.0 |
| | $ | 2.3 |
| | $ | 65.0 |
| | $ | 0.1 |
| | $ | 67.4 |
| | $ | (28.2 | ) | | $ | 39.2 |
|
| Natural gas commodity | | — |
| | 0.4 |
| | — |
| | 0.4 |
| | — |
| | 0.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
|
| Total current derivative assets | | $ | 5.4 |
| | $ | 33.7 |
| | $ | 0.2 |
| | $ | 39.3 |
| | $ | (20.9 | ) | | 18.4 |
| | $ | 2.3 |
| | $ | 68.4 |
| | $ | 0.1 |
| | $ | 70.8 |
| | $ | (28.2 | ) | | 42.6 |
|
PPAs (b) | | | | | | | | | | | | — |
| | | | | | | | | | | | — |
|
| Current derivative instruments | | | | | | | | | | | | $ | 18.4 |
| | | | | | | | | | | | $ | 42.6 |
|
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 0.2 |
| | $ | 4.6 |
| | $ | — |
| | $ | 4.8 |
| | $ | (2.3 | ) | | $ | 2.5 |
| | $ | — |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.6 |
| | $ | (0.4 | ) | | $ | 1.2 |
|
| Total noncurrent derivative assets | | $ | 0.2 |
| | $ | 4.6 |
| | $ | — |
| | $ | 4.8 |
| | $ | (2.3 | ) | | 2.5 |
| | $ | — |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.6 |
| | $ | (0.4 | ) | | 1.2 |
|
PPAs (b) | | | | | | | | | | | | — |
| | | | | | | | | | | | — |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 2.5 |
| | | | | | | | | | | | $ | 1.2 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2018 |
| | | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | | Total |
| Current derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 332 |
| | $ | 12,812 |
| | $ | 118 |
| | $ | 13,262 |
| | $ | (9,729 | ) | | $ | 3,533 |
|
| Natural gas commodity | | — |
| | 919 |
| | — |
| | 919 |
| | — |
| | 919 |
|
| Total current derivative assets | | $ | 332 |
| | $ | 13,731 |
| | $ | 118 |
| | $ | 14,181 |
| | $ | (9,729 | ) | | 4,452 |
|
PPAs (a) | | | | | | | | | | | | 888 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 5,340 |
|
| Noncurrent derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 1 |
| | $ | 2,715 |
| | $ | — |
| | $ | 2,716 |
| | $ | — |
| | $ | 2,716 |
|
| Total noncurrent derivative assets | | $ | 1 |
| | $ | 2,715 |
| | $ | — |
| | $ | 2,716 |
| | $ | — |
| | 2,716 |
|
PPAs (a) | | | | | | | | | | | | — |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 2,716 |
|
| | | | | June 30, 2018 | | June 30, 2019 | | Dec. 31, 2018 |
| | | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | | | Fair Value | | Fair Value
Total | | Netting (a) | | | | Fair Value | | Fair Value
Total | | Netting (a) | | |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Total | |
| (Millions of Dollars) | | | Level 1 | | Level 2 | | Level 3 | | Fair Value
Total | | Netting (a) | | Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value
Total | | Netting (a) | | Total |
| Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 333 |
| | $ | 12,409 |
| | $ | — |
| | $ | 12,742 |
| | $ | (12,474 | ) | | $ | 268 |
| | $ | 5.5 |
| | $ | 31.4 |
| | $ | — |
| | $ | 36.9 |
| | $ | (27.3 | ) | | $ | 9.6 |
| | $ | 2.4 |
| | $ | 64.2 |
| | $ | — |
| | $ | 66.6 |
| | $ | (34.7 | ) | | $ | 31.9 |
|
| Total current derivative liabilities | | $ | 333 |
| | $ | 12,409 |
| | $ | — |
| | $ | 12,742 |
| | $ | (12,474 | ) | | 268 |
| | $ | 5.5 |
| | $ | 31.4 |
| | $ | — |
| | $ | 36.9 |
| | $ | (27.3 | ) | | 9.6 |
| | $ | 2.4 |
| | $ | 64.2 |
| | $ | — |
| | $ | 66.6 |
| | $ | (34.7 | ) | | 31.9 |
|
PPAs (a) | | | | | | | | | | | | 5,160 |
| |
PPAs (b) | | | | | | | | | | | | | 0.1 |
| | | | | | | | | | | | 2.7 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 5,428 |
| | | | | | | | | | | | $ | 9.7 |
| | | | | | | | | | | | $ | 34.6 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | 2,382 |
| | $ | — |
| | $ | 2,382 |
| | $ | — |
| | $ | 2,382 |
| | $ | 0.2 |
| | $ | 2.7 |
| | $ | — |
| | $ | 2.9 |
| | $ | (2.3 | ) | | $ | 0.6 |
| | $ | — |
| | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
| | $ | (0.5 | ) | | $ | 0.6 |
|
| Total noncurrent derivative liabilities | | $ | — |
| | $ | 2,382 |
| | $ | — |
| | $ | 2,382 |
| | $ | — |
| | 2,382 |
| | $ | 0.2 |
| | $ | 2.7 |
| | $ | — |
| | $ | 2.9 |
| | $ | (2.3 | ) | | 0.6 |
| | $ | — |
| | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
| | $ | (0.5 | ) | | 0.6 |
|
PPAs (a) | | | | | | | | | | | | 89 |
| |
PPAs (b) | | | | | | | | | | | | | — |
| | | | | | | | | | | | — |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 2,471 |
| | | | | | | | | | | | $ | 0.6 |
| | | | | | | | | | | | $ | 0.6 |
|
| |
(a) | During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
|
| |
(b)
| PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2019 and Dec. 31, 2018. At both June 30, 2019 and Dec. 31, 2018, derivative assets and liabilities include no obligations to return cash collateralcollateral. At June 30, 2019 and Dec. 31, 2018, derivative assets and liabilities include the rights to reclaim cash collateral of $2.7 million.$6.4 million and $6.5 million, respectively. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2017 |
| | | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | | Total |
| Current derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 528 |
| | $ | 4,488 |
| | $ | 12 |
| | $ | 5,028 |
| | $ | (3,554 | ) | | $ | 1,474 |
|
| Natural gas commodity | | — |
| | 18 |
| | — |
| | 18 |
| | (10 | ) | | 8 |
|
| Total current derivative assets | | $ | 528 |
| | $ | 4,506 |
| | $ | 12 |
| | $ | 5,046 |
| | $ | (3,564 | ) | | 1,482 |
|
PPAs (a) | | | | | | | | | | | | 1,715 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 3,197 |
|
| Noncurrent derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | |
| | | | |
| | |
| | |
|
| Commodity trading | | $ | — |
| | $ | 1,541 |
| | $ | — |
| | $ | 1,541 |
| | $ | (563 | ) | | $ | 978 |
|
| Total noncurrent derivative assets | | $ | — |
| | $ | 1,541 |
| | $ | — |
| | $ | 1,541 |
| | $ | (563 | ) | | 978 |
|
PPAs (a) | | | | | | | | | | | | 31 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 1,009 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2017 |
| | | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | | Total |
| Current derivative liabilities | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 446 |
| | $ | 4,285 |
| | $ | 6 |
| | $ | 4,737 |
| | $ | (3,431 | ) | | $ | 1,306 |
|
| Natural gas commodity | | — |
| | 1,016 |
| | — |
| | 1,016 |
| | (10 | ) | | 1,006 |
|
| Total current derivative liabilities | | $ | 446 |
| | $ | 5,301 |
| | $ | 6 |
| | $ | 5,753 |
| | $ | (3,441 | ) | | 2,312 |
|
PPAs (a) | | | | | | | | | | | | 5,036 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 7,348 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | 1,362 |
| | $ | — |
| | $ | 1,362 |
| | $ | (563 | ) | | $ | 799 |
|
| Total noncurrent derivative liabilities | | $ | — |
| | $ | 1,362 |
| | $ | — |
| | $ | 1,362 |
| | $ | (563 | ) | | 799 |
|
PPAs (a) | | | | | | | | | | | | $ | 2,669 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 3,468 |
|
| |
(a)(b)
| During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts is beingwill be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
| |
(b)
| PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
There were $0.1$0.3 million and $1.0 million of gains recognized in earnings for Level 3 commodity trading derivatives in the three and six months ended June 30, 2018.2019, respectively. There were immaterial$0.1 million of gains and losses recognized in earnings for Level 3 commodity trading derivatives in both the three and six months ended June 30, 2017.
2018.
PSCo recognizes transfers between fair value hierarchy levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 20182019 and 2017.2018.
Fair Value of Long-Term Debt
As of June 30, 2018 and Dec. 31, 2017, otherOther financial instruments for which the carrying amount did not equal fair value were as follows:value:
|
| | | | | | | | | | | | | | | | |
| | | June 30, 2019 | | Dec. 31, 2018 |
| (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 4,846.1 |
| | $ | 5,333.3 |
| | $ | 4,997.6 |
| | $ | 5,123.2 |
|
|
| | | | | | | | | | | | | | | | |
| | | June 30, 2018 | | Dec. 31, 2017 |
| (Thousands of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 5,300,062 |
| | $ | 5,464,543 |
| | $ | 4,608,275 |
| | $ | 5,024,840 |
|
The fairFair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fairFair value estimates are based on information available to management as of June 30, 20182019 and Dec. 31, 2017,2018, and given the observability of the inputs, to these estimates, the fair values presented for long-term debt have beenwere assigned aas Level 2.
| |
| 8. | Benefit Plans and Other Postretirement Benefits |
Components of Net Periodic Benefit Cost (Credit)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30 |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| (Millions of Dollars) | | Pension Benefits | | Postretirement Health
Care Benefits |
| Service cost | | $ | 6.4 |
| | $ | 7.3 |
| | $ | 0.1 |
| | $ | 0.2 |
|
Interest cost (a) | | 12.9 |
| | 11.8 |
| | 3.9 |
| | 3.8 |
|
Expected return on plan assets (a) | | (17.1 | ) | | (17.1 | ) | | (4.7 | ) | | (5.7 | ) |
Amortization of prior service credit (a) | | (0.8 | ) | | (0.9 | ) | | (1.3 | ) | | (1.6 | ) |
Amortization of net loss (a) | | 6.3 |
| | 7.8 |
| | 0.7 |
| | 1.0 |
|
| Net periodic benefit cost (credit) | | 7.7 |
| | 8.9 |
| | (1.3 | ) | | (2.3 | ) |
| Credits not recognized due to the effects of regulation | | 1.8 |
| | 0.9 |
| | 0.2 |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 9.5 |
| | $ | 9.8 |
| | $ | (1.1 | ) | | $ | (2.3 | ) |
|
| | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30 |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| (Millions of Dollars) | | Pension Benefits | | Postretirement Health
Care Benefits |
| Service cost | | $ | 12.8 |
| | $ | 14.6 |
| | $ | 0.2 |
| | $ | 0.3 |
|
Interest cost (a) | | 25.8 |
| | 23.6 |
| | 7.8 |
| | 7.5 |
|
Expected return on plan assets (a) | | (34.2 | ) | | (34.3 | ) | | (9.4 | ) | | (11.3 | ) |
Amortization of prior service credit (a) | | (1.7 | ) | | (1.7 | ) | | (2.7 | ) | | (3.1 | ) |
Amortization of net loss (a) | | 12.7 |
| | 15.6 |
| | 1.5 |
| | 2.0 |
|
| Net periodic benefit cost (credit) | | 15.4 |
| | 17.8 |
| | (2.6 | ) | | (4.6 | ) |
| Credits not recognized due to the effects of regulation | | 3.6 |
| | 2.4 |
| | 0.5 |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 19.0 |
| | $ | 20.2 |
| | $ | (2.1 | ) | | $ | (4.6 | ) |
| |
(a) | The components of net periodic cost other than the service cost component are included in the line item “other income, net” in the consolidated statement of income or capitalized on the consolidated balance sheet as a regulatory asset. |
In January 2019, contributions of $150 million were made across four of Xcel Energy’s pension plans, of which $43 million was attributable to PSCo. On July 1, 2019, Xcel Energy made a $4 million contribution to the Xcel Energy Inc. Non-Bargaining Pension Plan (South), of which $3 million was attributable to PSCo, and does not expect any additional pension contributions during 2019.
| |
| 9. | Other Income, NetCommitments and Contingencies |
Legal Contingencies
PSCo is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Gas Trading Litigation —e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
Two cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.).
Breckenridge/Colorado - The MDL panel remanded Breckenridge back to the U.S. District Court in Colorado and assigned to a judge.
Other income, net consistedArandell Corp. - In February 2019, Xcel Energy filed a no opposition motion to have the case remanded back to the U.S. District Court in Wisconsin. The motion was granted and the case has been remanded back to the District Court.
Xcel Energy has concluded that a loss is remote for both remaining lawsuits.
Employment, Tort and Commercial Litigation
Line Extension Disputes — In December 2015, the DRC filed a lawsuit seeking monetary damages in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements. The dispute involves claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the following:lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so.
This claim is similar to the arguments previously raised by DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals. Briefs have been filed and it is uncertain when a decision will be rendered.
PSCo has concluded that a loss is remote with respect to both of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. If a loss were sustained, PSCo believes it would be allowed to recover costs through traditional regulatory mechanisms. Amount or range in dispute is presently unknown and no accrual has been recorded for this matter.
Environmental
MGP, Landfill or Disposal Sites — PSCo is cooperating with the City of Denver on an environmental investigation of the Rice Yards Site in the Central Platte Valley of Denver, Colorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard, and MGP operations. In the 1990’s, environmental remediation activities took place at the site under state oversight to accommodate the development of an amusement park and parking lots. The area is being redeveloped into residential and commercial mixed uses, and PSCo is in discussions with the current property owner regarding legal claims related to the Rice Yards Site.
In addition, PSCo is currently investigating or remediating two other MGP, landfill or other disposal sites across its service territories.
PSCo has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of the costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation— PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste.
Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. By the end of 2019, only six of PSCo’s regulated ash units are expected to be in operation. PSCo is conducting groundwater sampling, and where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments.
Until PSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.
Leases
PSCo evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by PSCo on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent PSCo's rights to use leased assets. Starting in 2019, the present value of future operating lease payments are recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of PSCo’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is calculated using the estimated incremental borrowing rate (weighted-average of 4.1%). PSCo has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
|
| | | | |
| (Millions of Dollars) | | June 30, 2019 |
| PPAs | | $ | 585.1 |
|
| Other | | 68.3 |
|
| Gross operating lease ROU assets | | 653.4 |
|
| Accumulated amortization | | (39.7 | ) |
| Net operating lease ROU assets | | $ | 613.7 |
|
In 2019, ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities. Prior to 2019, finance leases were included in property, plant and equipment, the current portion of long-term debt and long-term debt.
PSCo’s most significant finance lease activities are related to WYCO.WYCO is a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases.
Finance lease ROU assets:
|
| | | | |
| (Millions of Dollars) | | June 30, 2019 |
| Gas storage facilities | | $ | 200.5 |
|
| Gas pipeline | | 20.7 |
|
| Gross finance lease ROU assets | | 221.2 |
|
| Accumulated amortization | | (79.2 | ) |
| Net finance lease ROU assets | | $ | 142.0 |
|
Components of lease expense:
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30 | | Six Months Ended June 30 |
| (Thousands of Dollars) | | 2018 | | 2017 | | 2018 | | 2017 |
| Interest income | | $ | 508 |
| | $ | 609 |
| | $ | 372 |
| | $ | 984 |
|
| Other nonoperating income | | 483 |
| | 1,326 |
| | 956 |
| | 4,747 |
|
| Insurance policy expense | | (73 | ) | | (103 | ) | | (150 | ) | | (182 | ) |
| Benefits non-service cost | | (119 | ) | | (513 | ) | | (148 | ) | | (1,026 | ) |
| Other income, net | | $ | 799 |
| | $ | 1,319 |
| | $ | 1,030 |
| | $ | 4,523 |
|
|
| | | | | | | | |
| (Millions of Dollars) | | Three Months Ended June 30, 2019 | | Six Months Ended June 30, 2019 |
| Operating leases | | | | |
| PPA capacity payments | | $ | 24.7 |
| | $ | 49.0 |
|
Other operating leases (a) | | 3.6 |
| | 7.2 |
|
Total operating lease expense (b) | | $ | 28.3 |
| | $ | 56.2 |
|
| | | | | |
| Finance leases | | | | |
| Amortization of ROU assets | | $ | 1.5 |
| | $ | 3.0 |
|
| Interest expense on lease liability | | 4.7 |
| | 9.5 |
|
| Total finance lease expense | | $ | 6.2 |
| | $ | 12.5 |
|
| |
(a) | Includes short-term lease expense of $0.3 million for three months ended June 30, 2019 and $0.7 million for six months ended June 30, 2019. |
| |
(b) | PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power. |
Future commitments under operating and finance leases as of June 30, 2019:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases | | Finance Leases |
| 2019 | | $ | 47.8 |
| | $ | 6.5 |
| | $ | 54.3 |
| | $ | 12.4 |
|
| 2020 | | 95.9 |
| | 13.2 |
| | 109.1 |
| | 24.8 |
|
| 2021 | | 96.4 |
| | 12.1 |
| | 108.5 |
| | 23.6 |
|
| 2022 | | 82.6 |
| | 11.2 |
| | 93.8 |
| | 20.5 |
|
| 2023 | | 70.0 |
| | 10.9 |
| | 80.9 |
| | 20.3 |
|
| Thereafter | | 288.6 |
| | 29.2 |
| | 317.8 |
| | 420.4 |
|
| Total minimum obligation | | 681.3 |
| | 83.1 |
| | 764.4 |
| | 522.0 |
|
| Interest component of obligation | | (106.4 | ) | | (13.8 | ) | | (120.2 | ) | | (380.0 | ) |
| Present value of minimum obligation | | $ | 574.9 |
| | $ | 69.3 |
| | 644.2 |
| | 142.0 |
|
| Less current portion | | | | | | (83.9 | ) | | (6.5 | ) |
| Noncurrent operating and finance lease liabilities | | | | | | $ | 560.3 |
| | $ | 135.5 |
|
| | | | | | | | | |
| Weighted-average remaining lease term in years | | | | | | 8.3 |
| | 39.0 |
|
| |
(a) | Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. |
| |
(b) | PPA operating leases contractually expire at various dates through 2032. |
Future commitments under operating and finance leases as of Dec. 31, 2018:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases | | Finance Leases |
| 2019 | | $ | 95.5 |
| | $ | 10.8 |
| | $ | 106.3 |
| | $ | 24.9 |
|
| 2020 | | 95.9 |
| | 10.7 |
| | 106.6 |
| | 24.8 |
|
| 2021 | | 96.4 |
| | 9.5 |
| | 105.9 |
| | 23.6 |
|
| 2022 | | 82.6 |
| | 8.4 |
| | 91.0 |
| | 20.5 |
|
| 2023 | | 70.0 |
| | 8.1 |
| | 78.1 |
| | 20.3 |
|
| Thereafter | | 288.6 |
| | 53.4 |
| | 342.0 |
| | 420.4 |
|
| Total minimum obligation | |
|
| |
|
| |
|
| | 534.5 |
|
| Interest component of obligation | | | | | | | | (389.5 | ) |
| Present value of minimum obligation | | | | | | $ | 145.0 |
|
| |
(a) | Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. |
| |
(b) | PPA operating leases contractually expire at various dates through 2032. |
Variable Interest Entities
Under certain PPAs, PSCo purchases power from IPPs and is required to reimburse the IPPs for fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated IPP.
PSCo had approximately 1,442 MW and 1,571 MW of capacity under long-term PPAs as of June 30, 2019 and Dec. 31, 2018, respectively, with entities that have been determined to be VIEs. PSCo concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that significantly impact the entities’ economic performance. These agreements have various expiration dates through 2032.
| |
| 10. | Other Comprehensive Income (Loss) |
Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2019 and 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2018 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at April 1 | | $ | (25.0 | ) | | $ | (0.2 | ) | | $ | (25.2 | ) | | $ | (26.1 | ) | | $ | (0.3 | ) | | $ | (26.4 | ) |
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | | | | | | | |
Interest rate derivatives (net of taxes of $0.1, $0, $0.1 and $0, respectively) (a) | | 0.3 |
| | — |
| | 0.3 |
| | 0.3 |
| | — |
| | 0.3 |
|
| Net current period other comprehensive income | | 0.3 |
| | — |
| | 0.3 |
| | 0.3 |
| | — |
| | 0.3 |
|
| Accumulated other comprehensive loss at June 30 | | $ | (24.7 | ) | | $ | (0.2 | ) | | $ | (24.9 | ) | | $ | (25.8 | ) | | $ | (0.3 | ) | | $ | (26.1 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2018 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (25.3 | ) | | $ | (0.2 | ) | | $ | (25.5 | ) | | $ | (26.4 | ) | | $ | (0.3 | ) | | $ | (26.7 | ) |
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | | | | | | | |
Interest rate derivatives (net of taxes of $0.1, $0, $0.2 and $0, respectively) (a) | | 0.6 |
| | — |
| | 0.6 |
| | 0.6 |
| | — |
| | 0.6 |
|
| Net current period other comprehensive income | | 0.6 |
| | — |
| | 0.6 |
| | 0.6 |
| | — |
| | 0.6 |
|
| Accumulated other comprehensive loss at June 30 | | $ | (24.7 | ) | | $ | (0.2 | ) | | $ | (24.9 | ) | | $ | (25.8 | ) | | $ | (0.3 | ) | | $ | (26.1 | ) |
| |
(a) | Included in interest charges. |
Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker. PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
PSCo has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.
PSCo’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s commodity trading operations.
PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Colorado.
Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities.
| |
| • | Regulated Electric - The regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. This segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s wholesale commodity and trading operations. |
| |
| • | Regulated Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado. |
| |
| • | All Other - Revenues from operating segments not included above are below the necessary quantitative thresholds are included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities. |
Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, someCertain costs, such as common depreciation, common operating and maintenance (O&M)O&M expenses and interest expense are allocated based on cost causation allocators. Aallocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
| Three Months Ended June 30, 2018 | | | | | | | | | | |
Operating revenues (a)(b) | | $ | 716,195 |
| | $ | 186,661 |
| | $ | 9,010 |
| | $ | — |
| | $ | 911,866 |
|
| Intersegment revenues | | 76 |
| | 79 |
| | — |
| | (155 | ) | | — |
|
| Total revenues | | $ | 716,271 |
| | $ | 186,740 |
| | $ | 9,010 |
| | $ | (155 | ) | | $ | 911,866 |
|
| Net income (loss) | | $ | 101,956 |
| | $ | 20,963 |
| | $ | (623 | ) | | $ | — |
| | $ | 122,296 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
| Three Months Ended June 30, 2017 | | | | | | | | | | |
Operating revenues (a)(b) | | $ | 729,920 |
| | $ | 192,777 |
| | $ | 8,219 |
| | $ | — |
| | $ | 930,916 |
|
| Intersegment revenues | | 67 |
| | 40 |
| | — |
| | (107 | ) | | — |
|
| Total revenues | | $ | 729,987 |
| | $ | 192,817 |
| | $ | 8,219 |
| | $ | (107 | ) | | $ | 930,916 |
|
| Net income | | $ | 87,403 |
| | $ | 12,835 |
| | $ | 349 |
| | $ | — |
| | $ | 100,587 |
|
(a) Operating revenues include $0 million of affiliate electric revenue for the three months ended June 30, 2018 and 2017.
(b) Operating revenues include $1 million of other affiliate revenue for the three months ended June 30, 2018 and 2017.
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated
Electric | | Regulated
Natural Gas | | All
Other | | Reconciling
Eliminations | | Consolidated
Total |
| Six Months Ended June 30, 2018 | | | | | | | | | | |
| Operating revenues from external customers | | $ | 1,414,469 |
| | $ | 550,647 |
| | $ | 20,048 |
| | $ | — |
| | $ | 1,985,164 |
|
| Intersegment revenues | | 188 |
| | 143 |
| | — |
| | (331 | ) | | — |
|
| Total revenues | | $ | 1,414,657 |
| | $ | 550,790 |
| | $ | 20,048 |
| | $ | (331 | ) | | $ | 1,985,164 |
|
| Net income (loss) | | $ | 181,507 |
| | $ | 74,675 |
| | $ | (164 | ) | | $ | — |
| | $ | 256,018 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated
Electric | | Regulated
Natural Gas | | All
Other | | Reconciling
Eliminations | | Consolidated
Total |
| Six Months Ended June 30, 2017 | | | | |
| | | | | | |
| Operating revenues from external customers | | $ | 1,441,308 |
| | $ | 548,913 |
| | $ | 21,229 |
| | $ | — |
| | $ | 2,011,450 |
|
| Intersegment revenues | | 159 |
| | 96 |
| | — |
| | (255 | ) | | — |
|
| Total revenues | | $ | 1,441,467 |
| | $ | 549,009 |
| | $ | 21,229 |
| | $ | (255 | ) | | $ | 2,011,450 |
|
| Net income | | $ | 163,547 |
| | $ | 47,318 |
| | $ | 1,268 |
| | $ | — |
| | $ | 212,133 |
|
(a) Operating revenues include $0 million and $1 million of affiliate electric revenue for the six months ended June 30, 2018 and 2017.
(b) Operating revenues include $2 million of other affiliate revenue for the six months ended June 30, 2018 and 2017.
| |
11. | Benefit Plans and Other Postretirement Benefits |
Components of Net Periodic Benefit Cost (Credit)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30 |
| | | 2018 | | 2017 | | 2018 | | 2017 |
| (Thousands of Dollars) | | Pension Benefits | | Postretirement Health Care Benefits |
| Service cost | | $ | 7,271 |
| | $ | 6,820 |
| | $ | 152 |
| | $ | 192 |
|
Interest cost (a) | | 11,814 |
| | 12,640 |
| | 3,748 |
| | 4,191 |
|
Expected return on plan assets (a) | | (17,130 | ) | | (17,134 | ) | | (5,674 | ) | | (5,476 | ) |
Amortization of prior service credit (a) | | (845 | ) | | (803 | ) | | (1,544 | ) | | (1,562 | ) |
Amortization of net loss (a) | | 7,815 |
| | 7,089 |
| | 1,021 |
| | 961 |
|
| Net periodic benefit cost (credit) | | 8,925 |
| | 8,612 |
| | (2,297 | ) | | (1,694 | ) |
| Credits not recognized due to the effects of regulation | | 895 |
| | 426 |
| | — |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 9,820 |
| | $ | 9,038 |
| | $ | (2,297 | ) | | $ | (1,694 | ) |
|
| | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30 |
| | | 2018 | | 2017 | | 2018 | | 2017 |
| (Thousands of Dollars) | | Pension Benefits | | Postretirement Health
Care Benefits |
| Service cost | | $ | 14,542 |
| | $ | 13,640 |
| | $ | 304 |
| | $ | 384 |
|
Interest cost (a) | | 23,628 |
| | 25,280 |
| | 7,497 |
| | 8,382 |
|
Expected return on plan assets (a) | | (34,260 | ) | | (34,268 | ) | | (11,349 | ) | | (10,952 | ) |
Amortization of prior service credit (a) | | (1,690 | ) | | (1,606 | ) | | (3,089 | ) | | (3,124 | ) |
Amortization of net loss (a) | | 15,630 |
| | 14,178 |
| | 2,042 |
| | 1,922 |
|
| Net periodic benefit cost (credit) | | 17,850 |
| | 17,224 |
| | (4,595 | ) | | (3,388 | ) |
| Credits not recognized due to the effects of regulation | | 2,370 |
| | 1,162 |
| | — |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 20,220 |
| | $ | 18,386 |
| | $ | (4,595 | ) | | $ | (3,388 | ) |
| |
(a)
| The components of net periodic cost other than the service cost component are included in the line item “other income, net” in the income statement or capitalized on the balance sheet as a regulatory asset. |
In January 2018, contributions of $150 million were made across four of Xcel Energy’s pension plans, of which $22.0 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2018.
| |
12. | Other Comprehensive Income (Loss) |
Changes in accumulated other comprehensive loss, net of tax,PSCo’s segment information for the three and six months ended June 30, 2018 and 2017 were as follows:30:
|
| | | | | | | | | | | | |
| | | Three Months Ended June 30, 2018 |
| (Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at April 1 | | $ | (26,165 | ) | | $ | (265 | ) | | $ | (26,430 | ) |
| Losses reclassified from net accumulated other comprehensive loss | | 303 |
| | 2 |
| | 305 |
|
| Net current period other comprehensive income | | 303 |
| | 2 |
| | 305 |
|
| Accumulated other comprehensive loss at June 30 | | $ | (25,862 | ) | | $ | (263 | ) | | $ | (26,125 | ) |
|
| | | | | | | | | | | | |
| | | Three Months Ended June 30, 2017 |
| (Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at April 1 | | $ | (22,534 | ) | | $ | (219 | ) | | $ | (22,753 | ) |
| Losses reclassified from net accumulated other comprehensive loss | | 250 |
| | 1 |
| | 251 |
|
| Net current period other comprehensive income | | 250 |
| | 1 |
| | 251 |
|
| Accumulated other comprehensive loss at June 30 | | $ | (22,284 | ) | | $ | (218 | ) | | $ | (22,502 | ) |
|
| | | | | | | | | | | | |
| | | Six Months Ended June 30, 2018 |
| (Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (26,465 | ) | | $ | (267 | ) | | $ | (26,732 | ) |
| Losses reclassified from net accumulated other comprehensive loss | | 603 |
| | 4 |
| | 607 |
|
| Net current period other comprehensive income | | 603 |
| | 4 |
| | 607 |
|
| Accumulated other comprehensive loss at June 30 | | $ | (25,862 | ) | | $ | (263 | ) | | $ | (26,125 | ) |
|
| | | | | | | | | | | | |
| | | Six Months Ended June 30, 2017 |
| (Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (22,780 | ) | | $ | (220 | ) | | $ | (23,000 | ) |
| Losses reclassified from net accumulated other comprehensive loss | | 496 |
| | 2 |
| | 498 |
|
| Net current period other comprehensive income | | 496 |
| | 2 |
| | 498 |
|
| Accumulated other comprehensive loss at June 30 | | $ | (22,284 | ) | | $ | (218 | ) | | $ | (22,502 | ) |
Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2018 and 2017 were as follows:
|
| | | | | | | | | |
| | | | | | |
| | | Amounts Reclassified from Accumulated Other
Comprehensive Loss | |
| (Thousands of Dollars) | | Three Months Ended June 30, 2018 | | Three Months Ended June 30, 2017 | |
| Losses on cash flow hedges: | | |
| | | |
| Interest rate derivatives | | $ | 402 |
| (a) | $ | 403 |
| (a) |
| Total, pre-tax | | 402 |
| | 403 |
| |
| Tax benefit | | (99 | ) | | (153 | ) | |
| Total, net of tax | | 303 |
| | 250 |
| |
| Defined benefit pension and postretirement losses: | | | | | |
| Amortization of net loss | | 2 |
| (b) | 2 |
| (b) |
| Total, pre-tax | | 2 |
| | 2 |
| |
| Tax benefit | | — |
| | (1 | ) | |
| Total, net of tax | | 2 |
| | 1 |
| |
| Total amounts reclassified, net of tax | | $ | 305 |
| | $ | 251 |
| |
|
| | | | | | | | | |
| | | | | | |
| | | Amounts Reclassified from Accumulated Other Comprehensive Loss | |
| (Thousands of Dollars) | | Six Months Ended June 30, 2018 | | Six Months Ended June 30, 2017 | |
| Losses on cash flow hedges: | | | | | |
| Interest rate derivatives | | $ | 800 |
| (a) | $ | 801 |
| (a) |
| Total, pre-tax | | 800 |
| | 801 |
| |
| Tax benefit | | (197 | ) | | (305 | ) | |
| Total, net of tax | | $ | 603 |
| | $ | 496 |
| |
| Defined benefit pension and postretirement losses: | | | | | |
| Amortization of net loss | | $ | 4 |
| (b) | $ | 4 |
| (b) |
| Total, pre-tax | | 4 |
| | 4 |
| |
| Tax benefit | | — |
| | (2 | ) | |
| Total, net of tax | | 4 |
| | 2 |
| |
| Total amounts reclassified, net of tax | | $ | 607 |
| | $ | 498 |
| |
|
| | | | | | | | |
| | | Three Months Ended June 30 |
| (Millions of Dollars) | | 2019 | | 2018 |
| Regulated Electric | | | | |
| Operating revenues | | $ | 692.7 |
| | $ | 716.2 |
|
| Intersegment revenues | | 0.1 |
| | 0.1 |
|
| Total revenue | | 692.8 |
| | 716.3 |
|
| Net income | | 84.8 |
| | 101.9 |
|
| Regulated Natural Gas | | | | |
| Operating revenues | | $ | 207.6 |
| | $ | 186.7 |
|
| Intersegment revenues | | — |
| | 0.1 |
|
| Total revenue | | 207.6 |
| | 186.8 |
|
| Net income | | 17.6 |
| | 21.0 |
|
| All Other | | | | |
Operating revenues (a) | | $ | 9.7 |
| | $ | 9.0 |
|
| Net loss | | (0.9 | ) | | (0.6 | ) |
| Consolidated Total | | | | |
Operating revenues (a) | | $ | 910.1 |
| | $ | 912.1 |
|
| Reconciling eliminations | | (0.1 | ) | | (0.2 | ) |
| Total revenue | | $ | 910.0 |
| | $ | 911.9 |
|
| Net income | | 101.5 |
| | 122.3 |
|
| |
(a) | Included in interest charges.Operating revenues include $1.1 million of other affiliate revenue for the three months ended June 30, 2019 and 2018. |
|
| | | | | | | | |
| | | Six Months Ended June 30 |
| (Millions of Dollars) | | 2019 | | 2018 |
| Regulated Electric | | | | |
| Operating revenues | | $ | 1,434.2 |
| | $ | 1,414.5 |
|
| Intersegment revenues | | 0.2 |
| | 0.2 |
|
| Total revenue | | 1,434.4 |
| | 1,414.7 |
|
| Net income | | 167.2 |
| | 181.5 |
|
| Regulated Natural Gas | | | | |
| Operating revenues | | $ | 676.7 |
| | $ | 550.6 |
|
| Intersegment revenues | | 0.1 |
| | 0.1 |
|
| Total revenue | | 676.8 |
| | 550.7 |
|
| Net income | | 76.8 |
| | 74.7 |
|
| All Other | | | | |
Operating revenues (a) | | $ | 22.1 |
| | $ | 20.1 |
|
| Net loss | | (3.7 | ) | | (0.2 | ) |
| Consolidated Total | | | | |
Operating revenues (a) | | $ | 2,133.3 |
| | $ | 1,985.5 |
|
| Reconciling eliminations | | (0.3 | ) | | (0.3 | ) |
| Total revenue | | $ | 2,133.0 |
| | $ | 1,985.2 |
|
| Net income | | 240.3 |
| | 256.0 |
|
| |
(b)(a)
| Included inOperating revenues include $2.2 million of other affiliate revenue for the computation of net periodic pensionsix months ended June 30, 2019 and postretirement benefit costs. See Note 11 to the consolidated financial statements for details regarding these benefit plans.2018. |
PSCo principally generates revenue from the generation, transmission, distribution and sale of electricity and the transportation, distribution and sale of natural gas to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. PSCo recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such PSCo does not recognize a separate financing component of its collections from customers. PSCo presents its revenues net of any excise or other fiduciary-type taxes or fees.
PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned.
In the following tables, revenue is classified by the type of goods/services rendered and market/customer type. The tables also reconcile revenue to the reportable segments.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, 2018 |
| (Thousands of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 222,687 |
| | $ | 104,000 |
| | $ | 2,560 |
| | $ | 329,247 |
|
| Commercial and industrial (C&I) | | 383,707 |
| | 38,904 |
| | 5,326 |
| | 427,937 |
|
| Other | | 11,455 |
| | — |
| | — |
| | 11,455 |
|
| Total retail | | 617,849 |
| | 142,904 |
| | 7,886 |
| | 768,639 |
|
| Wholesale | | 36,148 |
| | — |
| | — |
| | 36,148 |
|
| Transmission | | 13,159 |
| | — |
| | — |
| | 13,159 |
|
| Other | | 14,696 |
| | 18,845 |
| | — |
| | 33,541 |
|
| Total revenue from contracts with customers | | 681,852 |
| | 161,749 |
| | 7,886 |
| | 851,487 |
|
| Alternative revenue and other | | 34,343 |
| | 24,912 |
| | 1,124 |
| | 60,379 |
|
| Total revenues | | $ | 716,195 |
| | $ | 186,661 |
| | $ | 9,010 |
| | $ | 911,866 |
|
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, 2017 |
| (Thousands of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 225,921 |
| | $ | 117,393 |
| | $ | 2,639 |
| | $ | 345,953 |
|
| C&I | | 392,280 |
| | 45,032 |
| | 4,457 |
| | 441,769 |
|
| Other | | 11,711 |
| | — |
| | — |
| | 11,711 |
|
| Total retail | | 629,912 |
| | 162,425 |
| | 7,096 |
| | 799,433 |
|
| Wholesale | | 41,579 |
| | — |
| | — |
| | 41,579 |
|
| Transmission | | 13,180 |
| | — |
| | — |
| | 13,180 |
|
| Other | | 16,837 |
| | 20,040 |
| | — |
| | 36,877 |
|
| Total revenue from contracts with customers | | 701,508 |
| | 182,465 |
| | 7,096 |
| | 891,069 |
|
| Alternative revenue and other | | 28,412 |
| | 10,312 |
| | 1,123 |
| | 39,847 |
|
| Total revenues | | $ | 729,920 |
| | $ | 192,777 |
| | $ | 8,219 |
| | $ | 930,916 |
|
|
| | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2018 |
| (Thousands of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 450,336 |
| | $ | 331,746 |
| | $ | 5,256 |
| | $ | 787,338 |
|
| C&I | | 726,933 |
| | 124,932 |
| | 12,485 |
| | 864,350 |
|
| Other | | 23,631 |
| | — |
| | 60 |
| | 23,691 |
|
| Total retail | | 1,200,900 |
| | 456,678 |
| | 17,801 |
| | 1,675,379 |
|
| Wholesale | | 84,038 |
| | — |
| | — |
| | 84,038 |
|
| Transmission | | 25,411 |
| | — |
| | — |
| | 25,411 |
|
| Other | | 33,527 |
| | 43,774 |
| | — |
| | 77,301 |
|
| Total revenue from contracts with customers | | 1,343,876 |
| | 500,452 |
| | 17,801 |
| | 1,862,129 |
|
| Alternative revenue and other | | 70,593 |
| | 50,195 |
| | 2,247 |
| | 123,035 |
|
| Total revenues | | $ | 1,414,469 |
| | $ | 550,647 |
| | $ | 20,048 |
| | $ | 1,985,164 |
|
|
| | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2017 |
| (Thousands of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 460,355 |
| | $ | 343,303 |
| | $ | 5,203 |
| | $ | 808,861 |
|
| C&I | | 751,977 |
| | 131,274 |
| | 13,717 |
| | 896,968 |
|
| Other | | 24,386 |
| | — |
| | 63 |
| | 24,449 |
|
| Total retail | | 1,236,718 |
| | 474,577 |
| | 18,983 |
| | 1,730,278 |
|
| Wholesale | | 85,155 |
| | — |
| | — |
| | 85,155 |
|
| Transmission | | 27,819 |
| | — |
| | — |
| | 27,819 |
|
| Other | | 33,532 |
| | 42,650 |
| | — |
| | 76,182 |
|
| Total revenue from contracts with customers | | 1,383,224 |
| | 517,227 |
| | 18,983 |
| | 1,919,434 |
|
| Alternative revenue and other | | 58,084 |
| | 31,686 |
| | 2,246 |
| | 92,016 |
|
| Total revenues | | $ | 1,441,308 |
| | $ | 548,913 |
| | $ | 21,229 |
| | $ | 2,011,450 |
|
Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions H (1) H(1)(a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) H(2)(a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).
Financial Review
The following discussion and analysis by management focuses on those factors that had a material effect on PSCo’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements. Due to the seasonality of PSCo’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.
Forward-Looking Statements
Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements including the TCJA’s impact to PSCo and its customers, as well as assumptions and other statements identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including PSCo’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2017 and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, and natural gas margin.margin and ongoing earnings. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from the most directly comparable measuremeasures calculated and presented in accordance with GAAP. PSCo’s management uses non-GAAP measures internally for financial planning and analysis, for reporting of results, to the Board of Directorsin determining performance-based compensation and when communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our operating performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses and naturalexpenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas sold and transported are generally recovered through various regulatory recovery mechanisms, and asmechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including steam and other operating revenues, cost of sales - steam and other,sales-other, O&M expenses, conservation and demand side management (DSM) expenses, depreciation and amortization and taxes (other than income taxes).
Results of Operations
PSCo’s net income was approximately $256$240.3 million for the second quarter of 2018,2019, compared with approximately $212$256.0 million for the same period of 2017.2018. The increasedecrease in year-to-date earnings was driven by higher electricO&M and natural gas margins due to the impact of an interim rate increase, subject to refund, and favorable weather and increased allowance for funds used during construction (AFUDC) primarily related to the Rush Creek wind project. These items weredepreciation partially offset by the timing of gas rates in 2018 and higher interest charges and depreciation expense.
gas sales.
Electric Revenues and Margin
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas and coal used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. The following table details theIn addition, electric customers receive a credit for PTCs that are generated in a particular period.
Electric revenues and margin:
| | | | | Six Months Ended June 30 | | Six Months Ended June 30 |
| (Millions of Dollars) | | 2018 | | 2017 | | 2019 | | 2018 |
| Electric revenues before impact of the TCJA | | $ | 1,460 |
| | $ | 1,441 |
| |
| Electric revenues | | | $ | 1,434.2 |
| | $ | 1,414.5 |
|
| Electric fuel and purchased power | | (553 | ) | | (568 | ) | | (544.9 | ) | | (553.1 | ) |
| Electric margin before impact of the TCJA | | $ | 907 |
| | $ | 873 |
| |
| Impact of the TCJA (offset as a reduction in income tax expense) | | (46 | ) | | — |
| |
| Electric margin | | $ | 861 |
| | $ | 873 |
| | $ | 889.3 |
| | $ | 861.4 |
|
The following tables summarize the components of the changesChanges in electric revenues and electric margin for the six months ended June 30:
Electric Revenuesmargin:
|
| | | | |
| (Millions of Dollars) | | 2018 vs. 2017 |
| Fuel and purchased power cost recovery | | $ | (8 | ) |
| Estimated impact of weather | | 8 |
|
| DSM program revenues (offset by expenses) | | 7 |
|
| Trading | | 5 |
|
| DSM incentive | | 2 |
|
| Non-fuel riders | | 2 |
|
| Firm wholesale | | 2 |
|
| Other, net | | 1 |
|
| Total increase in electric revenues before impact of the TCJA | | $ | 19 |
|
| Impact of the TCJA (offset as a reduction in income tax expense) | | (46 | ) |
| Total decrease in electric revenues | | $ | (27 | ) |
Electric Margin
|
| | | | |
| (Millions of Dollars) | | 2018 vs. 2017 |
| Estimated impact of weather | | $ | 8 |
|
| DSM program revenues (offset by expenses) | | 7 |
|
| Trading | | 3 |
|
| DSM incentive | | 2 |
|
| Fuel handling and procurement | | 2 |
|
| Non-fuel riders | | 2 |
|
| Firm wholesale | | 2 |
|
| Other, net | | 8 |
|
| Total increase in electric margin before impact of the TCJA | | $ | 34 |
|
| Impact of the TCJA (offset as a reduction in income tax expense) | | (46 | ) |
| Total decrease in electric margin | | $ | (12 | ) |
|
| | | | |
| (Millions of Dollars) | | Three Months Ended June 30, 2019 vs. 2018 |
| Non-fuel riders | | $ | 32.5 |
|
| Finance leases (offset in interest expense and amortization) | | 10.9 |
|
| Timing of tax reform regulatory decisions (offset in income tax and amortization) | | 6.0 |
|
| Estimated impact of weather | | (11.0 | ) |
| Wholesale transmission revenue (net) | | (2.5 | ) |
| Other, net | | (8.0 | ) |
| Total increase in electric margin | | $ | 27.9 |
|
Natural Gas Revenues and Margin
Total natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas hashave minimal impact on natural gas margin due to natural gas cost recovery mechanisms. The following table details natural
Natural gas revenues and margin:
|
| | | | | | | | |
| | | Six Months Ended June 30 |
| (Millions of Dollars) | | 2019 | | 2018 |
| Natural gas revenues | | $ | 676.7 |
| | $ | 550.6 |
|
| Cost of natural gas sold and transported | | (342.4 | ) | | (249.8 | ) |
| Natural gas margin | | $ | 334.3 |
| | $ | 300.8 |
|
|
| | | | | | | | |
| | | Six Months Ended June 30 |
| (Millions of Dollars) | | 2018 | | 2017 |
| Natural gas revenues before impact of the TCJA | | $ | 566 |
| | $ | 549 |
|
| Cost of natural gas sold and transported | | (250 | ) | | (267 | ) |
| Natural gas margin before impact of the TCJA | | $ | 316 |
| | $ | 282 |
|
| Impact of the TCJA (offset as a reduction in income tax expense) | | (15 | ) | | — |
|
| Natural gas margin | | $ | 301 |
| | $ | 282 |
|
The following tables summarize the components of the changesChanges in natural gas revenues and natural gas margin for the six months ended June 30:
Natural Gas Revenuesmargin:
|
| | | | |
| (Millions of Dollars) | | 2018 vs. 2017 |
| Retail rate increase (interim, subject to refund) | | $ | 20 |
|
| Infrastructure and integrity riders | | 8 |
|
| Estimated impact of weather | | 4 |
|
| Purchased natural gas adjustment clause recovery | | (16 | ) |
| Other, net | | 1 |
|
| Total increase in natural gas revenues before impact of the TCJA | | $ | 17 |
|
| Impact of the TCJA (offset as a reduction in income tax expense) | | (15 | ) |
| Total increase in natural gas revenues | | $ | 2 |
|
Natural Gas Margin
| | | (Millions of Dollars) | | 2018 vs. 2017 | | Three Months Ended June 30, 2019 vs. 2018 |
| Retail rate increase (interim, subject to refund) | | $ | 20 |
| |
| Retail rate increase | | | $ | 11.9 |
|
| Estimated impact of weather | | | 8.7 |
|
| Infrastructure and integrity riders | | 8 |
| | 5.2 |
|
| Estimated impact of weather | | 4 |
| |
| Transport sales | | | 3.7 |
|
| Retail sales growth (excluding weather impact) | | | 3.5 |
|
| Other, net | | 2 |
| | 0.5 |
|
| Total increase in natural gas margin before impact of the TCJA | | $ | 34 |
| |
| Impact of the TCJA (offset as a reduction in income tax expense) | | (15 | ) | |
| Total increase in natural gas margin | | $ | 19 |
| | $ | 33.5 |
|
Non-Fuel Operating Expenses and Other Items
O&M Expenses— O&M expenses increased $27.4 million, or 7.4%, for 2019 year-to-date. Increase was primarily driven by distribution, plant generation and natural gas operations costs. Distribution costs were higher due to storms, meters and vegetation management. Plant generation costs increased due to the Rush Creek wind project being placed in-service and the timing of planned maintenance and overhauls. Natural gas operation expenses increased due to pipeline maintenance.
Depreciation and Amortization— Depreciation and amortization expense increased $56.8 million, or 23.8%, for 2019 year-to-date. Increase was primarily driven by the Rush Creek wind project being placed in-service (recovered in riders), additional amortization of a prepaid pension asset in Colorado related to tax reform settlements (offset in income taxes) and other capital investments.
AFUDC, Equity and Debt— AFUDC decreased $20.3 million for 2019 year-to-date. Decrease was primarily due to the Rush Creek wind project being placed in-service in 2018.
Interest Charges— Interest charges increased $15.9 million, or 15.7%, for 2019 year-to-date. Increase was related to higher debt levels to fund capital investments, changes in short-term interest rates and implementation of lease accounting standard (offset in electric margin).
Income Taxes — Income tax expense decreased $44.6 million for the second quarter of 2019 compared with 2018. Decrease was primarily driven by wind PTCs, lower pretax earnings and an increase in plant-related regulatory differences. Wind PTCs flow back to customers (recorded as a reduction to revenue) and do not have a material impact on net income. ETR was 11.0% for the first six months of 2019 compared with 22.5% for the same period of 2018, largely due to the adjustments above. See Note 6 to the consolidated financial statements.
Regulation
FERC and State Regulation — The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters.
Xcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations. Decisions by these regulators can significantly impact PSCo’s results of operations.
Colorado 2019 Electric Rate Case — In May 2019, PSCo filed a request with the CPUC seeking a net rate increase of $158.3 million, or 5.7%. The filing also requests the transfer of $249.4 million of rider revenue to base rates, which will not impact overall customer bills as the revenue is currently being recovered through various riders. The request is based on a ROE of 10.35%, an equity ratio of 56.46%, a historic test year ended Dec. 31, 2018 (adjusted for 2019 capital investment) and incorporates the full impact of tax reform. PSCo has requested rates effective Jan. 1, 2020.
|
| | | | |
| Revenue Request (Millions of Dollars) | | 2020 |
| Changes since 2014 rate case: | | |
| Plant-related growth 2013-2018 | | $ | 85.3 |
|
| O&M savings, sales growth and other cost reductions | | (89.1 | ) |
| Forecasted 2019 capital additions | | 48.9 |
|
| Advanced Grid Intelligence and Security grid modernization | | 39.1 |
|
| Updated cost of capital | | 31.7 |
|
| Previously approved depreciation rates | | 28.1 |
|
| Incremental wildfire mitigation | | 14.3 |
|
| Net increase to revenue | | 158.3 |
|
| Previously authorized costs: | | |
CACJA, TCA and Rush Creek (a) | | 249.4 |
|
| Total base revenue request | | $ | 407.7 |
|
| | | |
Expected year-end rate base (b) | | $ | 8,221.1 |
|
| |
(a) | Roll-in of CACJA, TCA and Rush Creek Wind Project (excluding PTCs) amounts into base rates will not impact total revenue as costs are currently recovered from customers through riders or the fuel clause. |
| |
(b) | Base rate request does not include the impact of the proposed Colorado Energy Plan. |
The procedural schedule is as follows:
Answer testimony — Sept. 6, 2019
Rebuttal testimony — Oct. 8, 2019
Evidentiary hearing — Nov. 4-13, 2019
Statement of position — Nov. 22, 2019
Other Pending and Recently Concluded Regulatory Proceedings
|
| | | | | | | | | | |
| Mechanism | | Utility Service | | Amount Requested (in millions) | | Filing Date | | Approval | | Additional Information |
| CPUC |
| Rate Case | | Steam | | $7 | | May 2019 | | Pending | | In May 2019, PSCo filed an unopposed Settlement Agreement with CPUC Staff and the City of Denver. The settlement reflects a ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. Final rates would be effective in October 2020, with an initial step increase in October 2019. In July 2019, the Administrative Law Judge recommended that the settlement agreement be approved without modification. Settlement is pending a CPUC decision. |
| Rate Case Appeal | | Natural Gas | | N/A | | April 2019 | | Pending | | In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). Appeal requests review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure that is not based on the actual historical test year level; and the use of an average rate base methodology rather than a year-end rate base methodology. The District Court of Denver County has adopted a briefing schedule that will conclude in October 2019. Timeline on a final ruling is unknown at this point. |
DSM Program Expenses — DSM program expenses increased $8 million, or 13.7 percent, for 2018 year-to-date. The increase was due to higher recovery rates for electric and natural gas sales. DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred.
Depreciation and Amortization— Depreciation and amortization expense increased $6 million, or 2.4 percent, for 2018 year-to-date. The increase was primarily driven by capital expenditures due to planned system investments.
AFUDC, Equity and Debt— AFUDC increased $19 million for 2018 year-to-date. The increase was primarily due to the Rush Creek wind project.
Interest Charges— Interest charges increased $9 million, or 9.6 percent, for 2018 year-to-date. The increase was primarily due to higher debt levels to fund capital investments, partially offset by refinancings at lower interest rates.
Income Taxes — Income tax expense decreased $47 million for the first six months of 2018 compared with the same period in 2017. The decrease was primarily driven by a lower federal tax rate due to the TCJA. The ETR was 22.5 percent for the first six months of 2018 compared with 36.4 percent for the same period of 2017. The lower ETR in 2018 is primarily due to the lower federal tax rate. See Note 4 to the consolidated financial statements.
Public Utility Regulation
Except to the extent noted below and in Note 5 to the consolidated financial statements,Regulation above, the circumstances set forth in Public Utility Regulation included in Item 1 of PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 20172018 and Public Utility Regulation included in Item 2 of PSCo’sPSCo's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018,2019, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference. Colorado Energy Plan (CEP) — In 2016, PSCo filed its 2016 Electric Resource Plan (ERP) which included the estimated need for additional generation resources through spring of 2024. In 2017, PSCo filed an updated capacity need with the CPUC of 450 MW in 2023.
In 2017, PSCo and various other stakeholders filed a stipulation agreement proposing the CEP, an alternative plan that increases PSCo’s potential capacity need up to 1,110 MW due to the proposed retirement of two coal units.
Environmental Matters
In June 2018, PSCo filed its 120-day update report2019, the EPA issued the final ACE rule to replace the Obama-era Clean Power Plan. The final ACE rule may require implementation of heat rate improvement projects at some of our coal-fired power plants. It is not known what the costs associated with the CPUC which includes multiple portfolios and recommends a preferred CEP portfolio. PSCo's investment underfinal rule might be until state plans are developed to implement the preferred CEP portfoliofinal regulation. PSCo believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be approximately $1 billion, including investment in transmission to support the significant increase in renewable generation in the state. The preferred CEP portfolio includes the following additions as well as the retirement of the two coal-fired generation units:
|
| | | | |
| Total Capacity | | PSCo's Ownership |
Wind generation | 1,100 MW | | 500 MW |
|
Solar generation | 700 MW | | — |
|
Battery storage | 275 MW | | — |
|
Natural gas generation | 380 MW | | 380 MW |
|
On July 13, 2018, the Independent Evaluator (IE) for the ERP filed their report on the process, modeling and evaluation of the various offers receivedrecoverable through the RFP process. Generally, the IE report was favorable to the process employed and the outcomes included in the modeling. Certain recommendations for future ERP processes were provided with a primary focus regarding enhanced modeling of new resource types such as battery storage.
On July 23, 2018, various stakeholders commented on the 120-day update report for the ERP and the CEP. Many community, advocate and developer interests supported the CEP, while certain stakeholders opposed the CEP and the associated early coal plant retirements. The CPUC staff indicated that PSCo’s preferred CEP plan is a valid option, but expressed concerns on the saving assumptions, complexity of modeling and the utilization of production tax credits.
A CPUC decision is anticipated in September 2018.
Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC — Sustainable Power Group, LLC (sPower) has proposed to construct over 1,500 MW of solar and wind generation in Colorado and is seeking to require PSCo to contract for these resources under PURPA. In March 2017, sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find a December 2016 CPUC ruling that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process violated PURPA and FERC rules. In June 2018, the court denied a motion by the CPUC to dismiss. The case remains pending further action from the court.
Open Access Transmission Tariff (OATT) Reform — In May 2018, the FERC denied a request by PSCo to amend its OATT to allow large generating interconnection agreements to be suspended by the generator only due to a force majeure event, rather than allowing suspension for up to 36 months for any reason. PSCo requested the changes to facilitate more efficient processing of generator interconnection requests. PSCo has initiated a process to achieve broader generator interconnection queue reform and anticipates requesting additional OATT changes later in 2018. In April, 2018, the FERC had issued a final rule requiring generator interconnection OATT queue reforms in addition (but generally complimentary) to reforms PSCo already requested. PSCo currently has more than 22,000 MW of new generator projects in its interconnection queue. The broader interconnection queue reforms are intended to allow generators to proceed to interconnection on a “first ready, first served” basis, similar to the processes already use in MISO.
Boulder, Colorado Municipalization — In 2011, City of Boulder, Colorado (Boulder) voters passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Since that time, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme Court rejected Boulder’s request to dismiss the case and ruled that the case be remanded for hearing at the Boulder District Court (District Court).
Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings. In July 2018, the CPUC approved Boulder and PSCo’s joint request to extend the time by which these filings would be due until Aug. 24, 2018. Boulder does not have authorization from the CPUC to initiate a condemnation proceeding at this time.
Summary of Recent Federal Regulatory Developments
FERC
The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2017 and Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.
Xcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations.
rates.
Item 4 — CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of June 30, 2018,2019, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in PSCo’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, PSCo’s internal control over financial reporting.
Part II — OTHER INFORMATION
Item 1—LEGAL PROCEEDINGSLegal Proceedings
PSCoPSCO is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessmentAssessment of whether a loss is probable or is a reasonable possibility, and whether thea loss or a range of loss is estimable, often involves a series of complex judgments aboutregarding future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimesmay be unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
Additional Information
See Note 69 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Part I Item 2 and Note 5 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.
further information.
Item 1A — RISK FACTORS
PSCo’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2017,2018, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.10-K. Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.