Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
Public Service Electric and Gas Company and PSEG Power LLC are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q. Each is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.
adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry,industry;
any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers, and anycustomers;
All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business, prospects, financial condition, or results of operations.operations or cash flows. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking
statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change,in light of new information or future events, unless otherwise required by applicable securities laws.
The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
This combined Quarterly Report on Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power). Information relating to any individual company is filed by such company on its own behalf. PSE&G and Power are each only responsible for information about itself and its subsidiaries.
Discussions throughout the document refer to PSEG and its direct operating subsidiaries, PSE&G and Power. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed.
See Notes to Condensed Consolidated Financial Statements.
See Notes to Condensed Consolidated Financial Statements.
See Notes to Condensed Consolidated Financial Statements.
See Notes to Condensed Consolidated Financial Statements.
See Notes to Condensed Consolidated Financial Statements.
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.
See disclosures regarding PSEG Power LLC included in the Notes to the Condensed Consolidated Financial Statements.
Note 1. Organization and Basis of Presentation
The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2015.2016.
The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2015.2016.
Note 2. Recent Accounting Standards
The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.
This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method and how they will present changes in the fair value of financial liabilities measured under the fair value option that are attributable to their own credit.method. Under the new guidance, equity investments (other than those accounted for using the equity method) will now have to be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures.
This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee wouldwill recognize a lease asset and corresponding lease obligation. A lessee wouldwill classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor wouldwill classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.
PSEG is currently analyzing the impact of this standard on its financial statements.
PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA'sLIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco'sServco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.
For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operation and Maintenance (O&M)O&M Expense, respectively. Servco recorded $98$112 million and $82$98 million for the three months ended March 31, 20162017 and 2015,2016, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG'sPSEG’s Condensed Consolidated Statement of Operations.
In addition to items previously reported in the Annual Report on Form 10-K, significant regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:
PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with solar renewable energy certificates generated from the installed solar electric system. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG'sPSEG’s and PSE&G's&G’s Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”
Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third partythird-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables on its investments over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Condensed Consolidated Balance Sheets.
The corresponding receivables associated with the lease portfolio are reflected in the following table, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings.
The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions.structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and attempt to seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital investments and trigger certain material tax obligations.obligations which could wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record aadditional pre-tax write-offwrite-offs up to its gross investment in these facilities and may also be required to pay significantmaterial cash tax liabilities to the Internal Revenue Service (IRS).Service.
Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third partythird-party investment advisersmanagers who operate under investment guidelines developed by Power.
The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.
The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months.
The proceeds from the sales of and the net realized gains on securities in the NDT Fund were:
The cost of these securities was determined on the basis of specific identification.
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”
The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.
The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:
The cost of these securities was determined on the basis of specific identification.
PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the three months ended March 31, 2017, no OTTIs were recognized on securities in the Rabbi Trust. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 3.4. Variable Interest Entities.Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.
Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco plans to contribute $28$35 million into its pension plan trusts during 2016. Servco's2017. Servco’s pension-related revenues and costs were $9 million and $6 million for each of the three months ended March 31, 2017 and 2016, and 2015.respectively. The OPEB-related revenues earned and costs incurred for each of the three months ended March 31, 20162017 were $1 million and 2015 were immaterial.immaterial for the three months ended March 31, 2016.
Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.guarantees as a form of collateral.
Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to
support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
obtain credit.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to
fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and
Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This currentCurrent exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.
As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10.11. Financial Risk Management Activities for further discussion. In accordance with PSEG'sPSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
As of March 31, 2016, PSE&G had posted $14 million in letters of credit to support various environmental obligations. PSE&G had $615 million of liquidity available under its credit facility as of March 31, 2016.
Environmental Matters
Passaic River
Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows.
Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)
In 2002, the U.S. Environmental Protection Agency (EPA) determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA.
The EPA determined that there was a need to perform a comprehensive study of the entire 17-miles17 miles of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites.
In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.
In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.
In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than with respect to their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power'sPower’s combined share of the cost of that effort is approximately three percent. The remaining CPG members, PSE&G and Power included, have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal.
On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplatedcontemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS setsets forth various alternatives for remediating this portion of the Passaic River.
The CPG, which consisted of 5352 members as of March 31, 2016,2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost for the preparation of the RI/FS is approximately $156$190 million, which the CPG continues to incur. Of the estimated $156$190 million, as of March 31, 2016,2017, the CPG had spent approximately $146$160 million, of which PSE&G's and Power's combinedPSEG’s total share was approximately $9$11 million.
The CPG'sCPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranged from approximately $518 million to $772 million. Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G's&G’s and Power'sPower’s estimated share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
In March 2016, the EPA released its Record of Decision (ROD) for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7 and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation.
Based upon the estimated cost of the ROD Remedy, PSEG'sPSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of March 31, 2016,2017, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.
Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental ChemicalsChemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, willwould voluntarily perform the remedial design for the ROD Remedy. IfOn September 30, 2016, OCC and the EPA secures aexecuted an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the Remedial Design from OCC,remedial design, it is anticipated that the EPA plans towill begin negotiation of a remedial action consent decree, under which OCC and the other “major” PRPs“major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. "Major PRP"The EPA has not defined “major PRPs.”
In June 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Maxus and Tierra are subsidiaries of YPF Holdings, Inc. (YPF Holdings). YPF Holdings is undefineda wholly owned subsidiary of YPF S.A. (YPF), a company controlled by the Argentinian government. Neither YPF Holdings nor YPF is a party to the bankruptcy proceedings. However, Tierra and Maxus have filed a plan of liquidation that may allow the parties to assert one or more causes of action to hold YPF responsible for certain amounts owed by Tierra and Maxus. PSEG cannot currently determine the impact, if any, that the bankruptcy of Tierra and Maxus or any related proceeding might have on its allocable share or total liability for the Passaic River matter, and therefore, PSEG, through the CPG and independently, will continue to monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs.
In March 2017, the EPA sent a letter to 20 PRPs, that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements in return for payments by each PRP of $280,600. The PRPs that settle will be released from their CERCLA remediation liability for the letter.lower 8.3 miles of the lower Passaic River. It is unclear how the EPA made that determination or how many PRPs will accept the proposal. The settlement is subject to a 30 day public comment period that has not yet commenced. The impact of this settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.
The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G's&G’s and Power'sPower’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G's&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG'sPSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.
Natural Resource Damage Claims
In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MGP Remediation Program
PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $434$386 million and $500$443 million through 2021, including its $46 million share for the Passaic River accrued as of March 31, 2016, as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $434$386 million as of March 31, 2016.2017. Of this amount, $90$74 million was recorded in Other Current Liabilities and $344$312 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $434$386 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.
In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.
Clean Water Act Permit Renewals
Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.
In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. On June 30, 2015, the NJDEP issued a draft permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system with certain required system modifications. The draft permit was subject to a public notice and comment period. The NJDEP may make revisions before issuing the final permit expected during the first half of 2016. Power participated in the NJDEP’s August 5, 2015 public hearing and submitted comments on the draft permit on September 18, 2015.
On May 19, 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. On August 15, 2014,
The EPA has structured the EPA established October 14, 2014 as the effective date forrule so that each state Permitting Director will continue to implement the provisions of the rule going forward when considering theconsider renewal of permits for existing
power facilities on a case by case basis. OnIn connection with the assessment of the best technology available for minimizing
adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
of studies related to impingement mortality and entrainment and submit the results with their permit applications.
In September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisionspetitions for
review of the rule. Thisrule and the case is pending athas been assigned to the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challengesAppeals (Second Circuit). Environmental
organizations, including but not limited to the endangered species act provisionsenvironmental petitioners in the Second Circuit, have also filed suit under the
Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by
mid-2017.
In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the 316 (b) rule. Power is unableClean Water Act, it requires additional studies and the selection of technology to determineaddress impingement for the ultimate impact of these actions onservice water system. In July 2016, the implementationDelaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the rule.final permit for Salem. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the Clean Water Act. Such service water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1.0 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.
Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power'sPower’s future capital requirements, financial condition or results of operations.
Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3).BH3. To address compliance with the EPA’s Clean Water Act Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the currentpreviously estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2016.2017. See Note 3. Early Plant Retirements.
Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut.Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power willmay seek to operate BH3 through the currentpreviously estimated useful life.
In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting BH5. All major environmental permits have been obtained. Operations are expected to begin in mid-2019.
Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance
In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station'sstation’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. At this early stage, Power cannot predict the impact of this matter.
Jersey City, New Jersey Subsurface Feeder Cable Matter
In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing. The investigation of the discharge and its potential cause is in the preliminary
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
stages, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the necessary repair and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs has been extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s debris removal activities are ongoing.
Steam Electric Effluent Guidelines
OnIn September 30, 2015, the EPA issued a new Effluent Limitation Guidelines Limitation Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power's Mercer andPower’s Bridgeport Harbor stationsstation and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.
In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and is acting promptly to issue an administrative stay of the compliance dates in the rule that have not yet passed pending judicial review. The deadlines that are expected to be stayed include the BAT limitations and pretreatment standards for each of the following waste streams: fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater. Power is unable to determine how this will ultimately impact compliance requirements or the financial impact it may have on the company.
Coal Combustion Residuals (CCRs)
On December 19, 2014, the EPA issued a final rule whichthat regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power'sPower’s Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third party suppliers. The first category, which represents about 80% of PSE&G's&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.
The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2016 is $335.33$276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78$335.33 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | Auction Year | | |
| | | 2013 | | 2014 | | 2015 | | 2016 | | |
| | 36-Month Terms Ending | May 2016 |
| | May 2017 |
| | May 2018 |
| | May 2019 |
| (A) | |
| | Load (MW) | 2,800 |
| | 2,800 |
| | 2,900 |
| | 2,800 |
| | |
| | $ per MWh | $92.18 | | $97.39 | | $99.54 | | $96.38 | | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | Auction Year | | |
| | | 2014 | | 2015 | | 2016 | | 2017 | | |
| | 36-Month Terms Ending | May 2017 |
| | May 2018 |
| | May 2019 |
| | May 2020 |
| (A) | |
| | Load (MW) | 2,800 |
| | 2,900 |
| | 2,800 |
| | 2,800 |
| | |
| | $ per MWh | $97.39 | | $99.54 | | $96.38 | | $90.78 | | |
| | | | | | | | | | | |
| |
| (A) | Prices set in the 20162017 BGS auction year will become effective on June 1, 20162017 when the 20132014 BGS auction agreements expire. |
Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.
PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 17.18. Related-Party Transactions.
Minimum Fuel Purchase Requirements
Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 20172018 and a significant portion through 20202021 at Salem, Hope Creek and Peach Bottom.
Power has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations.
Power also has various multi-year contracts for natural gas and firm pipeline transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess deliverypipeline capacity available beyond the needs of PSE&G's&G’s customers, Power can use the gas to make third-party sales and if excess volume remains after the third-party sales, supply its fossil generating stations.stations in New Jersey.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Power also has various long-term fuel purchase commitments for coal through 2019 to support its fossil generation stations.
As of March 31, 2016,2017, the total minimum purchase requirements included in these commitments were as follows: |
| | | | | | |
| | | | | |
| | Fuel Type | | Power's Share of Commitments through 2020 | |
| | | | Millions | |
| | Nuclear Fuel | | | |
| | Uranium | | $ | 467 |
| |
| | Enrichment | | $ | 348 |
| |
| | Fabrication | | $ | 193 |
| |
| | Natural Gas | | $ | 1,002 |
| |
| | Coal | | $ | 277 |
| |
| | | | | |
|
| | | | | | |
| | | | | |
| | Fuel Type | | Power's Share of Commitments through 2021 | |
| | | | Millions | |
| | Nuclear Fuel | | | |
| | Uranium | | $ | 301 |
| |
| | Enrichment | | $ | 359 |
| |
| | Fabrication | | $ | 192 |
| |
| | Natural Gas | | $ | 1,101 |
| |
| | Coal | | $ | 181 |
| |
| | | | | |
Regulatory Proceedings
FERC Compliance
PJM Bidding Matter
In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power continues to implementhas implemented procedures to help mitigate the risk of similar issues occurring in the future.
During the three month periodmonths ended March 31, 2014, based upon its best estimate available at the time, Power recorded a pre-tax charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time.
InSince September 2014, FERC Staff initiatedhas been conducting a preliminary, non-public staff investigation into these matters. While considerable uncertainty remains as to the final resolution of these matters, based upon recent developments in the investigation, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and issued data requests covering a period from 2002 through$135 million, depending on the datelegal interpretation of the self-report. This investigationprinciples under the PJM Tariff, plus penalties. Since no point within this range is ongoing. Since that time,more likely than any other, Power has respondedaccrued the low end of this range of $35 million by recording an additional pre-tax charge to data requests from FERC Staff, including recent data requests in whichincome of $10 million during the three months ended March 31, 2017. Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.
PSEG is unable to reasonably estimate the range of possible loss, if any, for this matter; however, the amountsquantity of potential disgorgement and other potentialenergy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power.
Power continues to believe that it has legal defenses that it may incur spanassert in a wide range depending onjudicial challenge, including the success of PSEG's legal arguments. These arguments includedefense that Power’s energy market bidsits cost-based bidding in a substantial majority of the hours werewas below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial and thatimmaterial. Furthermore, it is unclear whether the quantity of the bidsenergy offered violated any legal requirement. If PSEG's legal arguments do not prevailAs a result, PSEG and Power cannot predict the final outcome of these matters.
Financial Transmission Rights (FTR) Auction Matter
In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in whole orthe annual FTR auction in partPJM for the 2016-2017 planning year and the monthly FTR auctions in PJM for February, March and April 2016. PSEG is cooperating with FERC or in ajudicial challengethis matter. PSEG cannot predict the outcome of this matter at this time.
Note 10. Debt and Credit Facilities
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
In March 2017, PSEG, Power and PSE&G amended their credit agreements, extending the expiration dates to March 2022. Concurrently, PSEG increased its existing $1 billion in credit facilities to $1.5 billion, Power decreased its existing $2.6 billion in credit facilities to $2.1 billion, which includes two new 3-year $100 million letter of credit facilities that PSEG may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to PSEG’s and Power’s Consolidated Statementsexpire in March 2020.
The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of OperationsMarch 31, 2017, the total available credit capacity was $3.6 billion.
As of March 31, 2017, no single institution represented more than 8% of the total commitments in the quarterly and annual periodscredit facilities.
As of March 31, 2017, the total credit capacity was in which they are recorded.
Nuclear Insurance Coverages
The following should be read in conjunction with Note 12. Commitments and Contingent Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.
Based upon a reviewexcess of its nuclear insurance, Power made changes to its Nuclear Electric Insurance Limited (NEIL) insurance coverage of the excess layer for property damage which became effective on April 1, 2016. The excess layer provides coverage above the primary layer of NEIL insurance coverage for property damage of $1.5 billion. For the excess layer at the Salem/Hope Creek site, Power purchased coverage for property damage of $300 million due to a nuclear event and $300 million due to a non-nuclear event. For the excess layer at the Peach Bottom site, Power purchased coverage for its ownership interest for property damage of $300 million due to a nuclear event. For the excess layer at the Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ownership interest of Power. anticipated maximum liquidity requirements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of March 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | As of March 31, 2017 | | | | | |
| | Company/Facility | | Total Facility | | Usage | | Available Liquidity | | Expiration Date | | Primary Purpose | |
| | | | Millions | | | | | |
| | PSEG | | | | | | | | | | | |
| | 5-year Credit Facilities (A) | | $ | 1,500 |
| | $ | 332 |
| | $ | 1,168 |
| | Mar 2022 | | Commercial Paper Support/Funding/Letters of Credit | |
| | Total PSEG | | $ | 1,500 |
| | $ | 332 |
| | $ | 1,168 |
| | | | | |
| | PSE&G | | | | | | | | | | | |
| | 5-year Credit Facility (A) | | $ | 600 |
| | $ | 14 |
| | $ | 586 |
| | Mar 2022 | | Commercial Paper Support/Funding/Letters of Credit | |
| | Total PSE&G | | $ | 600 |
| | $ | 14 |
| | $ | 586 |
| | | | | |
| | Power | | | | | | | | | | | |
| | 3-year LC Facilities | | $ | 200 |
| | $ | 137 |
| | $ | 63 |
| | Mar 2020 | | Letters of Credit | |
| | 5-year Credit Facilities | | 1,900 |
| | 98 |
| | 1,802 |
| | Mar 2022 | | Funding/Letters of Credit | |
| | Total Power | | $ | 2,100 |
| | $ | 235 |
| | $ | 1,865 |
| | | | | |
| | Total | | $ | 4,200 |
| | $ | 581 |
| | $ | 3,619 |
| | | | | |
| | | | | | | | | | | | | |
(A)The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs,
under which as of March 31, 2017, PSEG had $315 million outstanding at a weighted average interest rate of 1.25%. As of March 31, 2017, PSE&G had no amounts outstanding under its Commercial Paper Program.
Note 9. Changes in Capitalization
The following capital transactions occurred in the three months ended March 31, 2016:
PSE&G
issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021,
issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046, and
retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds, Series VV at maturity.
Note 10.11. Financial Risk Management Activities
The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchasepurchases and normal salesales (NPNS), cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. Transactions receiving NPNS treatmentPSEG uses interest rate swaps and other derivatives, which are accounted for upon settlement. For a derivative instrument that qualifiesdesignated and is designatedeffective as a cash flow hedge, the changes in theor fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period.hedges. Power and PSE&G enter into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value.
Commodity Prices
Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. PSEG had no commodity derivative transactions designatedsuch as cash flow or fair value hedges as of March 31, 2016 and December 31, 2015.
Economic Hedges
Power enters into derivative contracts that are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intendedelectricity, to mitigatemanage the exposure to fluctuations in commodity prices and optimize the value of Power'sPower’s expected generation. Changes in the fair market value of thesethe derivative contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract tooptimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Interest Rates
PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of March 31, 2016, PSEG had interest rate swaps outstanding totaling $550 million. These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective asThe changes in fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. AsThere were no outstanding interest rate swaps as of March 31, 2016 and2017 or December 31, 2015, the2016. The fair value of all the underlying hedges was $4 million and $6 million, respectively. The effect of these hedges was to reducereduced interest expense by $2 million and $5 million for the three months ended March 31, 2016 and 2015, respectively.2016.
Cash Flow Hedges
PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of March 31, 2017 and December 31, 2016, PSEG had interest rate hedges outstanding totaling $900$500 million. The hedge ineffectiveness associated with theseThese hedges was immaterial. The totalconvert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of March 31, 2017 and December 31, 2016, the fair value of these interest rate hedges was $3$2 million and $1 million, respectively. There was no ineffectiveness as of March 31, 2016. There were no outstanding interest rate hedges as of2017 and December 31, 2015. 2016.
The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of March 31, 20162017 and was immaterial as of December 31, 2015.2016. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is $1 million.
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG'sPSEG’s accounting policy, these positions have beenare offset on the Condensed Consolidated Balance Sheets of Power PSE&G and PSEG.
The following tabular disclosure does not include the offsetting of trade receivables and payables.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | As of March 31, 2016 | |
| | | | Power (A) | | PSE&G (A) | | PSEG (A) | | Consolidated | |
| | | | Not Designated | | | | | | Not Designated | | Designated as Hedges | | | |
| | Balance Sheet Location | | Energy- Related Contracts | | Netting (B) | | Total Power | | Energy- Related Contracts | | Interest Rate Swaps | | Total Derivatives | |
| | | | Millions | |
| | Derivative Contracts | | | | | | | | | | | | | |
| | Current Assets | | $ | 718 |
| | $ | (500 | ) | | $ | 218 |
| | $ | 8 |
| | $ | 4 |
| | $ | 230 |
| |
| | Noncurrent Assets | | 346 |
| | (219 | ) | | 127 |
| | 2 |
| | 4 |
| | 133 |
| |
| | Total Mark-to-Market Derivative Assets | | $ | 1,064 |
| | $ | (719 | ) | | $ | 345 |
| | $ | 10 |
| | $ | 8 |
| | $ | 363 |
| |
| | Derivative Contracts | | | | | | | | | | | | | |
| | Current Liabilities | | $ | (533 | ) | | $ | 481 |
| | $ | (52 | ) | | $ | — |
| | $ | (1 | ) | | $ | (53 | ) | |
| | Noncurrent Liabilities | | (218 | ) | | 204 |
| | (14 | ) | | — |
| | — |
| | (14 | ) | |
| | Total Mark-to-Market Derivative (Liabilities) | | $ | (751 | ) | | $ | 685 |
| | $ | (66 | ) | | $ | — |
| | $ | (1 | ) | | $ | (67 | ) | |
| | Total Net Mark-to-Market Derivative Assets (Liabilities) | | $ | 313 |
| | $ | (34 | ) | | $ | 279 |
| | $ | 10 |
| | $ | 7 |
| | $ | 296 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | As of March 31, 2017 | |
| | | | Power (A) | | PSE&G (A) | | PSEG (A) | | Consolidated | |
| | | | Not Designated | | | | | | Not Designated | | Designated as Hedges | | | |
| | Balance Sheet Location | | Energy- Related Contracts | | Netting (B) | | Total Power | | Energy- Related Contracts | | Interest Rate Swaps | | Total Derivatives | |
| | | | Millions | |
| | Derivative Contracts | | | | | | | | | | | | | |
| | Current Assets | | $ | 525 |
| | $ | (414 | ) | | $ | 111 |
| | $ | 1 |
| | $ | 2 |
| | $ | 114 |
| |
| | Noncurrent Assets | | 264 |
| | (171 | ) | | 93 |
| | — |
| | — |
| | 93 |
| |
| | Total Mark-to-Market Derivative Assets | | $ | 789 |
| | $ | (585 | ) | | $ | 204 |
| | $ | 1 |
| | $ | 2 |
| | $ | 207 |
| |
| | Derivative Contracts | | | | | | | | | | | | | |
| | Current Liabilities | | $ | (425 | ) | | $ | 418 |
| | $ | (7 | ) | | $ | — |
| | $ | — |
| | $ | (7 | ) | |
| | Noncurrent Liabilities | | (168 | ) | | 167 |
| | (1 | ) | | — |
| | — |
| | (1 | ) | |
| | Total Mark-to-Market Derivative (Liabilities) | | $ | (593 | ) | | $ | 585 |
| | $ | (8 | ) | | $ | — |
| | $ | — |
| | $ | (8 | ) | |
| | Total Net Mark-to-Market Derivative Assets (Liabilities) | | $ | 196 |
| | $ | — |
| | $ | 196 |
| | $ | 1 |
| | $ | 2 |
| | $ | 199 |
| |
| | | | | | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | As of December 31, 2015 | |
| | | | Power (A) | | PSE&G (A) | | PSEG (A) | | Consolidated | |
| | | | Not Designated | | | | | | Not Designated | | Designated as Hedges | | | |
| | Balance Sheet Location | | Energy- Related Contracts | | Netting (B) | | Total Power | | Energy- Related Contracts | | Interest Rate Swaps | | Total Derivatives | |
| | | | Millions | |
| | Derivative Contracts | | | | | | | | | | | | | |
| | Current Assets | | $ | 700 |
| | $ | (477 | ) | | $ | 223 |
| | $ | 13 |
| | $ | 6 |
| | $ | 242 |
| |
| | Noncurrent Assets | | 208 |
| | (131 | ) | | 77 |
| | — |
| | — |
| | 77 |
| |
| | Total Mark-to-Market Derivative Assets | | $ | 908 |
| | $ | (608 | ) | | $ | 300 |
| | $ | 13 |
| | $ | 6 |
| | $ | 319 |
| |
| | Derivative Contracts | | | | | | | | | | | | | |
| | Current Liabilities | | $ | (513 | ) | | $ | 437 |
| | $ | (76 | ) | | $ | — |
| | $ | — |
| | $ | (76 | ) | |
| | Noncurrent Liabilities | | (132 | ) | | 116 |
| | (16 | ) | | (11 | ) | | — |
| | (27 | ) | |
| | Total Mark-to-Market Derivative (Liabilities) | | $ | (645 | ) | | $ | 553 |
| | $ | (92 | ) | | $ | (11 | ) | | $ | — |
| | $ | (103 | ) | |
| | Total Net Mark-to-Market Derivative Assets (Liabilities) | | $ | 263 |
| | $ | (55 | ) | | $ | 208 |
| | $ | 2 |
| | $ | 6 |
| | $ | 216 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | As of December 31, 2016 | |
| | | | Power (A) | | PSE&G (A) | | PSEG (A) | | Consolidated | |
| | | | Not Designated | | | | | | Not Designated | | Designated as Hedges | | | |
| | Balance Sheet Location | | Energy- Related Contracts | | Netting (B) | | Total Power | | Energy- Related Contracts | | Interest Rate Swaps | | Total Derivatives | |
| | | | Millions | |
| | Derivative Contracts | | | | | | | | | | | | | |
| | Current Assets | | $ | 435 |
| | $ | (273 | ) | | $ | 162 |
| | $ | — |
| | $ | 1 |
| | $ | 163 |
| |
| | Noncurrent Assets | | 122 |
| | (98 | ) | | 24 |
| | — |
| | — |
| | 24 |
| |
| | Total Mark-to-Market Derivative Assets | | $ | 557 |
| | $ | (371 | ) | | $ | 186 |
| | $ | — |
| | $ | 1 |
| | $ | 187 |
| |
| | Derivative Contracts | | | | | | | | | | | | | |
| | Current Liabilities | | $ | (285 | ) | | $ | 277 |
| | $ | (8 | ) | | $ | (5 | ) | | $ | — |
| | $ | (13 | ) | |
| | Noncurrent Liabilities | | (98 | ) | | 95 |
| | (3 | ) | | — |
| | — |
| | (3 | ) | |
| | Total Mark-to-Market Derivative (Liabilities) | | $ | (383 | ) | | $ | 372 |
| | $ | (11 | ) | | $ | (5 | ) | | $ | — |
| | $ | (16 | ) | |
| | Total Net Mark-to-Market Derivative Assets (Liabilities) | | $ | 174 |
| | $ | 1 |
| | $ | 175 |
| | $ | (5 | ) | | $ | 1 |
| | $ | 171 |
| |
| | | | | | | | | | | | | | | |
| |
| (A) | Substantially all of Power'sPower’s and PSEG'sPSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of March 31, 20162017 and December 31, 2015.2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements. |
| |
| (B) | Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Condensed Consolidated Balance Sheets. As of March 31, 20162017 net cash collateral (received) paid was netted against the corresponding net derivative contract positions with $(4) million of cash collateral netted against noncurrent assets, and $4 million netted against current liabilities. As of December 31, 2015,2016, net cash collateral (received) paid of $(34)$1 million and $(55) million, respectively, werewas netted against the corresponding net derivative contract positions. Of the $(34)$1 million as of MarchDecember 31, 2016, $(37)$(3) million and $(16) million of cash collateral werewas netted against currentnoncurrent assets and noncurrent assets, respectively, and $19$4 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively. |
Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.
The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $62$13 million and $78$19 million as of March 31, 20162017 and December 31, 2015,2016, respectively. As of March 31, 20162017 and December 31, 2015,2016, Power had the contractual right of offset of $16$7 million and $12$9 million, respectively, related to derivative instruments that are assets with the same counterparty under agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $46$6 million and $66$10 million as of March 31, 20162017 and December 31, 2015,2016, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $851 million and $864 million as of March 31, 2016 and December 31, 2015, respectively, discussed in Note 8. Commitments and Contingent Liabilities.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended March 31, 20162017 and 2015.2016. |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | Derivatives in Cash Flow Hedging Relationships | | Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) | | Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income | | Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion) | |
| | | Three Months Ended | | | | Three Months Ended | |
| | | March 31, | | | | March 31, | |
| | | 2017 | | 2016 | | | | 2017 | | 2016 | |
| | | | Millions | | | | Millions | |
| | PSEG | | | | | | | | | | | |
| | Interest Rate Swaps | | — |
| | 3 |
| | Interest Expense | | — |
| | — |
| |
| | Total PSEG | | $ | — |
| | $ | 3 |
| | | | $ | — |
| | $ | — |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | Derivatives in Cash Flow Hedging Relationships | | Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) | | Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income | | Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion) | | Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) | | Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) | |
| | | Three Months Ended | | | | Three Months Ended | | | | Three Months Ended | |
| | | March 31, | | | | March 31, | | | | March 31, | |
| | | 2016 | | 2015 | | | | 2016 | | 2015 | | | | 2016 | | 2015 | |
| | | | Millions | |
| | PSEG | | | | | | | | | | | | | | | | | |
| | Energy-Related Contracts | | $ | — |
| | $ | 1 |
| | Operating Revenues | | $ | — |
| | $ | 17 |
| | Operating Revenues | | $ | — |
| | $ | — |
| |
| | Interest Rate Swaps | | 3 |
| | — |
| | Interest Expense | | — |
| | — |
| | Interest Expense | | — |
| | — |
| |
| | Total PSEG | | $ | 3 |
| | $ | 1 |
| | | | $ | — |
| | $ | 17 |
| | | | $ | — |
| | $ | — |
| |
| | Power | | | | | | | | | | | | | | | | | |
| | Energy-Related Contracts | | $ | — |
| | $ | 1 |
| | Operating Revenues | | $ | — |
| | $ | 17 |
| | Operating Revenues | | $ | — |
| | $ | — |
| |
| | Total Power | | $ | — |
| | $ | 1 |
| | | | $ | — |
| | $ | 17 |
| | | | $ | — |
| | $ | — |
| |
| | | | | | | | | | | | | | | | | | | |
The following reconciles the Accumulated Other Comprehensive IncomeAOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis. |
| | | | | | | | | | | |
| | | | | | | |
| | Accumulated Other Comprehensive Income | | Pre-Tax | | After-Tax | |
| | | | Millions | |
| | Balance as of December 31, 2014 | | $ | 17 |
| | $ | 10 |
|
|
| | Gain Recognized in AOCI | | 3 |
| | 2 |
| |
| | Less: Gain Reclassified into Income | | (20 | ) | | (12 | ) | |
| | Balance as of December 31, 2015 | | $ | — |
| | $ | — |
| |
| | Gain Recognized in AOCI | | 3 |
| — |
| 2 |
| |
| | Less: Gain Reclassified into Income | | — |
| | — |
| |
| | Balance as of March 31, 2016 | | $ | 3 |
| | $ | 2 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | Accumulated Other Comprehensive Income | | Pre-Tax | | After-Tax | |
| | | | Millions | |
| | Balance as of December 31, 2015 | | $ | — |
| | $ | — |
| |
| | Gain Recognized in AOCI | | 3 |
| | 2 |
| |
| | Less: Gain Reclassified into Income | | — |
| | — |
| |
| | Balance as of December 31, 2016 | | $ | 3 |
| | $ | 2 |
| |
| | Gain Recognized in AOCI | | — |
| | — |
| |
| | Less: Gain Reclassified into Income | | — |
| | — |
| |
| | Balance as of March 31, 2017 | | $ | 3 |
| | $ | 2 |
| |
| | | | | | | |
The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months ended March 31, 20162017 and 2015. |
| | | | | | | | | | | | |
| | | | | | | | | |
| | Derivatives Not Designated as Hedges | | Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives | Pre-Tax Gain (Loss) Recognized in Income on Derivatives | |
| | | | | | Three Months Ended | |
| | | | | | March 31, | |
| | | | | | 2016 | | 2015 | |
| | | | | Millions | |
| | PSEG and Power | | | | | | | |
| | Energy-Related Contracts | | Operating Revenues | | $ | 216 |
| | $ | (76 | ) | |
| | Energy-Related Contracts | | Energy Costs | | 2 |
| | 10 |
| |
| | Total PSEG and Power | | | | $ | 218 |
| | $ | (66 | ) | |
| | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2016. Power’s derivative contracts reflected in the preceding tablesthis table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The tables above dotable does not include contracts for which Power has elected thedesignated as NPNS, exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.
|
| | | | | | | | | | | | |
| | | | | | | | | |
| | Derivatives Not Designated as Hedges | | Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives | | Pre-Tax Gain (Loss) Recognized in Income on Derivatives | |
| | | | | | Three Months Ended | |
| | | | | | March 31, | |
| | | | | | 2017 | | 2016 | |
| | | | | Millions | |
| | PSEG and Power | | | | | | | |
| | Energy-Related Contracts | | Operating Revenues | | $ | 83 |
| | $ | 216 |
| |
| | Energy-Related Contracts | | Energy Costs | | (5 | ) | | 2 |
| |
| | Total PSEG and Power | | | | $ | 78 |
| | $ | 218 |
| |
| | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The following reflects the gross volume, on an absolute value basis, of derivatives as of March 31, 20162017 and December 31, 2015.2016.
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | Type | | Notional | | Total | | PSEG | | Power | | PSE&G | |
| | | | | | Millions | |
| | As of March 31, 2016 | | | | | | | | | | | |
| | Natural Gas | | Dekatherm (Dth) | | 298 |
| | — |
| | 272 |
| | 26 |
| |
| | Electricity | | MWh | | 303 |
| | — |
| | 303 |
| | — |
| |
| | Financial Transmission Rights (FTRs) | | MWh | | 14 |
| | — |
| | 14 |
| | — |
| |
| | Interest Rate Swaps | | U.S. Dollars | | 1,450 |
| | 1,450 |
| | — |
| | — |
| |
| | As of December 31, 2015 | | | | | | | | | | | |
| | Natural Gas | | Dth | | 201 |
| | — |
| | 168 |
| | 33 |
| |
| | Electricity | | MWh | | 299 |
| | — |
| | 299 |
| | — |
| |
| | FTRs | | MWh | | 23 |
| | — |
| | 23 |
| | — |
| |
| | Interest Rate Swaps | | U.S. Dollars | | 550 |
| | 550 |
| | — |
| | — |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | Type | | Notional | | Total | | PSEG | | Power | | PSE&G | |
| | | | | | Millions | |
| | As of March 31, 2017 | | | | | | | | | | | |
| | Natural Gas | | Dekatherm (Dth) | | 357 |
| | — |
| | 355 |
| | 2 |
| |
| | Electricity | | MWh | | 346 |
| | — |
| | 346 |
| | — |
| |
| | Financial Transmission Rights (FTRs) | | MWh | | 5 |
| | — |
| | 5 |
| | — |
| |
| | Interest Rate Swaps | | U.S. Dollars | | 500 |
| | 500 |
| | — |
| | — |
| |
| | As of December 31, 2016 | | | | | | | | | | | |
| | Natural Gas | | Dth | | 357 |
| | — |
| | 348 |
| | 9 |
| |
| | Electricity | | MWh | | 323 |
| | — |
| | 323 |
| | — |
| |
| | FTRs | | MWh | | 9 |
| | — |
| | 9 |
| | — |
| |
| | Interest Rate Swaps | | U.S. Dollars | | 500 |
| | 500 |
| | — |
| | — |
| |
| | | | | | | | | | | | | |
Credit Risk
Credit risk relates to the risk of loss that wePower would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We havePSEG has established credit policies that we believeit believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.
As of March 31, 2016, 91%2017, 98% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives and normal purchases/normal sales)non-derivatives).
The following table provides information on Power’s credit risk from others, net of cash collateral, as of March 31, 2016.2017. It further delineates that exposure by the credit rating of the counterparties, andwhich is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | Rating | | Current Exposure | | Securities Held as Collateral | | Net Exposure | | Number of Counterparties >10% | | Net Exposure of Counterparties >10% | | |
| | | | Millions | | | | Millions | | |
| | Investment Grade—External Rating | | $ | 542 |
| | $ | 230 |
| | $ | 312 |
| | 1 |
| | $ | 178 |
| (A) | |
| | Non-Investment Grade—External Rating | | 30 |
| | — |
| | 30 |
| | — |
| | — |
| | |
| | Investment Grade—No External Rating | | 10 |
| | 1 |
| | 9 |
| | — |
| | — |
| | |
| | Non-Investment Grade—No External Rating | | — |
| | — |
| | — |
| | — |
| | — |
| | |
| | Total | | $ | 582 |
| | $ | 231 |
| | $ | 351 |
| | 1 |
| | $ | 178 |
| | |
| | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | Rating | | Current Exposure | | Securities Held as Collateral | | Net Exposure | | Number of Counterparties >10% | | Net Exposure of Counterparties >10% | | |
| | | | Millions | | | | Millions | �� | |
| | Investment Grade | | $ | 433 |
| | $ | 94 |
| | $ | 339 |
| | 1 |
| | $ | 202 |
| (A) | |
| | Non-Investment Grade | | 9 |
| | 1 |
| | 8 |
| | — |
| | — |
| | |
| | Total | | $ | 442 |
| | $ | 95 |
| | $ | 347 |
| | 1 |
| | $ | 202 |
| | |
| | | | | | | | | | | | | | |
| |
| (A) | Represents net exposure of $202 million with PSE&G. |
As of March 31, 2016,2017, collateral held from counterparties where Power had credit exposure included $16$1 million in cash collateral and $215$94 million in letters of credit.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
As of March 31, 20162017, Power had 137159 active counterparties.
PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of March 31, 2016,2017, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G's&G’s BGS suppliers’ credit exposure is calculated each business day. As of March 31, 2016,2017, PSE&G had no net credit exposure with suppliers, including Power.
PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.
Note 11.12. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds.funds, as well as natural gas futures contracts executed on NYMEX.
Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of March 31, 2016,2017, these consisted primarily of long-term gas supply contracts and certain electric load contracts and gas contracts.
Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.
The following tables present information about PSEG’s, PSE&G’s and Power'sPower’s respective assets and (liabilities) measured at fair value on a recurring basis as of March 31, 20162017 and December 31, 2015,2016, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | Recurring Fair Value Measurements as of March 31, 2017 | |
| | Description | | Total | |
Netting (E) | | Quoted Market Prices for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
| | | | Millions | |
| | PSEG | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Cash Equivalents (A) | | $ | 125 |
| | $ | — |
| | $ | 125 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 205 |
| | $ | (585 | ) | | $ | 11 |
| | $ | 774 |
| | $ | 5 |
| |
| | Interest Rate Swaps (C) | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | — |
| |
| | NDT Fund (D) | | | | | | | | | | | |
| | Equity Securities | | $ | 1,007 |
| | $ | — |
| | $ | 1,005 |
| | $ | 2 |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 223 |
| | $ | — |
| | $ | — |
| | $ | 223 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 294 |
| | $ | — |
| | $ | — |
| | $ | 294 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 343 |
| | $ | — |
| | $ | — |
| | $ | 343 |
| | $ | — |
| |
| | Other Securities | | $ | 46 |
| | $ | — |
| | $ | 46 |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 22 |
| | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 36 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 62 |
| | $ | — |
| | $ | — |
| | $ | 62 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 99 |
| | $ | — |
| | $ | — |
| | $ | 99 |
| | $ | — |
| |
| | Other Securities | | $ | 2 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (8 | ) | | $ | 585 |
| | $ | (6 | ) | | $ | (585 | ) | | $ | (2 | ) | |
| | Interest Rate Swaps (C) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | PSE&G | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Cash Equivalents (A) | | $ | 125 |
| | $ | — |
| | $ | 125 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 12 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | — |
| |
| | Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | Power | |
| | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 204 |
| | $ | (585 | ) | | $ | 11 |
| | $ | 774 |
| | $ | 4 |
| |
| | NDT Fund (D) | | | | | | | | | | | |
| | Equity Securities | | $ | 1,007 |
| | $ | — |
| | $ | 1,005 |
| | $ | 2 |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 223 |
| | $ | — |
| | $ | — |
| | $ | 223 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 294 |
| | $ | — |
| | $ | — |
| | $ | 294 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 343 |
| | $ | — |
| | $ | — |
| | $ | 343 |
| | $ | — |
| |
| | Other Securities | | $ | 46 |
| | $ | — |
| | $ | 46 |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 6 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 25 |
| | $ | — |
| | $ | — |
| | $ | 25 |
| | $ | — |
| |
| | Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (8 | ) | | $ | 585 |
| | $ | (6 | ) | | $ | (585 | ) | | $ | (2 | ) | |
| | | | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | Recurring Fair Value Measurements as of March 31, 2016 | |
| | Description | | Total | |
Netting (E) | | Quoted Market Prices for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
| | | | Millions | |
| | PSEG | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Cash Equivalents (A) | | $ | 521 |
| | $ | — |
| | $ | 521 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 355 |
| | $ | (719 | ) | | $ | — |
| | $ | 1,053 |
| | $ | 21 |
| |
| | Interest Rate Swaps (C) | | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
| | $ | — |
| |
| | NDT Fund (D) | | | | | | | | | | | |
| | Equity Securities | | $ | 872 |
| | $ | — |
| | $ | 872 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 502 |
| | $ | — |
| | $ | — |
| | $ | 502 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 372 |
| | $ | — |
| | $ | — |
| | $ | 372 |
| | $ | — |
| |
| | Other Securities | | $ | 32 |
| | $ | — |
| | $ | 32 |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 20 |
| | $ | — |
| | $ | 20 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 109 |
| | $ | — |
| | $ | — |
| | $ | 109 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 83 |
| | $ | — |
| | $ | — |
| | $ | 83 |
| | $ | — |
| |
| | Other Securities | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (66 | ) | | $ | 685 |
| | $ | — |
| | $ | (751 | ) | | $ | — |
| |
| | Interest Rate Swaps (C) | | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) | | $ | — |
| |
| | PSE&G | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Cash Equivalents (A) | | $ | 521 |
| | $ | — |
| | $ | 521 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 10 |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 4 |
| | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | — |
| |
| | Other Securities | | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | Power | |
| | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 345 |
| | $ | (719 | ) | | $ | — |
| | $ | 1,053 |
| | $ | 11 |
| |
| | NDT Fund (D) | | | | | | | | | | | |
| | Equity Securities | | $ | 872 |
| | $ | — |
| | $ | 872 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 502 |
| | $ | — |
| | $ | — |
| | $ | 502 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 372 |
| | $ | — |
| | $ | — |
| | $ | 372 |
| | $ | — |
| |
| | Other Securities | | $ | 32 |
| | $ | — |
| | $ | 32 |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 27 |
| | $ | — |
| | $ | — |
| | $ | 27 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | — |
| |
| | Other Securities | | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (66 | ) | | $ | 685 |
| | $ | — |
| | $ | (751 | ) | | $ | — |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | Recurring Fair Value Measurements as of December 31, 2016 | |
| | Description | | Total | | Netting (E) | | Quoted Market Prices for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
| | | | Millions | |
| | PSEG | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Cash Equivalents (A) | | $ | 365 |
| | $ | — |
| | $ | 365 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 186 |
| | $ | (371 | ) | | $ | 17 |
| | $ | 533 |
| | $ | 7 |
| |
| | Interest Rate Swaps (C) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| |
| | NDT Fund (D) | | | | | | | | | | | |
| | Equity Securities | | $ | 957 |
| | $ | — |
| | $ | 954 |
| | $ | 3 |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 227 |
| | $ | — |
| | $ | — |
| | $ | 227 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 293 |
| | $ | — |
| | $ | — |
| | $ | 293 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 337 |
| | $ | — |
| | $ | — |
| | $ | 337 |
| | $ | — |
| |
| | Other Securities | | $ | 44 |
| | $ | — |
| | $ | 44 |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 22 |
| | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 37 |
| | $ | — |
| | $ | — |
| | $ | 37 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 66 |
| | $ | — |
| | $ | — |
| | $ | 66 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 91 |
| | $ | — |
| | $ | — |
| | $ | 91 |
| | $ | — |
| |
| | Other Securities | | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (16 | ) | | $ | 372 |
| | $ | (18 | ) | | $ | (364 | ) | | $ | (6 | ) | |
| | PSE&G | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Cash Equivalents (A) | | $ | 365 |
| | $ | — |
| | $ | 365 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy Related Contracts (B) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | — |
| |
| | Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (5 | ) | |
| | Power | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 186 |
| | $ | (371 | ) | | $ | 17 |
| | $ | 533 |
| | $ | 7 |
| |
| | NDT Fund (D) | | | | | | | | | | | |
| | Equity Securities | | $ | 957 |
| | $ | — |
| | $ | 954 |
| | $ | 3 |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 227 |
| | $ | — |
| | $ | — |
| | $ | 227 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 293 |
| | $ | — |
| | $ | — |
| | $ | 293 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 337 |
| | $ | — |
| | $ | — |
| | $ | 337 |
| | $ | — |
| |
| | Other Securities | | $ | 44 |
| | $ | — |
| | $ | 44 |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—US Treasury | | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| | $ | — |
| |
| | Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (11 | ) | | $ | 372 |
| | $ | (18 | ) | | $ | (364 | ) | | $ | (1 | ) | |
| | | | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | Recurring Fair Value Measurements as of December 31, 2015 | |
| | Description | | Total | | Netting (E) | | Quoted Market Prices for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
| | | | Millions | |
| | PSEG | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Cash Equivalents (A) | | $ | 326 |
| | $ | — |
| | $ | 326 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 313 |
| | $ | (608 | ) | | $ | — |
| | $ | 896 |
| | $ | 25 |
| |
| | Interest Rate Swaps (C) | | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | — |
| |
| | NDT Fund (D) | | | | | | | | | | | |
| | Equity Securities | | $ | 865 |
| | $ | — |
| | $ | 865 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 488 |
| | $ | — |
| | $ | — |
| | $ | 488 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 359 |
| | $ | — |
| | $ | — |
| | $ | 359 |
| | $ | — |
| |
| | Other Securities | | $ | 42 |
| | $ | — |
| | $ | 42 |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 22 |
| | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 108 |
| | $ | — |
| | $ | — |
| | $ | 108 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 81 |
| | $ | — |
| | $ | — |
| | $ | 81 |
| | $ | — |
| |
| | Other Securities | | $ | 2 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (103 | ) | | $ | 553 |
| | $ | — |
| | $ | (644 | ) | | $ | (12 | ) | |
| | PSE&G | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Cash Equivalents (A) | | $ | 160 |
| | $ | — |
| | $ | 160 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy Related Contracts (B) | | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 13 |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | — |
| |
| | Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (11 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (11 | ) | |
| | Power | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 300 |
| | $ | (608 | ) | | $ | — |
| | $ | 896 |
| | $ | 12 |
| |
| | NDT Fund (D) | | | | | | | | | | | |
| | Equity Securities | | $ | 865 |
| | $ | — |
| | $ | 865 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 488 |
| | $ | — |
| | $ | — |
| | $ | 488 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 359 |
| | $ | — |
| | $ | — |
| | $ | 359 |
| | $ | — |
| |
| | Other Securities | | $ | 42 |
| | $ | — |
| | $ | 42 |
| | $ | — |
| | $ | — |
| |
| | Rabbi Trust (D) | | | | | | | | | | | |
| | Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—Govt Obligations | | $ | 26 |
| | $ | — |
| | $ | — |
| | $ | 26 |
| | $ | — |
| |
| | Debt Securities—Other | | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | — |
| |
| | Other Securities | | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (92 | ) | | $ | 553 |
| | $ | — |
| | $ | (644 | ) | | $ | (1 | ) | |
| | | | | | | | | | | | | |
| |
| (A) | Represents money market mutual funds. |
| |
| (B) | Level 2—Fair values for1— During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) arebeing valued usingsolely on settled pricing inputs which come directly from the average of the bid/askexchange. |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
midpointsLevel 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from multiple broker or dealer quotesan exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.
Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.
| |
| (C) | Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. |
| |
| (D) | The fair value measurement tables exclude an immaterial amount of cash as of March 31, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500a Russell 3000 index fund and various fixed income securities classified as “available for sale.”sale” as of March 31, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). |
Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.
Level 2—NDT and Rabbi Trust fixed income securities are limited toinclude investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.
| |
| (E) | Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of March 31, 2017, $(4) million of cash collateral was netted against assets, and $4 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of $(34)$1 million was netted against the corresponding net derivative contract positions. Of the $(34) million as of March 31, 2016, $(53) million of cash collateral was netted against assets, and $19 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55)$1 million of cash collateral as of December 31, 2015, $(69)2016, $(3) million was netted against assets, and $14$4 million was netted against liabilities. |
Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Corporate Governance and Audit CommitteeCommittees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
For PSE&G, the natural gas supply contracts arecontract is measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power'sPower’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of March 31, 20162017 and December 31, 2015.2016.
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Quantitative Information About Level 3 Fair Value Measurements | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | Significant | | | |
| | | | | | Fair Value as of | | Valuation | | Unobservable | | | |
| | Commodity | | Level 3 Position | | March 31, 2016 | | Technique(s) | | Input | | Range | |
| | | | | | Assets | | (Liabilities) | | | | | | | |
| | | | | | Millions | | | | | | | |
| | PSE&G | | | | | | | | | | | | | |
| | Gas | | Natural Gas Supply Contracts | | $ | 10 |
| | $ | — |
| | Discounted Cash Flow | | Transportation Costs | | $0.60 to $0.80/Dth | |
| | Total PSE&G | | | | $ | 10 |
| | $ | — |
| | | | | | | |
| | Power | | | | | | | | | | | | | |
| | Electricity | | Electric Load Contracts | | $ | 11 |
| | $ | — |
| | Discounted Cash flow | | Historic Load Variability | | 0% to +10% | |
| | Total Power | | | | $ | 11 |
| | $ | — |
| | | | | | | |
| | Total PSEG | | | | $ | 21 |
| | $ | — |
| | | | | | | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Quantitative Information About Level 3 Fair Value Measurements | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | Significant | | | |
| | | | | | Fair Value as of | | Valuation | | Unobservable | | | |
| | Commodity | | Level 3 Position | | March 31, 2017 | | Technique(s) | | Input | | Range | |
| | | | | | Assets | | (Liabilities) | | | | | | | |
| | | | | | Millions | | | | | | | |
| | PSE&G | | | | | | | | | | | | | |
| | Gas | | Natural Gas Supply Contract | | $ | 1 |
| | $ | — |
| | Discounted Cash Flow | | Transportation Costs | | $0.60 to $0.80/Dth | |
| | Total PSE&G | | | | $ | 1 |
| | $ | — |
| | | | | | | |
| | Power | | | | | | | | | | | | | |
| | Electricity | | Electric Load Contracts | | $ | 4 |
| | $ | (2 | ) | | Discounted Cash flow | | Historic Load Variability | | 0% to +10% | |
| | Gas (A) | | Other | | — |
| | — |
| | | | | | | |
| | Total Power | | | | $ | 4 |
| | $ | (2 | ) | | | | | | | |
| | Total PSEG | | | | $ | 5 |
| | $ | (2 | ) | | | | | | | |
| | | | | | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Quantitative Information About Level 3 Fair Value Measurements | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | Significant | | | |
| | | | | | Fair Value as of | | Valuation | | Unobservable | | | |
| | Commodity | | Level 3 Position | | December 31, 2015 | | Technique(s) | | Input | | Range | |
| | | | | | Assets | | (Liabilities) | | | | | | | |
| | | | | | Millions | | | | | | | |
| | PSE&G | | | | | | | | | | | | | |
| | Gas | | Natural Gas Supply Contracts | | $ | 13 |
| | $ | (11 | ) | | Discounted Cash Flow | | Transportation Costs | | $0.60 to $0.80/Dth | |
| | Total PSE&G | | | | $ | 13 |
| | $ | (11 | ) | | | | | | | |
| | Power | | | | | | | | | | | | | |
| | Electricity | | Electric Load Contracts | | $ | 11 |
| | $ | (1 | ) | | Discounted Cash Flow | | Historic Load Variability | | 0% to +10% | |
| | Electricity | | Other | | 1 |
| | — |
| | | | | | | |
| | Total Power | | | | $ | 12 |
| | $ | (1 | ) | | | | | | | |
| | Total PSEG | | | | $ | 25 |
| | $ | (12 | ) | | | | | | | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Quantitative Information About Level 3 Fair Value Measurements | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | Significant | | | |
| | | | | | Fair Value as of | | Valuation | | Unobservable | | | |
| | Commodity | | Level 3 Position | | December 31, 2016 | | Technique(s) | | Input | | Range | |
| | | | | | Assets | | (Liabilities) | | | | | | | |
| | | | | | Millions | | | | | | | |
| | PSE&G | | | | | | | | | | | | | |
| | Gas | | Natural Gas Supply Contract | | $ | — |
| | $ | (5 | ) | | Discounted Cash Flow | | Transportation Costs | | $0.60 to $0.80/Dth | |
| | Total PSE&G | | | | $ | — |
| | $ | (5 | ) | | | | | | | |
| | Power | | | | | | | | | | | | | |
| | Electricity | | Electric Load Contracts | | $ | 7 |
| | $ | (1 | ) | | Discounted Cash Flow | | Historic Load Variability | | 0% to +10% | |
| | Gas (A) | | Other | | — |
| | — |
| | | | | | | |
| | Total Power | | | | $ | 7 |
| | $ | (1 | ) | | | | | | | |
| | Total PSEG | | | | $ | 7 |
| | $ | (6 | ) | | | | | | | |
| | | | | | | | | | | | | | | |
(A) Includes gas positions which were immaterial as of March 31, 2017 and December 31, 2016.
Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months ended March 31, 20162017 and March 31, 2015,2016, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months EndedMarch 31, 20162017 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | Total Gains or (Losses) Realized/Unrealized | | | | | | | | | |
| | Description | | Balance as of January 1, 2016 | | Included in Income (A) | | Included in Regulatory Assets/ Liabilities (B) | | Purchases (Sales) | | Issuances/ Settlements (C) | | Transfers In/Out (D) | | Balance as of March 31, 2016 | |
| | | | Millions | | | |
| | PSEG | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 13 |
| | $ | 15 |
| | $ | 8 |
| | $ | — |
| | $ | (15 | ) | | $ | — |
| | $ | 21 |
| |
| | PSE&G | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 2 |
| | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 10 |
| |
| | Power | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 11 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | (15 | ) | | $ | — |
| | $ | 11 |
| |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, 2017 | | | |
| | | | | | Total Gains or (Losses) Realized/Unrealized | | | | | | | | | |
| | Description | | Balance as of January 1, 2017 | | Included in Income (A) | | Included in Regulatory Assets/ Liabilities (B) | | Purchases (Sales) | | Issuances/ Settlements (C) | | Transfers In/Out (D) | | Balance as of March 31, 2017 | |
| | | | Millions | | | |
| | PSEG | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 1 |
| | $ | 19 |
| | $ | 6 |
| | $ | — |
| | $ | (22 | ) | | $ | (1 | ) | | $ | 3 |
| |
| | PSE&G | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | (5 | ) | | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | Power | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 6 |
| | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | (22 | ) | | $ | (1 | ) | | $ | 2 |
| |
| | | | | | | | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months EndedMarch 31, 20152016 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | Total Gains or (Losses) Realized/Unrealized | | | | | | | | | |
| | Description | | Balance as of January 1, 2015 | | Included in Income (A) | | Included in Regulatory Assets/ Liabilities (B) | | Purchases (Sales) | | Issuances/ Settlements (C) | | Transfers In/Out (D) | | Balance as of March 31, 2015 | |
| | | | Millions | | | |
| | PSEG | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 37 |
| | $ | 3 |
| | $ | (19 | ) | | $ | — |
| | $ | (12 | ) | | $ | — |
| | $ | 9 |
| |
| | PSE&G | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 26 |
| | $ | — |
| | $ | (19 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 7 |
| |
| | Power | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 11 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | (12 | ) | | $ | — |
| | $ | 2 |
| |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, 2016 | | | |
| | | | | | Total Gains or (Losses) Realized/Unrealized | | | | | | | | | |
| | Description | | Balance as of January 1, 2016 | | Included in Income (A) | | Included in Regulatory Assets/ Liabilities (B) | | Purchases (Sales) | | Issuances/ Settlements (C) | | Transfers In/Out (D) | | Balance as of March 31, 2016 | |
| | | | Millions | | | |
| | PSEG | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 13 |
| | $ | 15 |
| | $ | 8 |
| | $ | — |
| | $ | (15 | ) | | $ | — |
| | $ | 21 |
| |
| | PSE&G | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 2 |
| | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 10 |
| |
| | Power | | | | | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 11 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | (15 | ) | | $ | — |
| | $ | 11 |
| |
| | | | | | | | | | | | | | | | | |
| |
| (A) | PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $15$19 million and $3$15 million in Operating Income for the three months ended March 31, 2017 and 2016, respectively. Of the $19 million in 2016 and 2015, respectively.Operating Income, $3 million is unrealized. The $15 million in Operating Income in 2016 is realized. Of the $3 million in Operating Income, $(9) million is unrealized. |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
| |
| (B) | Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. |
| |
| (C) | Represents $(15)$(22) million and $(12)$(15) million in settlements for the three months ended March 31, 2017 and 2016, and 2015.respectively. |
| |
| (D) | There were no transfers among levels duringDuring the three months ended March 31, 2016 and 2015. 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in to or out of Level 3 during 2016.
|
As of March 31, 2017, PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $3 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of March 31, 2016, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $21 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
AsNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Fair Value of Debt
The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of March 31, 20162017 and December 31, 20152016.
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of | | As of | |
| | | March 31, 2016 | | December 31, 2015 | |
| | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | |
| | | Millions | |
| | Long-Term Debt: | | | | | | | | |
| | PSEG (Parent) (A) | $ | 501 |
| | $ | 504 |
| | $ | 503 |
| | $ | 506 |
| |
| | PSE&G (B) | 7,492 |
| | 8,339 |
| | 6,821 |
| | 7,235 |
| |
| | Power - Recourse Debt (B) | 2,238 |
| | 2,502 |
| | 2,237 |
| | 2,508 |
| |
| | Energy Holdings: | | | | | | | | |
| | Project Level, Non-Recourse Debt (C) | 7 |
| | 7 |
| | 7 |
| | 7 |
| |
| | Total Long-Term Debt | $ | 10,238 |
| | $ | 11,352 |
| | $ | 9,568 |
| | $ | 10,256 |
| |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of | | As of | |
| | | March 31, 2017 | | December 31, 2016 | |
| | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | |
| | | Millions | |
| | Long-Term Debt: | | | | | | | | |
| | PSEG (Parent) (A) | $ | 1,196 |
| | $ | 1,184 |
| | $ | 1,195 |
| | $ | 1,185 |
| |
| | PSE&G (B) | 7,819 |
| | 8,349 |
| | 7,818 |
| | 8,240 |
| |
| | Power - Recourse Debt (B) | 2,383 |
| | 2,611 |
| | 2,382 |
| | 2,578 |
| |
| | Total Long-Term Debt | $ | 11,398 |
| | $ | 12,144 |
| | $ | 11,395 |
| | $ | 12,003 |
| |
| | | | | | | | | | |
| |
| (A) | Fair value includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power.offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings. |
| |
| (B) | Given that most bonds do not trade, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. |
| |
(C) | Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement. |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 12.13. Other Income and Deductions
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | Other Income | PSE&G | | Power | | Other (A) | | Consolidated | |
| | | Millions | |
| | Three Months Ended March 31, 2016 | | | | | | | | |
| | NDT Fund Gains, Interest, Dividend and Other Income | $ | — |
| | $ | 25 |
| | $ | — |
| | $ | 25 |
| |
| | Allowance for Funds Used During Construction | 11 |
| | — |
| | — |
| | 11 |
| |
| | Solar Loan Interest | 6 |
| | — |
| | — |
| | 6 |
| |
| | Other | 3 |
| | 1 |
| | 2 |
| | 6 |
| |
| | Total Other Income | $ | 20 |
| | $ | 26 |
| | $ | 2 |
| | $ | 48 |
| |
| | Three Months Ended March 31, 2015 | | | | | | | | |
| | NDT Fund Gains, Interest, Dividend and Other Income | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | 29 |
| |
| | Allowance for Funds Used During Construction | 10 |
| | — |
| | — |
| | 10 |
| |
| | Solar Loan Interest | 6 |
| | — |
| | — |
| | 6 |
| |
| | Other | 2 |
| | — |
| | 1 |
| | 3 |
| |
| | Total Other Income | $ | 18 |
| | $ | 29 |
| | $ | 1 |
| | $ | 48 |
| |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | Other Income | PSE&G | | Power | | Other (A) | | Consolidated | |
| | | Millions | |
| | Three Months Ended March 31, 2017 | | | | | | | | |
| | NDT Fund Gains, Interest, Dividend and Other Income | $ | — |
| | $ | 31 |
| | $ | — |
| | $ | 31 |
| |
| | Allowance for Funds Used During Construction | 14 |
| | — |
| | — |
| | 14 |
| |
| | Rabbi Trust Realized Gains, Interest and Dividends | 3 |
| | 4 |
| | 9 |
| | 16 |
| |
| | Solar Loan Interest | 5 |
| | — |
| | — |
| | 5 |
| |
| | Other | 3 |
| | 3 |
| | — |
| | 6 |
| |
| | Total Other Income | $ | 25 |
| | $ | 38 |
| | $ | 9 |
| | $ | 72 |
| |
| | Three Months Ended March 31, 2016 | | | | | | | | |
| | NDT Fund Gains, Interest, Dividend and Other Income | $ | — |
| | $ | 25 |
| | $ | — |
| | $ | 25 |
| |
| | Allowance for Funds Used During Construction | 11 |
| | — |
| | — |
| | 11 |
| |
| | Solar Loan Interest | 6 |
| | — |
| | — |
| | 6 |
| |
| | Other | 3 |
| | 1 |
| | 2 |
| | 6 |
| |
| | Total Other Income | $ | 20 |
| | $ | 26 |
| | $ | 2 |
| | $ | 48 |
| |
| | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | Other Deductions | PSE&G | | Power | | Other (A) | | Consolidated | |
| | | Millions | |
| | Three Months Ended March 31, 2016 | | | | | | | | |
| | NDT Fund Realized Losses and Expenses | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | 18 |
| |
| | Other | 1 |
| | ��� |
| | 2 |
| | 3 |
| |
| | Total Other Deductions | $ | 1 |
| | $ | 18 |
| | $ | 2 |
| | $ | 21 |
| |
| | Three Months Ended March 31, 2015 | | | | | | | | |
| | NDT Fund Realized Losses and Expenses | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | 11 |
| |
| | Other | 1 |
| | — |
| | — |
| | 1 |
| |
| | Total Other Deductions | $ | 1 |
| | $ | 11 |
| | $ | — |
| | $ | 12 |
| |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | Other Deductions | PSE&G | | Power | | Other (A) | | Consolidated | |
| | | Millions | |
| | Three Months Ended March 31, 2017 | | | | | | | | |
| | NDT Fund Realized Losses and Expenses | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 7 |
| |
| | Other | 1 |
| | — |
| | 3 |
| | 4 |
| |
| | Total Other Deductions | $ | 1 |
| | $ | 7 |
| | $ | 3 |
| | $ | 11 |
| |
| | Three Months Ended March 31, 2016 | | | | | | | | |
| | NDT Fund Realized Losses and Expenses | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | 18 |
| |
| | Other | 1 |
| | — |
| | 2 |
| | 3 |
| |
| | Total Other Deductions | $ | 1 |
| | $ | 18 |
| | $ | 2 |
| | $ | 21 |
| |
| | | | | | | | | | |
| |
| (A) | Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations. |
Note 13.14. Income Taxes
PSEG’s, PSE&G’s and Power'sPower’s effective tax rates for the three months ended March 31, 20162017 and 20152016 were as follows: |
| | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | 2016 | | 2015 | |
| | PSEG | | 37.5% | | 40.5% | |
| | PSE&G | | 36.6% | | 39.4% | |
| | Power | | 40.2% | | 41.1% | |
| | | | | | | |
|
| | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | 2017 | | 2016 | |
| | PSEG | | 20.3% | | 37.5% | |
| | PSE&G | | 36.4% | | 36.6% | |
| | Power | | 40.6% | | 40.2% | |
| | | | | | | |
For the three months ended March 31, 2016,2017, the overall decreasesdecrease in PSEG's and PSE&G'sPSEG’s effective tax rates as compared to the same periodsperiod in the prior year as well as to the statutory tax rate of 40.85%, werewas primarily due primarily to depreciation flow through items and changes in uncertain tax positions.
The Tax Increase Prevention Act of 2014 extended the 50% bonus depreciation rules for qualified property placed in service before January 1, 2015positions and for long production property placed in service in 2015.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
interest on a New Jersey State refund.
The Protecting Americans from Tax Hikes Act of 2015 (Tax Act) extended the 50% bonus depreciation rules for qualified property placed in service from January 1, 2015 through December 31, 2017. The rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. The Tax Act also extended the 30% ITC for qualified property placed in service starting January 1, 2016 through December 31, 2019 but reduces the ITC rate to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions.
These provisions haveThis provision has generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 14.15. Accumulated Other Comprehensive Income (Loss), Net of Tax |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | PSEG | | Other Comprehensive Income (Loss) | |
| | | | Three Months Ended March 31, 2016 | |
| | Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for-Sale Securities | | Total | |
| | | | Millions | |
| | Balance as of December 31, 2015 | | $ | — |
| | $ | (386 | ) | | $ | 91 |
| | $ | (295 | ) | |
| | Other Comprehensive Income before Reclassifications | | 2 |
| | — |
| | 10 |
| | 12 |
| |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 8 |
| | 6 |
| | 14 |
| |
| | Net Current Period Other Comprehensive Income (Loss) | | 2 |
| | 8 |
| | 16 |
| | 26 |
| |
| | Balance as of March 31, 2016 | | $ | 2 |
| | $ | (378 | ) | | $ | 107 |
| | $ | (269 | ) | |
| | | | | | | | | | | |
| | | | Other Comprehensive Income (Loss) | |
| | | | Three Months Ended March 31, 2015 | |
| | Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for-Sale Securities | | Total | |
| | | | Millions | |
| | Balance as of December 31, 2014 | | $ | 10 |
| | $ | (411 | ) | | $ | 118 |
| | $ | (283 | ) | |
| | Other Comprehensive Income before Reclassifications | | 1 |
| | — |
| | 16 |
| | 17 |
| |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | (10 | ) | | 8 |
| | (2 | ) | | (4 | ) | |
| | Net Current Period Other Comprehensive Income (Loss) | | (9 | ) | | 8 |
| | 14 |
| | 13 |
| |
| | Balance as of March 31, 2015 | | $ | 1 |
| | $ | (403 | ) | | $ | 132 |
| | $ | (270 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | PSEG | | Other Comprehensive Income (Loss) | |
| | | | Three Months Ended March 31, 2017 | |
| | Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for-Sale Securities | | Total | |
| | | | Millions | |
| | Balance as of December 31, 2016 | | $ | 2 |
| | $ | (398 | ) | | $ | 133 |
| | $ | (263 | ) | |
| | Other Comprehensive Income before Reclassifications | | — |
| | — |
| | 30 |
| | 30 |
| |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 6 |
| | (15 | ) | | (9 | ) | |
| | Net Current Period Other Comprehensive Income (Loss) | | — |
| | 6 |
| | 15 |
| | 21 |
| |
| | Balance as of March 31, 2017 | | $ | 2 |
| | $ | (392 | ) | | $ | 148 |
| | $ | (242 | ) | |
| | | | | | | | | | | |
| | PSEG | | Other Comprehensive Income (Loss) | |
| | | | Three Months Ended March 31, 2016 | |
| | Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for-Sale Securities | | Total | |
| | | | Millions | |
| | Balance as of December 31, 2015 | | $ | — |
| | $ | (386 | ) | | $ | 91 |
| | $ | (295 | ) | |
| | Other Comprehensive Income before Reclassifications | | 2 |
| | — |
| | 10 |
| | 12 |
| |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 8 |
| | 6 |
| | 14 |
| |
| | Net Current Period Other Comprehensive Income (Loss) | | 2 |
| | 8 |
| | 16 |
| | 26 |
| |
| | Balance as of March 31, 2016 | | $ | 2 |
| | $ | (378 | ) | | $ | 107 |
| | $ | (269 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | Power | | Other Comprehensive Income (Loss) | |
| | | | Three Months Ended March 31, 2017 | |
| | Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for-Sale Securities | | Total | |
| | | | Millions | |
| | Balance as of December 31, 2016 | | $ | — |
| | $ | (340 | ) | | $ | 129 |
| | $ | (211 | ) | |
| | Other Comprehensive Income before Reclassifications | | — |
| | — |
| | 28 |
| | 28 |
| |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 5 |
| | (9 | ) | | (4 | ) | |
| | Net Current Period Other Comprehensive Income (Loss) | | — |
| | 5 |
| | 19 |
| | 24 |
| |
| | Balance as of March 31, 2017 | | $ | — |
| | $ | (335 | ) | | $ | 148 |
| | $ | (187 | ) | |
| | | | | | | | | | | |
| | Power | | Other Comprehensive Income (Loss) | |
| | | | Three Months Ended March 31, 2016 | |
| | Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for-Sale Securities | | Total | |
| | | | Millions | |
| | Balance as of December 31, 2015 | | $ | — |
| | $ | (327 | ) | | $ | 87 |
| | $ | (240 | ) | |
| | Other Comprehensive Income before Reclassifications | | — |
| | — |
| | 10 |
| | 10 |
| |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 7 |
| | 6 |
| | 13 |
| |
| | Net Current Period Other Comprehensive Income (Loss) | | — |
| | 7 |
| | 16 |
| | 23 |
| |
| | Balance as of March 31, 2016 | | $ | — |
| | $ | (320 | ) | | $ | 103 |
| | $ | (217 | ) | |
| | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | Power | | Other Comprehensive Income (Loss) | |
| | | | Three Months Ended March 31, 2016 | |
| | Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for-Sale Securities | | Total | |
| | | | Millions | |
| | Balance as of December 31, 2015 | | $ | — |
| | $ | (327 | ) | | $ | 87 |
| | $ | (240 | ) | |
| | Other Comprehensive Income before Reclassifications | | — |
| | — |
| | 10 |
| | 10 |
| |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 7 |
| | 6 |
| | 13 |
| |
| | Net Current Period Other Comprehensive Income (Loss) | | — |
| | 7 |
| | 16 |
| | 23 |
| |
| | Balance as of March 31, 2016 | | $ | — |
| | $ | (320 | ) | | $ | 103 |
| | $ | (217 | ) | |
| | | | | | | | | | | |
| | | | Other Comprehensive Income (Loss) | |
| | | | Three Months Ended March 31, 2015 | |
| | Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for-Sale Securities | | Total | |
| | | | Millions | |
| | Balance as of December 31, 2014 | | $ | 11 |
| | $ | (351 | ) | | $ | 112 |
| | $ | (228 | ) | |
| | Other Comprehensive Income before Reclassifications | | 1 |
| | — |
| | 16 |
| | 17 |
| |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | (10 | ) | | 7 |
| | (2 | ) | | (5 | ) | |
| | Net Current Period Other Comprehensive Income (Loss) | | (9 | ) | | 7 |
| | 14 |
| | 12 |
| |
| | Balance as of March 31, 2015 | | $ | 2 |
| | $ | (344 | ) | | $ | 126 |
| | $ | (216 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Three Months Ended | |
| | Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | March 31, 2017 | |
| | | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| | Pension and OPEB Plans | | | | | | | |
| | Amortization of Prior Service (Cost) Credit | | O&M Expense | | $ | 2 |
| | $ | (1 | ) | | $ | 1 |
| |
| | Amortization of Actuarial Loss | | O&M Expense | | (12 | ) | | 5 |
| | (7 | ) | |
| | Total Pension and OPEB Plans | | (10 | ) | | 4 |
| | (6 | ) | |
| | Available-for-Sale Securities | | | | | | | |
| | Realized Gains | | Other Income | | 36 |
| | (17 | ) | | 19 |
| |
| | Realized Losses | | Other Deductions | | (7 | ) | | 3 |
| | (4 | ) | |
| | OTTI | | OTTI | | (1 | ) | | 1 |
| | — |
| |
| | Total Available-for-Sale Securities | | 28 |
| | (13 | ) | | 15 |
| |
| | Total | | | | $ | 18 |
| | $ | (9 | ) | | $ | 9 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | PSEG | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Three Months Ended | |
| | Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | March 31, 2016 | |
| | | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| | Pension and OPEB Plans | | | | | | | | | |
| | Amortization of Prior Service (Cost) Credit | | O&M Expense | | 3 |
| | (1 | ) | | 2 |
| |
| | Amortization of Actuarial Loss | | O&M Expense | | (17 | ) | | 7 |
| | (10 | ) | |
| | Total Pension and OPEB Plans | | (14 | ) | | 6 |
| | (8 | ) | |
| | Available-for-Sale Securities | | | | | | | |
| | Realized Gains | | Other Income | | 16 |
| | (8 | ) | | 8 |
| |
| | Realized Losses | | Other Deductions | | (17 | ) | | 8 |
| | (9 | ) | |
| | Other-Than-Temporary Impairments (OTTI) | | OTTI | | (10 | ) | | 5 |
| | (5 | ) | |
| | Total Available-for-Sale Securities | | (11 | ) | | 5 |
| | (6 | ) | |
| | Total | | | | $ | (25 | ) | | $ | 11 |
| | $ | (14 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | PSEG | | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | | Three Months Ended | |
| | Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | | March 31, 2016 | |
| | | | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | | Millions | |
| | Pension and OPEB Plans | | | | | | | | | | |
| | Amortization of Prior Service (Cost) Credit | | O&M Expense | | | $ | 3 |
| | $ | (1 | ) | | $ | 2 |
| |
| | Amortization of Actuarial Loss | | O&M Expense | | | (17 | ) | | 7 |
| | (10 | ) | |
| | Total Pension and OPEB Plans | | | (14 | ) | | 6 |
| | (8 | ) | |
| | Available-for-Sale Securities | | | | | | | | |
| | Realized Gains | | Other Income | | | 16 |
| | (8 | ) | | 8 |
| |
| | Realized Losses | | Other Deductions | | | (17 | ) | | 8 |
| | (9 | ) | |
| | OTTI | | OTTI | | | (10 | ) | | 5 |
| | (5 | ) | |
| | Total Available-for-Sale Securities | | | (11 | ) | | 5 |
| | (6 | ) | |
| | Total | | | | | $ | (25 | ) | | $ | 11 |
| | $ | (14 | ) | |
| | | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Three Months Ended | |
| | Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | March 31, 2015 | |
| | | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | | Millions | |
| | Cash Flow Hedges | | | | | | | | | |
| | Energy-Related Contracts | | Operating Revenues | | $ | 17 |
| | $ | (7 | ) | | $ | 10 |
| |
| | Total Cash Flow Hedges | | | | 17 |
| | (7 | ) | | 10 |
| |
| | Pension and OPEB Plans | | | | | | | | | |
| | Amortization of Prior Service (Cost) Credit | | O&M Expense | | 3 |
| | (1 | ) | | 2 |
| |
| | Amortization of Actuarial Loss | | O&M Expense | | (17 | ) | | 7 |
| | (10 | ) | |
| | Total Pension and OPEB Plans | | (14 | ) | | 6 |
| | (8 | ) | |
| | Available-for-Sale Securities | | | | | | | |
| | Realized Gains | | Other Income | | 19 |
| | (10 | ) | | 9 |
| |
| | Realized Losses | | Other Deductions | | (9 | ) | | 5 |
| | (4 | ) | |
| | OTTI | | OTTI | | (5 | ) | | 2 |
| | (3 | ) | |
| | Total Available-for-Sale Securities | | 5 |
| | (3 | ) | | 2 |
| |
| | Total | | | | $ | 8 |
| | $ | (4 | ) | | $ | 4 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | Power | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Three Months Ended | |
| | Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | March 31, 2017 | |
| | | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| | Pension and OPEB Plans | | | | | | | | | |
| | Amortization of Prior Service (Cost) Credit | | O&M Expense | | $ | 2 |
| | $ | (1 | ) | | $ | 1 |
| |
| | Amortization of Actuarial Loss | | O&M Expense | | (11 | ) | | 5 |
| | (6 | ) | |
| | Total Pension and OPEB Plans | | (9 | ) | | 4 |
| | (5 | ) | |
| | Available-for-Sale Securities | | | | | | | |
| | Realized Gains | | Other Income | | 25 |
| | (13 | ) | | 12 |
| |
| | Realized Losses | | Other Deductions | | (5 | ) | | 2 |
| | (3 | ) | |
| | OTTI | | OTTI | | (1 | ) | | 1 |
| | — |
| |
| | Total Available-for-Sale Securities | | 19 |
| | (10 | ) | | 9 |
| |
| | Total | | | | $ | 10 |
| | $ | (6 | ) | | $ | 4 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | Power | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Three Months Ended | |
| | Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | March 31, 2016 | |
| | | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | | Millions | |
| | Pension and OPEB Plans | | | | | | | | | |
| | Amortization of Prior Service (Cost) Credit | | O&M Expense | | 3 |
| | (1 | ) | | 2 |
| |
| | Amortization of Actuarial Loss | | O&M Expense | | (15 | ) | | 6 |
| | (9 | ) | |
| | Total Pension and OPEB Plans | | (12 | ) | | 5 |
| | (7 | ) | |
| | Available-for-Sale Securities | | | | | | | |
| | Realized Gains | | Other Income | | 15 |
| | (8 | ) | | 7 |
| |
| | Realized Losses | | Other Deductions | | (16 | ) | | 8 |
| | (8 | ) | |
| | OTTI | | OTTI | | (10 | ) | | 5 |
| | (5 | ) | |
| | Total Available-for-Sale Securities | | (11 | ) | | 5 |
| | (6 | ) | |
| | Total | | | | $ | (23 | ) | | $ | 10 |
| | $ | (13 | ) | |
| | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | Power | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Three Months Ended | |
| | Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | March 31, 2015 | |
| | | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | | Millions | |
| | Cash Flow Hedges | | | | | | | | | |
| | Energy-Related Contracts | | Operating Revenues | | $ | 17 |
| | $ | (7 | ) | | $ | 10 |
| |
| | Total Cash Flow Hedges | | | | 17 |
| | (7 | ) | | 10 |
| |
| | Pension and OPEB Plans | | | | | | | | | |
| | Amortization of Prior Service (Cost) Credit | | O&M Expense | | 3 |
| | (1 | ) | | 2 |
| |
| | Amortization of Actuarial Loss | | O&M Expense | | (15 | ) | | 6 |
| | (9 | ) | |
| | Total Pension and OPEB Plans | | (12 | ) | | 5 |
| | (7 | ) | |
| | Available-for-Sale Securities | | | | | | | |
| | Realized Gains | | Other Income | | 19 |
| | (10 | ) | | 9 |
| |
| | Realized Losses | | Other Deductions | | (9 | ) | | 5 |
| | (4 | ) | |
| | OTTI | | OTTI | | (5 | ) | | 2 |
| | (3 | ) | |
| | Total Available-for-Sale Securities | | 5 |
| | (3 | ) | | 2 |
| |
| | Total | | | | $ | 10 |
| | $ | (5 | ) | | $ | 5 |
| |
| | | | | | | | | | | |
Note 15.16. Earnings Per Share (EPS) and Dividends
EPS
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG'sPSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Three Months Ended March 31, | |
| | | | 2016 | | 2015 | |
| | | | Basic | | Diluted | | Basic | | Diluted | |
| | EPS Numerator (Millions): | | | | | | | | | |
| | Net Income | | $ | 471 |
| | $ | 471 |
| | $ | 586 |
| | $ | 586 |
| |
| | EPS Denominator (Millions): | | | | | | | | | |
| | Weighted Average Common Shares Outstanding | | 505 |
| | 505 |
| | 506 |
| | 506 |
| |
| | Effect of Stock Based Compensation Awards | | — |
| | 3 |
| | — |
| | 2 |
| |
| | Total Shares | | 505 |
| | 508 |
| | 506 |
| | 508 |
| |
| | | | | | | | | | | |
| | EPS | | | | | | | | | |
| | Net Income | | $ | 0.93 |
| | $ | 0.93 |
| | $ | 1.16 |
| | $ | 1.15 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Three Months Ended March 31, | |
| | | | 2017 | | 2016 | |
| | | | Basic | | Diluted | | Basic | | Diluted | |
| | EPS Numerator (Millions): | | | | | | | | | |
| | Net Income | | $ | 114 |
| | $ | 114 |
| | $ | 471 |
| | $ | 471 |
| |
| | EPS Denominator (Millions): | | | | | | | | | |
| | Weighted Average Common Shares Outstanding | | 505 |
| | 505 |
| | 505 |
| | 505 |
| |
| | Effect of Stock Based Compensation Awards | | — |
| | 3 |
| | — |
| | 3 |
| |
| | Total Shares | | 505 |
| | 508 |
| | 505 |
| | 508 |
| |
| | | | | | | | | | | |
| | EPS | | | | | | | | | |
| | Net Income | | $ | 0.23 |
| | $ | 0.22 |
| | $ | 0.93 |
| | $ | 0.93 |
| |
| | | | | | | | | | | |
There were approximately 0.3 million and 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months ended March 31, 20162017 and 2015, respectively.2016.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Dividends
|
| | | | | | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | Dividend Payments on Common Stock | | 2016 | | 2015 | |
| | Per Share | | $ | 0.41 |
| | $ | 0.39 |
| |
| | In Millions | | $ | 207 |
| | $ | 197 |
| |
| | | | | | | |
|
| | | | | | | | | |
| | | | | | |
| | | Three Months Ended | |
| | | March 31, | |
| | Dividend Payments on Common Stock | 2017 | | 2016 | |
| | Per Share | $ | 0.43 |
| | $ | 0.41 |
| |
| | In Millions | $ | 218 |
| | $ | 207 |
| |
| | | | | | |
On April 19, 2016, PSEG's18, 2017, PSEG’s Board of Directors approved a $0.41$0.43 per share common stock dividend for the second quarter of 2016.2017.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 16.17. Financial Information by Business Segment
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | Power | | Other (A) | | Eliminations (B) | | Consolidated | |
| | | Millions | |
| | Three Months Ended March 31, 2016 | | | | | | | | | | |
| | Operating Revenues | $ | 1,712 |
| | $ | 1,313 |
| | $ | 122 |
| | $ | (531 | ) | | $ | 2,616 |
| |
| | Net Income (Loss) | 262 |
| | 192 |
| | 17 |
| | — |
| | 471 |
| |
| | Gross Additions to Long-Lived Assets | 724 |
| | 333 |
| | 8 |
| | — |
| | 1,065 |
| |
| | Three Months Ended March 31, 2015 | | | | | | | | | | |
| | Operating Revenues | $ | 2,002 |
| | $ | 1,725 |
| | $ | 98 |
| | $ | (690 | ) | | $ | 3,135 |
| |
| | Net Income (Loss) | 242 |
| | 335 |
| | 9 |
| | — |
| | 586 |
| |
| | Gross Additions to Long-Lived Assets | 599 |
| | 139 |
| | 9 |
| | — |
| | 747 |
| |
| | As of March 31, 2016 | | | | | | | | | | |
| | Total Assets | $ | 24,372 |
| | $ | 12,617 |
| | $ | 2,462 |
| | $ | (1,325 | ) | | $ | 38,126 |
| |
| | Investments in Equity Method Subsidiaries | $ | — |
| | $ | 116 |
| | $ | — |
| | $ | — |
| | $ | 116 |
| |
| | As of December 31, 2015 | | | | | | | | | | |
| | Total Assets | $ | 23,677 |
| | $ | 12,250 |
| | $ | 2,810 |
| | $ | (1,202 | ) | | $ | 37,535 |
| |
| | Investments in Equity Method Subsidiaries | $ | — |
| | $ | 119 |
| | $ | — |
| | $ | — |
| | $ | 119 |
| |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | Power | | Other (A) | | Eliminations (B) | | Consolidated | |
| | | Millions | |
| | Three Months Ended March 31, 2017 | | | | | | | | | | |
| | Operating Revenues | $ | 1,812 |
| | $ | 1,284 |
| | $ | 83 |
| | $ | (587 | ) | | $ | 2,592 |
| |
| | Net Income (Loss) | 299 |
| | (170 | ) | | (15 | ) | | — |
| | 114 |
| |
| | Gross Additions to Long-Lived Assets | 748 |
| | 307 |
| | 7 |
| | — |
| | 1,062 |
| |
| | Three Months Ended March 31, 2016 | | | | | | | | | | |
| | Operating Revenues | $ | 1,712 |
| | $ | 1,313 |
| | $ | 122 |
| | $ | (531 | ) | | $ | 2,616 |
| |
| | Net Income (Loss) | 262 |
| | 192 |
| | 17 |
| | — |
| | 471 |
| |
| | Gross Additions to Long-Lived Assets | 724 |
| | 333 |
| | 8 |
| | — |
| | 1,065 |
| |
| | As of March 31, 2017 | | | | | | | | | | |
| | Total Assets | $ | 26,487 |
| | $ | 11,729 |
| | $ | 2,249 |
| | $ | (801 | ) | | $ | 39,664 |
| |
| | Investments in Equity Method Subsidiaries | $ | — |
| | $ | 103 |
| | $ | — |
| | $ | — |
| | $ | 103 |
| |
| | As of December 31, 2016 | | | | | | | | | | |
| | Total Assets | $ | 26,288 |
| | $ | 12,193 |
| | $ | 2,373 |
| | $ | (784 | ) | | $ | 40,070 |
| |
| | Investments in Equity Method Subsidiaries | $ | — |
| | $ | 102 |
| | $ | — |
| | $ | — |
| | $ | 102 |
| |
| | | | | | | | | | | | |
| |
| (A) | Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. |
| |
| (B) | Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 17.18. Related-Party Transactions. |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 17.18. Related-Party Transactions
The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.
PSE&G
The financial statements for PSE&G include transactions with related parties as follows: |
| | | | | | | | | |
| | | | | | |
| | | Three Months Ended | |
| | | March 31, | |
| | Related-Party Transactions | 2017 | | 2016 | |
| | | Millions | |
| | Billings from Affiliates: | | | | |
| | Net Billings from Power primarily through BGS and BGSS (A) | $ | 599 |
| | $ | 545 |
| |
| | Administrative Billings from Services (B) | 65 |
| | 69 |
| |
| | Total Billings from Affiliates | $ | 664 |
| | $ | 614 |
| |
| | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | Related-Party Transactions | | 2016 | | 2015 | |
| | | Millions | |
| | Billings from Affiliates: | | | | | |
| | Net Billings from Power primarily through BGS and BGSS (A) | | $ | 545 |
| | $ | 696 |
| |
| | Administrative Billings from Services (B) | | 69 |
| | 66 |
| |
| | Total Billings from Affiliates | | $ | 614 |
| | $ | 762 |
| |
| | | | | | | |
|
| | | | | | | | | |
| | | | | | |
| | | As of | | As of | |
| | Related-Party Transactions | March 31, 2016 | | December 31, 2015 | |
| | | Millions | |
| | Receivables from PSEG (C) | $ | 3 |
| | $ | 222 |
| |
| | Payable to Power (A) | $ | 184 |
| | $ | 212 |
| |
| | Payable to Services (B) | 74 |
| | 80 |
| |
| | Accounts Payable—Affiliated Companies | $ | 258 |
| | $ | 292 |
| |
| | Working Capital Advances to Services (D) | $ | 33 |
| | $ | 33 |
| |
| | Long-Term Accrued Taxes Payable | $ | 89 |
| | $ | 109 |
| |
| | | | | | |
|
| | | | | | | | | |
| | | | | | |
| | | As of | | As of | |
| | Related-Party Transactions | March 31, 2017 | | December 31, 2016 | |
| | | Millions | |
| | Receivables from PSEG (C) | $ | 34 |
| | $ | 76 |
| |
| | Payable to Power (A) | $ | 175 |
| | $ | 193 |
| |
| | Payable to Services (B) | 43 |
| | 67 |
| |
| | Accounts Payable—Affiliated Companies | $ | 218 |
| | $ | 260 |
| |
| | Working Capital Advances to Services (D) | $ | 33 |
| | $ | 33 |
| |
| | Long-Term Accrued Taxes Payable | $ | 116 |
| | $ | 130 |
| |
| | | | | | |
Power
The financial statements for Power include transactions with related parties as follows:
|
| | | | | | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | Related-Party Transactions | | 2016 | | 2015 | |
| | | Millions | |
| | Billings to Affiliates: | | | | | |
| | Net Billings to PSE&G primarily through BGS and BGSS (A) | | $ | 545 |
| | $ | 696 |
| |
| | Billings from Affiliates: | | | | | |
| | Administrative Billings from Services (B) | | $ | 45 |
| | $ | 45 |
| |
| | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | |
| | | | | | |
| | | Three Months Ended | |
| | | March 31, | |
| | Related-Party Transactions | 2017 | | 2016 | |
| | | Millions | |
| | Billings to Affiliates: | | | | |
| | Net Billings to PSE&G primarily through BGS and BGSS (A) | $ | 599 |
| | $ | 545 |
| |
| | Billings from Affiliates: | | | | |
| | Administrative Billings from Services (B) | $ | 36 |
| | $ | 45 |
| |
| | | | | | |
|
| | | | | | | | | |
| | | | | | |
| | | As of | | As of | |
| | Related-Party Transactions | March 31, 2016 | | December 31, 2015 | |
| | | Millions | |
| | Receivables from PSE&G (A) | $ | 184 |
| | $ | 212 |
| |
| | Receivables from PSEG (C) | — |
| | 64 |
| |
| | Accounts Receivable—Affiliated Companies | $ | 184 |
| | $ | 276 |
| |
| | Payable to Services (B) | $ | 34 |
| | $ | 33 |
| |
| | Payable to PSEG (C) | 118 |
| | — |
| |
| | Accounts Payable—Affiliated Companies | $ | 152 |
| | $ | 33 |
| |
| | Short-Term Loan Due (to) from Affiliate (E) | $ | 672 |
| | $ | 363 |
| |
| | Working Capital Advances to Services (D) | $ | 17 |
| | $ | 17 |
| |
| | Long-Term Accrued Taxes Payable | $ | 38 |
| | $ | 35 |
| |
| | | | | | |
|
| | | | | | | | | |
| | | | | | |
| | | As of | | As of | |
| | Related-Party Transactions | March 31, 2017 | | December 31, 2016 | |
| | | Millions | |
| | Receivables from PSE&G (A) | $ | 175 |
| | $ | 193 |
| |
| | Receivables from PSEG (C) | — |
| | 12 |
| |
| | Accounts Receivable—Affiliated Companies | $ | 175 |
| | $ | 205 |
| |
| | Payable to Services (B) | $ | 10 |
| | $ | 25 |
| |
| | Payable to PSEG (C) | 71 |
| | — |
| |
| | Accounts Payable—Affiliated Companies | $ | 81 |
| | $ | 25 |
| |
| | Short-Term Loan Due (to) from Affiliate (E) | $ | 157 |
| | $ | 87 |
| |
| | Working Capital Advances to Services (D) | $ | 17 |
| | $ | 17 |
| |
| | Long-Term Accrued Taxes Payable | $ | 78 |
| | $ | 77 |
| |
| | | | | | |
| |
| (A) | PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. |
| |
| (B) | Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. |
| |
| (C) | PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. |
| |
| (D) | PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Condensed Consolidated Balance Sheets. |
| |
| (E) | Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 18.19. Guarantees of Debt
Each series of Power’s Senior Notes Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of March 31, 20162017 and December 31, 20152016 and for the three months ended March 31, 20162017 and 2015.2016. |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | Millions | |
| | Three Months Ended March 31, 2017 | | | | | | | | | | |
| | Operating Revenues | $ | — |
| | $ | 1,270 |
| | $ | 52 |
| | $ | (38 | ) | | $ | 1,284 |
| |
| | Operating Expenses | 4 |
| | 1,569 |
| | 52 |
| | (38 | ) | | 1,587 |
| |
| | Operating Income (Loss) | (4 | ) | | (299 | ) | | — |
| | — |
| | (303 | ) | |
| | Equity Earnings (Losses) of Subsidiaries | (161 | ) | | (1 | ) | | 3 |
| | 162 |
| | 3 |
| |
| | Other Income | 25 |
| | 41 |
| | — |
| | (28 | ) | | 38 |
| |
| | Other Deductions | (1 | ) | | (6 | ) | | — |
| | — |
| | (7 | ) | |
| | Other-Than-Temporary Impairments | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) | |
| | Interest Expense | (30 | ) | | (9 | ) | | (5 | ) | | 28 |
| | (16 | ) | |
| | Income Tax Benefit (Expense) | 1 |
| | 111 |
| | 4 |
| | — |
| | 116 |
| |
| | Net Income (Loss) | $ | (170 | ) | | $ | (164 | ) | | $ | 2 |
| | $ | 162 |
| | $ | (170 | ) | |
| | Comprehensive Income (Loss) | $ | (146 | ) | | $ | (143 | ) | | $ | 2 |
| | $ | 141 |
| | $ | (146 | ) | |
| | Three Months Ended March 31, 2017 | | | | | | | | | | |
| | Net Cash Provided By (Used In) Operating Activities | $ | 77 |
| | $ | 377 |
| | $ | 91 |
| | $ | 35 |
| | $ | 580 |
| |
| | Net Cash Provided By (Used In) Investing Activities | $ | 251 |
| | $ | 20 |
| | $ | (154 | ) | | $ | (511 | ) | | $ | (394 | ) | |
| | Net Cash Provided By (Used In) Financing Activities | $ | (328 | ) | | $ | (395 | ) | | $ | 68 |
| | $ | 476 |
| | $ | (179 | ) | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | Millions | |
| | Three Months Ended March 31, 2016 | | | | | | | | | | |
| | Operating Revenues | $ | — |
| | $ | 1,302 |
| | $ | 42 |
| | $ | (31 | ) | | $ | 1,313 |
| |
| | Operating Expenses | 10 |
| | 952 |
| | 39 |
| | (31 | ) | | 970 |
| |
| | Operating Income (Loss) | (10 | ) | | 350 |
| | 3 |
| | — |
| | 343 |
| |
| | Equity Earnings (Losses) of Subsidiaries | 205 |
| | (1 | ) | | 2 |
| | (204 | ) | | 2 |
| |
| | Other Income | 17 |
| | 32 |
| | — |
| | (23 | ) | | 26 |
| |
| | Other Deductions | — |
| | (18 | ) | | — |
| | — |
| | (18 | ) | |
| | Other-Than-Temporary Impairments | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) | |
| | Interest Expense | (30 | ) | | (10 | ) | | (5 | ) | | 23 |
| | (22 | ) | |
| | Income Tax Benefit (Expense) | 10 |
| | (140 | ) | | 1 |
| | — |
| | (129 | ) | |
| | Net Income (Loss) | $ | 192 |
| | $ | 203 |
| | $ | 1 |
| | $ | (204 | ) | | $ | 192 |
| |
| | Comprehensive Income (Loss) | $ | 215 |
| | $ | 219 |
| | $ | 1 |
| | $ | (220 | ) | | $ | 215 |
| |
| | Three Months Ended March 31, 2016 | | | | | | | | | | |
| | Net Cash Provided By (Used In) Operating Activities | $ | 271 |
| | $ | 480 |
| | $ | 47 |
| | $ | (135 | ) | | $ | 663 |
| |
| | Net Cash Provided By (Used In) Investing Activities | $ | (598 | ) | | $ | (428 | ) | | $ | (246 | ) | | $ | 613 |
| | $ | (659 | ) | |
| | Net Cash Provided By (Used In) Financing Activities | $ | 326 |
| | $ | (51 | ) | | $ | 203 |
| | $ | (478 | ) | | $ | — |
| |
| | | | | | | | | | | | |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | Millions | |
| | Three Months Ended March 31, 2015 | | | | | | | | | | |
| | Operating Revenues | $ | — |
| | $ | 1,715 |
| | $ | 68 |
| | $ | (58 | ) | | $ | 1,725 |
| |
| | Operating Expenses | 5 |
| | 1,131 |
| | 63 |
| | (58 | ) | | 1,141 |
| |
| | Operating Income (Loss) | (5 | ) | | 584 |
| | 5 |
| | — |
| | 584 |
| |
| | Equity Earnings (Losses) of Subsidiaries | 349 |
| | (1 | ) | | 3 |
| | (348 | ) | | 3 |
| |
| | Other Income | 11 |
| | 30 |
| | — |
| | (12 | ) | | 29 |
| |
| | Other Deductions | — |
| | (11 | ) | | — |
| | — |
| | (11 | ) | |
| | Other-Than-Temporary Impairments | — |
| | (5 | ) | | — |
| | — |
| | (5 | ) | |
| | Interest Expense | (29 | ) | | (9 | ) | | (5 | ) | | 12 |
| | (31 | ) | |
| | Income Tax Benefit (Expense) | 9 |
| | (242 | ) | | (1 | ) | | — |
| | (234 | ) | |
| | Net Income (Loss) | $ | 335 |
| | $ | 346 |
| | $ | 2 |
| | $ | (348 | ) | | $ | 335 |
| |
| | Comprehensive Income (Loss) | $ | 347 |
| | $ | 351 |
| | $ | 2 |
| | $ | (353 | ) | | $ | 347 |
| |
| | Three Months Ended March 31, 2015 | | | | | | | | | | |
| | Net Cash Provided By (Used In) Operating Activities | $ | 327 |
| | $ | 772 |
| | $ | 11 |
| | $ | (260 | ) | | $ | 850 |
| |
| | Net Cash Provided By (Used In) Investing Activities | $ | (537 | ) | | $ | (515 | ) | | $ | (13 | ) | | $ | 430 |
| | $ | (635 | ) | |
| | Net Cash Provided By (Used In) Financing Activities | $ | 210 |
| | $ | (242 | ) | | $ | 2 |
| | $ | (170 | ) | | $ | (200 | ) | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | Millions | |
| | As of March 31, 2016 | | | | | | | | | | |
| | Current Assets | $ | 4,819 |
| | $ | 1,934 |
| | $ | 283 |
| | $ | (5,005 | ) | | $ | 2,031 |
| |
| | Property, Plant and Equipment, net | 88 |
| | 6,465 |
| | 1,773 |
| | — |
| | 8,326 |
| |
| | Investment in Subsidiaries | 4,615 |
| | 345 |
| | — |
| | (4,960 | ) | | — |
| |
| | Noncurrent Assets | 138 |
| | 2,046 |
| | 133 |
| | (57 | ) | | 2,260 |
| |
| | Total Assets | $ | 9,660 |
| | $ | 10,790 |
| | $ | 2,189 |
| | $ | (10,022 | ) | | $ | 12,617 |
| |
| | Current Liabilities | $ | 1,316 |
| | $ | 3,809 |
| | $ | 1,192 |
| | $ | (5,005 | ) | | $ | 1,312 |
| |
| | Noncurrent Liabilities | 441 |
| | 2,637 |
| | 382 |
| | (57 | ) | | 3,403 |
| |
| | Long-Term Debt | 1,685 |
| | — |
| | — |
| | — |
| | 1,685 |
| |
| | Member's Equity | 6,218 |
| | 4,344 |
| | 615 |
| | (4,960 | ) | | 6,217 |
| |
| | Total Liabilities and Member's Equity | $ | 9,660 |
| | $ | 10,790 |
| | $ | 2,189 |
| | $ | (10,022 | ) | | $ | 12,617 |
| |
| | As of December 31, 2015 | | | | | | | | | | |
| | Current Assets | $ | 4,501 |
| | $ | 1,912 |
| | $ | 364 |
| | $ | (4,828 | ) | | $ | 1,949 |
| |
| | Property, Plant and Equipment, net | 83 |
| | 6,502 |
| | 1,542 |
| | — |
| | 8,127 |
| |
| | Investment in Subsidiaries | 4,501 |
| | 346 |
| | — |
| | (4,847 | ) | | — |
| |
| | Noncurrent Assets | 155 |
| | 1,959 |
| | 136 |
| | (76 | ) | | 2,174 |
| |
| | Total Assets | $ | 9,240 |
| | $ | 10,719 |
| | $ | 2,042 |
| | $ | (9,751 | ) | | $ | 12,250 |
| |
| | Current Liabilities | $ | 1,112 |
| | $ | 3,866 |
| | $ | 1,076 |
| | $ | (4,828 | ) | | $ | 1,226 |
| |
| | Noncurrent Liabilities | 442 |
| | 2,597 |
| | 375 |
| | (76 | ) | | 3,338 |
| |
| | Long-Term Debt | 1,684 |
| | — |
| | — |
| | — |
| | 1,684 |
| |
| | Member's Equity | 6,002 |
| | 4,256 |
| | 591 |
| | (4,847 | ) | | 6,002 |
| |
| | Total Liabilities and Member's Equity | $ | 9,240 |
| | $ | 10,719 |
| | $ | 2,042 |
| | $ | (9,751 | ) | | $ | 12,250 |
| |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | Millions | |
| | As of March 31, 2017 | | | | | | | | | | |
| | Current Assets | $ | 4,244 |
| | $ | 1,332 |
| | $ | 174 |
| | $ | (4,458 | ) | | $ | 1,292 |
| |
| | Property, Plant and Equipment, net | 56 |
| | 5,582 |
| | 2,447 |
| | — |
| | 8,085 |
| |
| | Investment in Subsidiaries | 4,104 |
| | 343 |
| | — |
| | (4,447 | ) | | — |
| |
| | Noncurrent Assets | 175 |
| | 2,154 |
| | 129 |
| | (106 | ) | | 2,352 |
| |
| | Total Assets | $ | 8,579 |
| | $ | 9,411 |
| | $ | 2,750 |
| | $ | (9,011 | ) | | $ | 11,729 |
| |
| | Current Liabilities | $ | 187 |
| | $ | 3,436 |
| | $ | 1,580 |
| | $ | (4,458 | ) | | $ | 745 |
| |
| | Noncurrent Liabilities | 531 |
| | 2,171 |
| | 527 |
| | (106 | ) | | 3,123 |
| |
| | Long-Term Debt | 2,383 |
| | — |
| | — |
| | — |
| | 2,383 |
| |
| | Member’s Equity | 5,478 |
| | 3,804 |
| | 643 |
| | (4,447 | ) | | 5,478 |
| |
| | Total Liabilities and Member’s Equity | $ | 8,579 |
| | $ | 9,411 |
| | $ | 2,750 |
| | $ | (9,011 | ) | | $ | 11,729 |
| |
| | As of December 31, 2016 | | | | | | | | | | |
| | Current Assets | $ | 4,412 |
| | $ | 1,593 |
| | $ | 152 |
| | $ | (4,697 | ) | | $ | 1,460 |
| |
| | Property, Plant and Equipment, net | 55 |
| | 6,145 |
| | 2,320 |
| | — |
| | 8,520 |
| |
| | Investment in Subsidiaries | 4,249 |
| | 344 |
| | — |
| | (4,593 | ) | | — |
| |
| | Noncurrent Assets | 168 |
| | 2,016 |
| | 129 |
| | (100 | ) | | 2,213 |
| |
| | Total Assets | $ | 8,884 |
| | $ | 10,098 |
| | $ | 2,601 |
| | $ | (9,390 | ) | | $ | 12,193 |
| |
| | Current Liabilities | $ | 171 |
| | $ | 3,752 |
| | $ | 1,454 |
| | $ | (4,697 | ) | | $ | 680 |
| |
| | Noncurrent Liabilities | 532 |
| | 2,398 |
| | 502 |
| | (100 | ) | | 3,332 |
| |
| | Long-Term Debt | 2,382 |
| | — |
| | — |
| | — |
| | 2,382 |
| |
| | Member’s Equity | 5,799 |
| | 3,948 |
| | 645 |
| | (4,593 | ) | | 5,799 |
| |
| | Total Liabilities and Member’s Equity | $ | 8,884 |
| | $ | 10,098 |
| | $ | 2,601 |
| | $ | (9,390 | ) | | $ | 12,193 |
| |
| | | | | | | | | | | | |
| |
| ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) |
This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and Power each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG'sPSEG’s business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:
PSE&Gour—which is a public utility company which is engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU, and
Power our—which is a multi-regional wholesale energy supply company that integrates the operations of its merchant nuclear and fossil generating asset operations and gas supply commitmentsassets with its wholesalepower marketing businesses through competitive energy sales in well-developed energy markets and fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA), and the states in which they operate.
PSEG'sPSEG’s other direct wholly owned subsidiaries are:include PSEG Energy Holdings L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments;has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority'sAuthority’s (LIPA) transmission and distribution (T&D) system under aan Operations and Services Agreement contractual agreement; and PSEG Services Corporation (Services), which provides us and these operating subsidiaries with certain management, administrative and general services to PSEG and its subsidiaries at cost.
Our business discussion in Part I, Item 1. Business of our 20152016 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part I, Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of 20152016 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 20162017 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the 20152016 Form 10-K.
EXECUTIVE OVERVIEW OF 20162017 AND FUTURE OUTLOOK
Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:
growing ourimproving utility operations through continued investment in T&D and other infrastructure projects designed to enhance system reliability and resiliency and to meet customer expectations and public policy objectives,
maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.
Financial Results
The results for PSEG, PSE&G and Power for the three months ended March 31, 20162017 and 20152016 are presented as follows:
|
| | | | | | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | Earnings | | 2016 | | 2015 | |
| | | Millions | |
| | PSE&G | | $ | 262 |
| | $ | 242 |
| |
| | Power (A) | | 192 |
| | 335 |
| |
| | Other (B) | | 17 |
| | 9 |
| |
| | PSEG Net Income | | $ | 471 |
| | $ | 586 |
| |
| | | | | | | |
| | PSEG Net Income Per Share (Diluted) | | $ | 0.93 |
| | $ | 1.15 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | Earnings (Losses) | | 2017 | | 2016 | |
| | | Millions | |
| | PSE&G | | $ | 299 |
| | $ | 262 |
| |
| | Power (A) | | (170 | ) | | 192 |
| |
| | Other (B) | | (15 | ) | | 17 |
| |
| | PSEG Net Income | | $ | 114 |
| | $ | 471 |
| |
| | | | | | | |
| | PSEG Net Income Per Share (Diluted) | | $ | 0.22 |
| | $ | 0.93 |
| |
| | | | | | | |
| |
| (A) | Includes an after-tax insurance recoveryexpenses of $334 million primarily for Superstorm Sandyaccelerated depreciation related to the early retirement of $75 millionPower’s Hudson and Mercer coal/gas generation plants in the three months ended March 31, 2015.2017. See Item 1. Note 3. Early Plant Retirements for additional information. |
| |
| (B) | Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded an after-tax charge of $32 million related to its investments in NRG REMA, LLC’s leveraged leases in the three months ended March 31, 2017. See Item 1. Note 6. Financing Receivables for additional information. |
Power’s results above include the realized gains, losses and earnings on the Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity and the impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with forwardfuture delivery dates.
The variances in our Net Income include the changes related to NDT and MTM shown in the following table:
|
| | | | | | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | 2016 | | 2015 | |
| | | Millions, after tax | |
| | NDT Fund Income (Expense) (A) | | $ | (5 | ) | | $ | 2 |
| |
| | Non-Trading MTM Gains (Losses) | | $ | 13 |
| | $ | (20 | ) | |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | 2017 | | 2016 | |
| | | Millions, after tax | |
| | NDT Fund Income (Expense) (A) (B) | | $ | 8 |
| | $ | (5 | ) | |
| | Non-Trading MTM Gains (Losses) (C) | | $ | 6 |
| | $ | 13 |
| |
| | | | | | | |
| |
| (A) | NDT Fund Income (Expense) includes the realized gains and losses, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions, and impairments on certain NDT securities recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization (D&A) Expense. |
| |
| (B) | Net of tax (expense) benefit of $(9) million and $3 million for the three months ended March 31, 2017 and 2016, respectively. |
| |
| (C) | Net of tax (expense) benefit of $(4) million and $(10) million for the three months ended March 31, 2017 and 2016, respectively. |
Our $115$357 million decrease in Net Income for the three months ended March 31, 20162017 was driven primarily by
reduced volumesaccelerated depreciation related to the early retirement of our Hudson and Mercer coal/gas soldgeneration units at Power (see Item 1. Note 3. Early Plant Retirements),
a decrease in energy sales due primarily to lower average realized sales prices, under the BGSS contract,and
lower sales volumes of energy in the PJM and New England regions resulting from unseasonably warm temperatures in 2016 as compared to unusually cold temperatures in 2015,
insurance recoveries received primarily by Power in 2015a charge for estimated losses related to Superstorm Sandy, and
lower operating reserve revenues and capacity revenues in PJM.leveraged lease investments (see Item 1. Note 6. Financing Receivables).
These decreases were partially offset byby:
higher revenues due to increased investments in transmission projects,revenues, and
lower generation costs driven by lower naturalincreased gas prices at Power.distribution revenues.
During the first quarterthree months of 2016,2017, we sustainedmaintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our multi-year, long-term approach to managing our company. Our focus
has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, our merchant generator, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.
At PSE&G, we continue to invest in 2016 we continuedtransmission projects that focus on reliability improvements and replacement of aging infrastructure. We also continue to make investments and seek recovery on such investments made to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014.2014 and to seek recovery on such investments. We also commenced modernizingcontinue to modernize PSE&G's&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. As a result of our Energy Strong Order from the BPU, we will be required to file a distribution base rate case proceeding by no later than November 1, 2017. We cannot predict the impact such proceeding will have on our distribution business.
DuringAlthough the weather in the first quarter of 2016, Power continued to improve its performance for both nuclear and fossil operations, with continued upgrades in efficiency and output, while mitigating environmental impacts.2017 was warmer than normal, Power’s results benefitedsaw a continuing benefit from access to natural gas supplies through its existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the basic gas supply service (BGSS)BGSS arrangement. The contracts are sized to ensureprovide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third partythird-party sales and if excess volume remains after the third-party sales, supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s strategic hedging practices and ability to usecapitalize on market conditions to its advantageopportunities help it to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in 2017 relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.
Our recent investments in the latter half of 2015 and early 2016 in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced as being at risk for early retirement. This situation is generally due to low natural gas prices, and the related decline in market prices of energy, resulting from the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet and greater reliance on natural gas pipelines for fuel delivery.
If trends noted above continue or worsen, our nuclear generating units could cease being economically competitive which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs, and additional funding of nuclear decommissioning trust funds will likely have a material adverse impact on future financial results. We continue to advocate for sound policies that recognize nuclear power as a source of reliable and clean energy and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.
Regulatory, Legislative and Other Developments
In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.
Transmission Planning
In April 2013,2017, the PJM Interconnection, L.L.C. (PJM) initiated its first "open window" solicitation process to allow both incumbents and non-incumbentsBoard announced that it would be lifting the opportunity to submitpreviously disclosed suspension of the Artificial Island transmission project proposalsand approved the award to address identified high voltage issues at Artificial Island in New Jersey. In April 2016, PSE&G accepted construction responsibility for the three components of the project that PJM assigned to it, based on having reached agreement with PJM regarding an estimate for the project baseconstruction of necessary upgrade work in Hope Creek at a cost of $273 million, plus risk and contingency for a total project cost of up to $340approximately $130 million. PSE&G continues to work with PJM to optimize the scope and cost of the project.
In April 2016, PJM filed at FERC to incorporate a voltage threshold into PJM’s Regional Transmission Expansion Plan (RTEP) process to exempt, except under certain circumstances, reliability violations on facilities below 200 kV from PJM’s proposal window process. We generally support this reform as a measure to improve the efficiency of the open window procedure that will permit transmission developers to focus on the projects most likely to benefit from a competitive process.
There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G's&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey and may cause increased scrutiny regarding PSE&G's future capital investments.Jersey. In addition, as a basic generation service (BGS) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to an adjustment, subject to BPU approval. We do not believe that these matters will have a material effect on Power'sPower’s business or results of operations.
Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ base ROEs. While we are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, the results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.
Wholesale Power Market Design
In an important development in the proceedings concerning the actions that had been taken by the states of New Jersey and Maryland to subsidize above-market new generation, on April 19, 2016, the United States Supreme Court affirmed the decision of the lower courts that had held the action in Maryland to be unconstitutional. The Supreme Court’s ruling upholds FERC’s authority to foster competitive wholesale electricity markets and provides guidance to states in balancing their interests to encourage and support the development of renewables and other generating facilities. See Item 5. Other Information—Federal Regulation—Long-Term Capacity Agreement Pilot Program Act for additional information.
Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. In JuneDuring 2015, FERC conditionally acceptedPJM implemented a proposal from PJMnew “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for a capacity performance (CP) product to include generators, Demand Response and energy efficiency providers, which will be required to perform during emergency conditions as a supplementand significant penalties for non-performance. The CP product is expected to be implemented fully for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources (“seasonal resources”). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base capacity product. The proposal included enhanced performance-based incentives and penalties.resources for future auctions. We believe that the auction pricing adequately reflects the increased costs that could result from operating under more stringent rules for generation availability. Baseddo not expect action on the complaints before the upcoming 2020/2021 base residual auction results,in May 2017.
As a result of the CP mechanism appears to have provided the opportunity for enhanced capacity market revenue streams for Power, but future impacts cannot be assured. Further, there may be requirements for additional investment and there are additional performance risks. Applications for rehearingefforts of FERC's CP order are pending.
An emerging issuecertain entities in PJM involvesto obtain financial support arrangements from their state commissions, a group of suppliers requested that FERC direct PJM to expand the impact ofcurrently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized existing generation on RPM market outcomes. These subsidiesgenerators would likely enable the affected generators to submit bids into the PJM capacity marketsmarket that aredid not reflective ofreflect their actual costs of operation and may prevent uneconomic generating facilities from retiring. Either of these conditions could artificially suppress capacity market prices, especially given that PJM’sprices. We are currently effective “minimum offer price rule” (MOPR) which applies only to new gas-fired units, would not apply to these plants. See Item 5. Other Information—Federal Regulation—Capacity Market Issues for additional information.awaiting FERC action on the suppliers’ request and cannot predict the outcome of the proceeding.
Environmental Regulation
We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act (FWPCA) requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs. See Item 1. Note 8. Commitments and Contingent Liabilities for further information.
In October 2015,March 2017, the President of the United States issued an Executive Order that instructed the EPA publishedto review the New Source Performance Standards, which establish emissions standards for CO2 for certain new fossil power plants, and the Clean Power Plan, (CPP), a greenhouse gas emissions regulation under the Clean Air Act (CAA) for existing power plants. The regulationplants that establishes state-specific emission rate targets based on implementation of the best systemssystem of emission reduction. We continue to work with FERC and other federal and state regulators, as well as industry partners, to determine the potential impact of these regulations.
The U.S. Supreme Court’s February 2016 decision to stay the implementationUpon completion of the CPP will delay deadlines for submission of state requests for extensions and final plans. Ifreview, the CPPEPA is upheld, new deadlines will needexpected to be established andsuspend, revise or rescind the effective date of the compliance period may be impacted.rules as appropriate.
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs of any such remediation efforts could be material.
For further information regarding the matters described above as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 8.9. Commitments and Contingent Liabilities.Liabilities.
FERC Compliance
TheSince September 2014, FERC Staff has initiatedbeen conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power'sPower’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. ThisWhile considerable uncertainty remains as to the final resolution of these matters, based upon recent developments in the investigation, is ongoing. The amounts of potentialPower believes the disgorgement and other potential penalties that weinterest costs related to the cost-based bidding matter may incur span a wide range between approximately $35 million and $135 million, depending on the successlegal interpretation of our legal arguments. If our legal arguments do not prevail, in wholethe principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or in part withthe penalties that FERC would impose relating to either the cost-based bidding or in a judicial challenge that we may choose to pursue, it is likely that Power would record losses that wouldquantity of energy matter. However, any of these amounts could be individually material to PSEG'sPSEG and Power'sPower. We cannot predict the final outcome of these matters. For additional information, see Note 9. Commitments and Contingent Liabilities.
Early Retirement of Hudson and Mercer Units
In October 2016, Power determined it will cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. The exact timing of the early retirement of these units may be impacted by operational and other conditions that could subsequently arise. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operations in 2016 and continues to adversely impact their results of operations in 2017. During the quarterlyfirst three months of 2017, Power recognized incremental D&A of $558 million ($574 million in total) and annual periodsexpects to recognize an additional incremental $379 million ($389 million in total) in 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first quarter of 2017, Energy Costs of $7 million for coal inventory adjustments was also incurred and other costs may be incurred during the remaining period in 2017 prior to retirement. See Item 1. Note 3. Early Plant Retirements for additional information.
Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.
In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.
Leveraged Lease Portfolio
GenOn Energy, Inc. (GenOn), the parent company of NRG REMA LLC, (REMA), reported in August 2016 that it did not expect to have sufficient liquidity to repay their senior unsecured notes due in June 2017. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA.
During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain recent discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its investments in the REMA leases, which they are recorded.was reflected in Operating Revenues. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged leases. For additional information, see Item 1. Note 8. Commitments and Contingent Liabilities.
Salem Inspection
In April 2016, during6. Financing Receivables. There can be no assurance that a scheduled refueling outage at Salem Unit 1, a visual inspection revealed degradation to a series of bolts inside the reactor vessel. We have initiated further testing, which is ongoing and is expected to extend the refueling outage. The impactcontinuation or worsening of the outage on Salem Unit 1’s output, marginadverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and cost will depend onsuch write-downs could be material.
Additional facilities in our leveraged lease portfolio include the timingJoliet and resultsShawville generating facilities, which were converted to use natural gas, and Powerton, a coal facility. However, these units may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. As a result, these facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other coal generation facilities, which could require Energy Holdings to write down the residual value of the inspection and necessary repairs.
leveraged leases associated with these facilities.
Salem
Concurrently with the planned refueling outage at the Salem 2 unit that is scheduled for the second quarter of 2017, we intend to inspect and replace degraded baffle bolts as part of our multi-year project to replace baffle bolts at the Salem station.As a result, we expect the duration of this outage to be modestly longer than our typical refueling outage, which will reduce production and lower the nuclear capacity factor for the second quarter of 2017 as compared to the first quarter of 2017.
Operational Excellence
We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of market opportunities presented during the yearin a rapidly evolving market as we remain diligent in managing costs. For the first quarterthree months of 2016,2017, our
our utility continued top decile performance in electric reliability,
total nuclear fleet achieved an average capacity factor of 99.7%100%,
nuclear output increased by 7.5% as compared to the same period in 2015, and
diverse fuel mix and dispatch flexibility allowed us to generate approximately 13 terra-wattterawatt hours while addressing unit outages and balancing fuel availability and price volatility.volatility, and
combined cycle fleet produced three terawatt hours at an equivalent availability factor of 94%.
Financial Strength
Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first quarterthree months of 20162017 as we
had cash on hand of $592 million as of March 31, 2016,maintained sufficient liquidity,
maintained solid investment grade credit ratings, and
increased our indicative annual dividend for 20162017 to $1.64$1.72 per share.
We expect to be able to fund our planned capital requirements without the issuance of new equity.
Disciplined Investment
We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first quarterthree months of 2016,2017, we
made additional investments in transmission infrastructure projects,
began executingcontinued to execute our GSMP, and continued executing Energy Strong and other existing BPU-approved utility programs, and
commencedcontinued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and announced our plan to constructbegan construction of BH5 and commencefor targeted commercial operations in mid-2019, and
acquired three solar energy projects totaling 100 MW-direct current in North Carolina and Colorado expected to go into service during 2016.mid-2019.
Future Outlook
Our future success will depend on our ability to continue to maintain strong operational and financial performance in a slow-movingslow-growing economy and a cost-constrained environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to:
focus on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,
successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,
execute our utility capital investment program, including our Energy Strong program, GSMP and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,
effectively manage construction and start-up of our Keys Energy Center (Keys) , Sewaren 7, BH5(BH5) and other generation projects,
advocate for measures to ensure the implementation by PJM and FERC of market design and transmission planning rules that continue to promote fair and efficient electricity markets,
engage multiple stakeholders, including regulators, government officials, customers and investors, and
successfully operate the LIPA T&D system and manage LIPA'sLIPA’s fuel supply and generation dispatch obligations.
For 20162017 and beyond, the key issues and challenges we expect our business to confront include:
regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,
fair and timely rate relief from the BPU and FERC Staff’s continuing investigationfor recovery of certaincosts and return on investments, including with respect to our distribution base rate case proceeding to be filed in 2017,
the potential for comprehensive tax reform, particularly in light of Power’s New Jersey fossil generating unit bids inpublic statements by the PJM energy market,current U.S. administration and key members of Congress,
uncertainty in the slowly improving national and regional economic recovery,performance, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,
the potential for continued reductions in demand and sustained lower natural gas and electricity prices, both at market hubs and the locations where we operate,
the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,
delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory approvals.approvals,
maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and
FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.
Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:
the acquisition, construction or disposition of transmission and distribution facilities and/or generation units,
the disposition or reorganization of our merchant generation business or other existing businesses or the acquisition or development of new businesses,
the expansion of our geographic footprint,
continued or expanded participation in solar, demand response and energy efficiency programs, and
investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, and modernizing existing infrastructure.infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.
In 2016, Power announced its intention to develop a retail platform to sell physical electricity and natural gas, which we believe would begin to complement our existing wholesale marketing business. Power was granted licenses in 2016 to sell both electricity and gas in the states of New Jersey and Pennsylvania.
There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.
RESULTS OF OPERATIONS
PSEG
Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PSE&G and Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note 17.18. Related-Party Transactions.
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Three Months Ended | | Increase/ (Decrease) | |
| | | | March 31, | | |
| | | | 2016 | | 2015 | | 2016 vs. 2015 | |
| | | | Millions | | Millions | | % | |
| | Operating Revenues | | $ | 2,616 |
| | $ | 3,135 |
| | $ | (519 | ) | | (17 | ) | |
| | Energy Costs | | 836 |
| | 1,094 |
| | (258 | ) | | (24 | ) | |
| | Operation and Maintenance | | 729 |
| | 663 |
| | 66 |
| | 10 |
| |
| | Depreciation and Amortization | | 224 |
| | 330 |
| | (106 | ) | | (32 | ) | |
| | Income from Equity Method Investments | | 2 |
| | 3 |
| | (1 | ) | | (33 | ) | |
| | Other Income and (Deductions) | | 27 |
| | 36 |
| | (9 | ) | | (25 | ) | |
| | Other-Than-Temporary Impairments | | 10 |
| | 5 |
| | 5 |
| | N/A |
| |
| | Interest Expense | | 92 |
| | 98 |
| | (6 | ) | | (6 | ) | |
| | Income Tax Expense | | 283 |
| | 398 |
| | (115 | ) | | (29 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Three Months Ended | | Increase/ (Decrease) | |
| | | | March 31, | | |
| | | | 2017 | | 2016 | | 2017 vs. 2016 | |
| | | | Millions | | Millions | | % | |
| | Operating Revenues | | $ | 2,592 |
| | $ | 2,616 |
| | $ | (24 | ) | | (1 | ) | |
| | Energy Costs | | 874 |
| | 836 |
| | 38 |
| | 5 |
| |
| | Operation and Maintenance | | 712 |
| | 729 |
| | (17 | ) | | (2 | ) | |
| | Depreciation and Amortization | | 828 |
| | 224 |
| | 604 |
| | 270 |
| |
| | Income from Equity Method Investments | | 3 |
| | 2 |
| | 1 |
| | 50 |
| |
| | Other Income (Deductions) | | 61 |
| | 27 |
| | 34 |
| | 126 |
| |
| | Other-Than-Temporary Impairments | | 1 |
| | 10 |
| | (9 | ) | | (90 | ) | |
| | Interest Expense | | 98 |
| | 92 |
| | 6 |
| | 7 |
| |
| | Income Tax Expense | | 29 |
| | 283 |
| | (254 | ) | | (90 | ) | |
| | | | | | | | | | | |
The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.
PSE&G
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Three Months Ended | | Increase/ (Decrease) | |
| | | | March 31, | | |
| | | | 2016 | | 2015 | | 2016 vs. 2015 | |
| | | | Millions | | Millions | | % | |
| | Operating Revenues | | $ | 1,712 |
| | $ | 2,002 |
| | $ | (290 | ) | | (14 | ) | |
| | Energy Costs | | 729 |
| | 892 |
| | (163 | ) | | (18 | ) | |
| | Operation and Maintenance | | 382 |
| | 412 |
| | (30 | ) | | (7 | ) | |
| | Depreciation and Amortization | | 139 |
| | 247 |
| | (108 | ) | | (44 | ) | |
| | Other Income (Deductions) | | 19 |
| | 17 |
| | 2 |
| | 12 |
| |
| | Interest Expense | | 68 |
| | 69 |
| | (1 | ) | | (1 | ) | |
| | Income Tax Expense | | 151 |
| | 157 |
| | (6 | ) | | (4 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Three Months Ended | | Increase/ (Decrease) | |
| | | March 31, | | |
| | | 2017 | | 2016 | | 2017 vs. 2016 | |
| | | Millions | | Millions | | % | |
| | Operating Revenues | $ | 1,812 |
| | $ | 1,712 |
| | $ | 100 |
| | 6 |
| |
| | Energy Costs | 753 |
| | 729 |
| | 24 |
| | 3 |
| |
| | Operation and Maintenance | 367 |
| | 382 |
| | (15 | ) | | (4 | ) | |
| | Depreciation and Amortization | 171 |
| | 139 |
| | 32 |
| | 23 |
| |
| | Other Income (Deductions) | 24 |
| | 19 |
| | 5 |
| | 26 |
| |
| | Interest Expense | 75 |
| | 68 |
| | 7 |
| | 10 |
| |
| | Income Tax Expense | 171 |
| | 151 |
| | 20 |
| | 13 |
| |
| | | | | | | | | | |
Three Months Ended March 31, 20162017 as Compared to 20152016
Operating Revenues decreased $290increased $100 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues increased $29$58 million due primarily to an increase in transmission revenues.
Transmission revenues were $53$37 million higher due to increased capitalhigher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
ElectricGas distribution revenues decreased $23increased $24 million due primarily to loweran $11 million increase due to the inclusion of Energy Strong in base rates, a $5 million increase due to the Gas System Modernization Program, $4 million of higher delivery volumes, higher Green Program Recovery Charges (GPRC) of $14$2 million and $10 million in lower sales volumes.
Gas distribution revenues decreased $1 million due primarily to $76 million lower delivery volume and lower GPRC of $6 million due to lower sales volumes from warmer winter weather. These decreases were almost entirely offset by $73$2 million in higher Weather Normalization Clause (WNC) revenue and $8revenue.
Electric distribution revenues decreased $3 million due to roll inlower GPRC of $3 million and a $2 million decrease due to lower sales volumes, partially offset by a $2 million increase due to the inclusion of Energy Strong intoin base rates effective September 1, 2015.rates.
Commodity Revenue decreased $163increased $24 million as a result of lowerhigher Gas andrevenues partially offset by lower Electric revenues. The changes in Commodity revenue for both gas and electric isare entirely offset with decreasedby the changes in Energy Costs. PSE&G earns no margin on the provision of Basic Gas Supply Servicebasic gas supply service (BGSS) and basic generation service (BGS)BGS to retail customers.
Gas commodity revenues decreased $109 million due to lower BGSS volume.
Electric revenues decreased $54increased $74 million due primarily to a $35higher BGSS sales prices.
Electric commodity revenues decreased $50 million or 8% decrease in BGS revenues due primarily to lower sales volumes, $11$23 million of lower revenues from collections of Non-Utility Generation Charges (NGC), a $17 million decrease in BGS revenues due to lower sales prices and volumes and a decrease of $8$10 million due to higherlower volumes of Non-Utility Generation (NUG) energy sold at lower prices.sold.
Clause Revenues decreased $155increased $19 million due primarily to lowerthe 2016 return to customers of $15 million of overcollections of Securitization Transition Charges (STC) of $129 million, and lowerhigher Societal Benefit Charges (SBC) of $33$2 million partially offset by higher Margin Adjustment Clause Revenue (MAC) of $12 million. The STC reduction is a result of rate reductions due to the completion of securitization collections in 2015.2017. The changes in the STC SBC and MACSBC amounts are entirely offset by decreases in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC or SBC or MAC collections.
Other Operating Revenues experienced no material change.
Operating Expenses
Energy Costs decreased $163increased $24 million. This is entirely offset by the change in Commodity Revenue.
Operation and Maintenance decreased $30$15 million, of which the most significant components were
a $44$6 million decrease in appliance service costs,
a $4 million decrease in distribution corrective and preventative maintenance,
a $2 million decrease in pension and OPEB costs, net of capitalized amounts and
a $3 million net reductiondecrease in costs related to various clause mechanisms and GPRC,
partially offset by $15 million of storm insurance recovery proceeds received in 2015.operational expenses.
Depreciation and Amortization decreased $108increased $32 million due primarily to a decreasean increase of $124$17 million in amortization of Regulatory Assets primarily asand a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by a $16$14 million increase in depreciation due to of additional plant in service.
Other Income and (Deductions) increased $5 million due primarily to an increase of $3 million in Allowance for Funds Used During Construction and a $3 million increase in realized gains on Rabbi Trust investments.
Interest Expense increased $7 million due primarily to net debt issuances in 2016.
Income Tax Expense decreased $6increased $20 million due primarily to depreciation flow through items and uncertain tax positions offset by higher pre-tax income.
Power
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Three Months Ended | | Increase/ (Decrease) | |
| | | | March 31, | | |
| | | | 2016 | | 2015 | | 2016 vs. 2015 | |
| | | | Millions | | Millions | | % | |
| | Operating Revenues | | $ | 1,313 |
| | $ | 1,725 |
| | $ | (412 | ) | | (24 | ) | |
| | Energy Costs | | 638 |
| | 893 |
| | (255 | ) | | (29 | ) | |
| | Operation and Maintenance | | 253 |
| | 172 |
| | 81 |
| | 47 |
| |
| | Depreciation and Amortization | | 79 |
| | 76 |
| | 3 |
| | 4 |
| |
| | Income from Equity Method Investments | | 2 |
| | 3 |
| | (1 | ) | | (33 | ) | |
| | Other Income (Deductions) | | 8 |
| | 18 |
| | (10 | ) | | (56 | ) | |
| | Other-Than-Temporary Impairments | | 10 |
| | 5 |
| | 5 |
| | N/A |
| |
| | Interest Expense | | 22 |
| | 31 |
| | (9 | ) | | (29 | ) | |
| | Income Tax Expense | | 129 |
| | 234 |
| | (105 | ) | | (45 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Three Months Ended | | Increase/ (Decrease) | |
| | | | March 31, | | |
| | | | 2017 | | 2016 | | 2017 vs. 2016 | |
| | | | Millions | | Millions | | % | |
| | Operating Revenues | | $ | 1,284 |
| | $ | 1,313 |
| | $ | (29 | ) | | (2 | ) | |
| | Energy Costs | | 707 |
| | 638 |
| | 69 |
| | 11 |
| |
| | Operation and Maintenance | | 230 |
| | 253 |
| | (23 | ) | | (9 | ) | |
| | Depreciation and Amortization | | 650 |
| | 79 |
| | 571 |
| | N/A |
| |
| | Income from Equity Method Investments | | 3 |
| | 2 |
| | 1 |
| | 50 |
| |
| | Other Income (Deductions) | | 31 |
| | 8 |
| | 23 |
| | N/A |
| |
| | Other-Than-Temporary Impairments | | 1 |
| | 10 |
| | (9 | ) | | (90 | ) | |
| | Interest Expense | | 16 |
| | 22 |
| | (6 | ) | | (27 | ) | |
| | Income Tax Expense (Benefit) | | (116 | ) | | 129 |
| | (245 | ) | | N/A |
| |
| | | | | | | | | | | |
Three Months Ended March 31, 20162017 as Compared to 20152016
Operating Revenues decreased $41229 million due to changes in generation and gas supply revenues.
Generation Revenues decreased $174 million due primarily to
a decrease of $75 million primarily in the PJM region due to lower operating reserve revenue coupled with lower capacity revenues resulting from the retirement of older peaking units in June 2015,
lower net revenues of $75 million due primarily to milder weather which led to lower energy volumes sold in the PJM and NE regions and lower average realized prices,
a decrease of $38 million due primarily to lower volumes of electricity sold under fewer wholesale load contracts in the PJM and NE regions coupled with lower average prices,
a net decrease of $25 million due primarily to lower volumes of electricity sold under the BGS contracts as a result of milder weather partially offset by higher average prices, and
partially offset by an increase of $39 million due to MTM gains in 2016 as compared to MTM losses in 2015.
Gas SupplyGeneration Revenuesdecreased $238decreased $124 million due primarily to
a net decrease of $220$95 million in energy sales in the PJM and New England (NE) regions due primarily to lower average realized prices, and
a net decrease of $24 million due to MTM losses in 2017 as compared to MTM gains in 2016. Of this amount, $131 million was due to changes in forward power prices. The decrease was offset by an increase of $107 million due to losses on positions reclassified to realized upon settlement this year as compared to gains last year, and
a charge of $10 million due to an increase in the FERC accrual related to the PJM bidding matter, see Note 9. Commitments and Contingent Liabilities,
partially offset by a net increase of $10 million due primarily to higher volumes of electricity sold under wholesale load contracts in the NE region partially offset by lower average prices.
Gas Supply Revenuesincreased $95 million due primarily to
an increase of $46 million in sales under the BGSS contract substantially comprised of lowerdue primarily to higher average sales prices coupled with an increase in sales volumes due to warmer average temperaturesperiods of colder weather in the 2016 winter heating season, coupled with lowerMarch,
an increase of $41 million related to sales to third parties due to higher average sales prices, and
a net decreaseincrease of $18$8 million on sales to third party customers, of which $47 million was due to lower average sales prices, partially offset by $29 million of higher volumes sold.MTM gains in 2017 as compared to 2016, primarily due to losses on positions reclassified to realized upon settlement this year as compared to gains last year.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased$255increased $69 million due to
Generation costsdecreased $123decreased $1 million due primarily to
a net decrease of $26 million primarily due to lower congestion costs in PJM due to lower congestion rates and volumes,
partially offset by higher fuel costs of $234$14 million reflecting lowerhigher average realized prices for natural gas prices andcoupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of coal,gas and oil, and gas. These decreased costs were partially offset by higher congestion costs
an increase of $8 million in energy purchase volumes in the PJMNE region to serve load obligations, and
a $7 million charge associated primarily with a lower of $145 million, mainly as a result of credits received in the prior year due to extremely cold weather. Also, lower MTM losses in 2016 resulted in a $20 million decrease.cost or market coal inventory adjustment at Mercer.
Gas costs decreasedincreased $132$70 million due mainly to
an increase of $39 million related to a decrease in volumes soldsales to third parties due to higher average gas costs, and
an increase of $31 million related to sales under the BGSS contract coupled with lowerdue primarily to higher average gas costs. Gas costs on salesand an increase in volumes sold due to third parties were flat.
periods of colder weather in March.Operation and Maintenance increased $81decreased $23 million due primarily to
$128a $15 million of insurance recoveries received in 2015 related to Superstorm Sandy,
partially offset by a net decrease of $48 million related to our fossilnuclear plants largelydue primarily to lower labor-related costs, and
a $7 million legal reserve for environmental expenses recorded in 2016.
Depreciation and Amortization increased$571 milliondue primarily to
$558 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,
$4 million of greater depreciation due to the accelerated retirement date at Bridgeport Harbor 3,
a $4 million increase due to a higher costs incurred in 2015 for planned major outages.nuclear asset base, and
$3 million of higher depreciation due to new solar projects.
Other Income and (Deductions) decreased $10increased $23 million due primarily to higher$17 million of lower net realized losses from the NDT Fund in 2017 and $3 million of higher realized gains in the Rabbi Trust Fund.
Other-Than-Temporary Impairments increased $5decreased $9 million due primarily to an increase inlower impairments of equity securities in the NDT Fund.Fund in 2017.
Interest Expense decreased $9$6 million due primarily to higher interest capitalized for the maturityconstruction of a $300 million 5.50% Senior Note in December 2015three new fossil stations: BH5, Sewaren 7 and higher capitalized interest in 2016.Keys.
Income Tax Expense decreased $105$245 million in 20162017 due primarily to lowera pre-tax income.loss in 2017 as compared to pre-tax income in 2016.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.
Operating Cash Flows
We expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder dividend payments.
For the three months ended March 31, 20162017, our operating cash flow decreased $46518 million as compared to the same period in 2015.2016. The net change was primarily due primarily to the net changes from PSE&G and Power as discussed below.below largely offset by higher tax refunds in 2017 at Energy Holdings.
PSE&G
PSE&G’s operating cash flow decreased $10954 million from $677568 million to $568514 million for the three months ended March 31, 20162017, as compared to the same period in 20152016, due primarily to a decreaselower tax refunds, partially offset by higher earnings, and an increase of $83$45 million due to a change in regulatory deferrals primarily driven by lower volumes due to warmer weather impacting our Gas Weather Normalization, SBC, GPRCdeferrals.
and BGSS clauses, a $42 million decrease in other current assets and liabilities and a $40 million decrease due to vendor payments. These amounts were partially offset by higher earnings and a reduction in tax payments.
Power
Power’s operating cash flow decreased $18783 million from $850663 million to $663580 million for the three months ended March 31, 20162017, as compared to the same period in 2015,2016, primarily due to tax payments in 2017 as compared to tax refunds in 2016 and lower earnings, and a $141 million decrease for fuel, materials and supplies, partially offset by a reduction in tax payments.$65 million increase from net collection of counterparty receivables and a $12 million increase from fuels, materials and supplies.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
The commitments underWe continually monitor our $4.3 billion credit facilities are provided by a diverse bank group. As of March 31, 2016,liquidity and seek to add capacity as needed to meet our total available credit capacity was $4.0 billion.
As of March 31, 2016, no single institution represented more than 7% of the total commitments in our credit facilities.
As of March 31, 2016, our total credit capacity was in excess of our anticipated maximum liquidity requirements.
Each of our credit facilities is restricted as to availability and use to the specific companies as listed in the following table;below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries'subsidiaries’ liquidity needs.
In March 2017, PSEG, Power and PSE&G amended their credit agreements, extending the expiration dates to March 2022. Concurrently, PSEG increased its existing $1 billion in credit facilities to $1.5 billion, Power decreased its existing $2.6 billion in credit facilities to $2.1 billion, which includes two new 3-year $100 million letter of credit facilities that expire in March 2020.
Our total credit facilities and available liquidity as of March 31, 20162017 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | As of March 31, 2016 | | | | | |
| | Company/Facility | | Total Facility | | Usage (D) | | Available Liquidity | | Expiration Date | | Primary Purpose | |
| | | | Millions | | | | | |
| | PSEG | | | | | | | | | | | |
| | 5-year Credit Facility | | $ | 500 |
| | $ | 10 |
| | $ | 490 |
| | Apr 2019 | | Commercial Paper (CP) Support/Funding/Letters of Credit | |
| | 5-year Credit Facility (A) | | 524 |
| | 12 |
| | 512 |
| | Apr 2020 | | CP Support/Funding/Letters of Credit | |
| | Total PSEG | | $ | 1,024 |
| | $ | 22 |
| | $ | 1,002 |
| | | | | |
| | PSE&G | | | | | | | | | | | |
| | 5-year Credit Facility (B) | | $ | 629 |
| | $ | 14 |
| | $ | 615 |
| | Apr 2020 | | CP Support/Funding/Letters of Credit | |
| | Total PSE&G | | $ | 629 |
| | $ | 14 |
| | $ | 615 |
| | | | | |
| | Power | | | | | | | | | | | |
| | 5-year Credit Facility | | $ | 1,600 |
| | $ | 202 |
| | $ | 1,398 |
| | Apr 2019 | | Funding/Letters of Credit | |
| | 5-year Credit Facility (C) | | 1,000 |
| | 9 |
| | 991 |
| | Apr 2020 | | Funding/Letters of Credit | |
| | Total Power | | $ | 2,600 |
| | $ | 211 |
| | $ | 2,389 |
| | | | | |
| | Total | | $ | 4,253 |
| | $ | 247 |
| | $ | 4,006 |
| | | | | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | Company/Facility | | As of March 31, 2017 | |
| | Total Facility | | Usage | | Available Liquidity | |
| | | | Millions | |
| | PSEG | | $ | 1,500 |
| | $ | 332 |
| | $ | 1,168 |
| |
| | PSE&G | | 600 |
| | 14 |
| | 586 |
| |
| | Power | | 2,100 |
| | 235 |
| | 1,865 |
| |
| | Total | | $ | 4,200 |
| | $ | 581 |
| | $ | 3,619 |
| |
| | | | | | | | | |
| |
(A) | PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018; PSEG's 2020 credit facility was increased by $24 million in March 2016 in anticipation of the April expiration. |
| |
(B) | PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018; PSE&G's 2020 facility was increased by $29 million in March 2016 in anticipation of the April expiration. |
(C)As of March 31, 2017, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power facility will be reduced by $48 million in April 2016 and $24 million in March 2018.losing its investment grade credit rating from S&P or Moody’s, which
| |
(D) | The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs under which as of March 31, 2016, PSEG had $12 million outstanding at a weighted average interest rate of 0.65%. PSE&G had no amounts outstanding under its CP Program as of March 31, 2016. |
Long-Term Debt Financing
would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s credit rating certain of Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if Power has $303were to lose its investment grade credit rating was approximately $801 million and $783 million as of 5.32% Senior NotesMarch 31, 2017 and $250 millionDecember 31, 2016, respectively. The early retirement of 2.75% Senior Notes maturing in September 2016.Power’s Hudson and Mercer coal/gas generation units is not expected to have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 1. Note 3. Early Plant Retirements.
For a discussion of our long-term debt transactions during 2016,additional information, see Item 1. Note 9. Changes10. Debt and Credit Facilities.
Long-Term Debt Financing
PSEG Parent has a floating rate $500 million term loan maturing in Capitalization.November 2017.
Common Stock Dividends
On February 16, 2016,21, 2017, our Board of Directors approved a $0.41$0.43 dividend per share of common stock dividend for the first quarter of 2016.2017. On April 19, 2016,18, 2017, our Board of Directors declared a quarterly$0.43 dividend of $0.41 per share of common stock for the second quarter of 2016.2017. This reflects an indicative annual dividend rate of $1.64$1.72 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. Note 15.Note16. Earnings Per Share (EPS) and Dividends.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies'agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
In January 2016,April 2017, S&P published updated research reports onand affirmed the ratings and outlooks of PSEG and PSE&G and the existing ratings and outlooks were unchanged. In March 2016, Moody's published an updated research report on Power and the existing&G. PSEG Power’s rating and outlook werealso remain unchanged.
|
| | | | | | |
| | | | | | | |
| | | | Moody’s (A) | | S&P (B) | |
| | PSEG | | | | | |
| | Outlook | | Positive | | Stable | |
| Senior Notes | | Baa2 | | BBB | |
| | Commercial Paper | | P2 | | A2 | |
| | PSE&G | | | | | |
| | Outlook | | Stable | | Stable | |
| | Mortgage Bonds | | Aa3 | | A | |
| | Commercial Paper | | P1 | | A2 | |
| | Power | | | | | |
| | Outlook | | Stable | | Stable | |
| | Senior Notes | | Baa1 | | BBB+ | |
| | | | | | | |
| |
| (A) | Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. |
| |
| (B) | S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. The Corporate Credit Rating outlook does not apply to PSEG's or PSE&G's Commercial Paper Rating or PSE&G's Mortgage Bond rating. |
CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures at PSE&G, Power and Services as compared to amounts disclosed in our 20152016 Form 10-K.
PSE&G
During the three months ended March 31, 2016,2017, PSE&G made capital expenditures of $724$752 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of $35$24 million, which are included in operating cash flows.
Power
During the three months ended March 31, 2016,2017, Power made capital expenditures of $283$274 million, excluding $5033 million for nuclear fuel, primarily related to our Keys, Sewaren 7, BH5 and other generation projects.
ACCOUNTING MATTERS
For information related to recent accounting matters, see Item 1. Note 2. Recent Accounting Standards.
| |
| ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.
Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.
Commodity Contracts
The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.
Value-at-Risk (VaR) Models
VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.
MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting.hedges. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities.
The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.
From January through March 2016,2017, MTM VaR remained relatively stable between a low of $11$7 million toand a high of $25 million at the 95% confidence level. The range of VaR was narrower for the three months ended March 31, 20162017 as compared with the year ended December 31, 2015.2016.
|
| | | | | | | | | | |
| | | | | | | |
| | | | MTM VaR | |
| | | | Three Months Ended March 31, 2016 | | Year Ended December 31, 2015 | |
| | | | Millions | |
| | 95% Confidence Level, Loss could exceed VaR one day in 20 days | | | | | |
| | Period End | | $ | 11 |
| | $ | 24 |
| |
| | Average for the Period | | $ | 17 |
| | $ | 17 |
| |
| | High | | $ | 25 |
| | $ | 40 |
| |
| | Low | | $ | 11 |
| | $ | 8 |
| |
| | 99.5% Confidence Level, Loss could exceed VaR one day in 200 days | | | | | |
| | Period End | | $ | 17 |
| | $ | 38 |
| |
| | Average for the Period | | $ | 27 |
| | $ | 26 |
| |
| | High | | $ | 40 |
| | $ | 63 |
| |
| | Low | | $ | 17 |
| | $ | 12 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | MTM VaR | |
| | | | Three Months Ended March 31, 2017 | | Year Ended December 31, 2016 | |
| | | | Millions | |
| | 95% Confidence Level, Loss could exceed VaR one day in 20 days | | | | | |
| | Period End | | $ | 7 |
| | $ | 26 |
| |
| | Average for the Period | | $ | 12 |
| | $ | 16 |
| |
| | High | | $ | 25 |
| | $ | 32 |
| |
| | Low | | $ | 7 |
| | $ | 10 |
| |
| | 99.5% Confidence Level, Loss could exceed VaR one day in 200 days | | | | | |
| | Period End | | $ | 11 |
| | $ | 40 |
| |
| | Average for the Period | | $ | 19 |
| | $ | 25 |
| |
| | High | | $ | 39 |
| | $ | 51 |
| |
| | Low | | $ | 10 |
| | $ | 16 |
| |
| | | | | | | |
See Item 1. Note 10.11. Financial Risk Management Activities for a discussion of credit risk.
| |
| ITEM 4. | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
PSEG, PSE&G and Power
We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of Public Service Enterprise Group Incorporated, Public Service ElectricPSEG, PSE&G and Gas Company and PSEG Power LLC.Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of Public Service Enterprise Group Incorporated, Public Service ElectricPSEG, PSE&G and Gas Company and PSEG Power LLC have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.
Internal Controls
PSEG, PSE&G and Power
There have been no changes in internal control over financial reporting that occurred during the first quarter of 20162017 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.
PART II. OTHER INFORMATION
We are party to various lawsuits and regulatory matters in the ordinary course of business. For additional information regarding material legal proceedings, including updates to information reported in Item 3 of Part I of the 20152016 Annual Report on Form 10-K, see Part I, Item 1. Note 8.9. Commitments and Contingent Liabilities and Item 5. Other Information.
Environmental Matters
The following updates information previously reported in Item 3 of Part I of the 2015 Annual Report on Form 10-K.
| |
(1) | Claim by the EPA, Region III, under CERCLA with respect to the Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and the former and current site owners are alleged to be liable for contamination at the site and PSE&G has been named as a Potentially Responsible Party (PRP). The EPA approved the Final Revised Remedial Design for the Site in early 2008. This document presented the design details of the EPA’s selected remedy. PSE&G and other utility companies as members of a PRP group entered into a Consent Decree and agreed to implement |
the negotiated EPA selected remedy. The EPA settled its claims against the site owners who did not join the Consent Decree to implement the remedy. The PRP group’s implementation of the remedy was completed in 2010; however, an additional estimated cost of $200,000 will be incurred by PSE&G in 2016 to repair part of the remedy. Although the PRP Group has not received a formal Certification of Completion of the Remedy from the EPA, the PRP Group does not anticipate further significant costs at this time. Although subject to EPA approval and oversight, long-term monitoring, operations, and maintenance activities are anticipated through 2018 at a total estimated cost to PSE&G of $200,000.
There are no additional Risk Factors toThe discussion of our business and operations in this Quarterly Report on Form 10-Q should be added to those disclosedread together with the risk factors contained in Part I, Item 1A of our 20152016 Annual Report on Form 10-K.10-K, which describe various risks and uncertainties that could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report. Except as follows, there have been no material changes to the risk factors set forth in the above-referenced filing as of March 31, 2017.
We may be unable to obtain an adequate fuel supply in the future.
We obtain substantially all of our physical natural gas, coal and nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and other contracts to ensure that the natural gas, coal and nuclear fuel are delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.
Additionally, the PJM power market has recently experienced an increase in natural gas-fired generation assets that supply electricity to the region. As a result, there has been a corresponding increase in the need for natural gas transportation assets to serve power generation assets. When extreme cold temperatures significantly increase the demand for natural gas used for residential heating, it can also create constraints on natural gas pipelines that serve power generation assets. When these conditions exist, it could interrupt the fuel supply to our natural gas-fired power plants in the PJM power market.
We are exposed to increases in the price of natural gas, coal and nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of natural gas, coal and nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of natural gas, coal and nuclear fuel by, our power plants including the following:
transportation may be unavailable if pipeline infrastructure is damaged or disabled;
pipeline tariff changes may adversely affect our ability to, or cost to, deliver such fuels;
creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;
market liquidity for physical supplies of such fuels or availability of related services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;
variation in the quality of such fuels may adversely affect our power plant operations;
legislative or regulatory actions or requirements, including those related to pipeline integrity inspections, may increase the cost of such fuels;
fuel supplies diverted to residential heating may limit the availability of such fuels for our power plants; and
the loss of critical infrastructure, terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.
Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, such fuel may not be available at any price, or we may not be able to transport it to our facilities on a timely basis. In this case, we may not be able to run those facilities even if it would be profitable. If we had sold forward the power from such a facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.
In March 2017, Westinghouse Electric Company (WEC) announced that it had filed for Chapter 11 bankruptcy in New York. WEC provides nuclear fuel fabrication services for Salem Units 1 and 2. In the event that WEC is unable to continue to provide fabrication services, we can provide no assurance that we would be able to find alternative providers of such services in a timely manner or on acceptable terms. As a result, a failure by WEC to perform its obligations during the pendency of, or following its emergence from, bankruptcy could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.
Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our liquidity, financial condition and results of operations. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used could impact our results of operations.
| |
| ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the first quarter of 20162017.
|
| | | | | | | | |
| | | | | | |
| | Three Months Ended March 31, 2016 | Total Number of Shares Purchased | | Average Price Paid per Share | |
| | January 1 - January 31 | — |
| | $ | — |
| |
| | February 1- February 29 | 621,983 |
| | $ | 43.62 |
| |
| | March 1- March 31 | 493,764 |
| | $ | 42.92 |
| |
| | | | | | |
|
| | | | | | | | |
| | | | | | |
| | Three Months Ended March 31, 2017 | Total Number of Shares Purchased | | Average Price Paid per Share | |
| | January 1 - January 31 | — |
| | $ | — |
| |
| | February 1 - February 28 | — |
| | $ | — |
| |
| | March 1- March 31 | 927,971 |
| | $ | 44.94 |
| |
| | | | | | |
ITEM 5. OTHER INFORMATION
Certain information reported in the 20152016 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 20152016 Annual Report on Form 10-K. References are to the related pages on the FormForms 10-K as printed and distributed.
Employee RelationsFederal Regulation
FERC
Capacity Market Issues
December 31, 20152016 Form 10-K page 16. DuringPJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the first quartermarket design for each of 2016, fourthese three capacity markets is working optimally. Issues presented in various forums include consideration of PSEG's eight labor unions ratifiedwhether the extension of their respective collective bargaining agreementscompetitive market framework can be reconciled with PSEG for four years effective May 1, 2017. Collectively, these unions represent approximately 75 percent of PSEG's total union employees. Therefore, as of March 31, 2016, our collective bargaining agreements will expirestate public policies that support particular resources or resource attributes, whether generators are being sufficiently compensated in November 2016the capacity market and whether subsidized resources may be adversely affecting capacity market prices. We cannot predict what action, if any, FERC might take with one union, in October 2017 with two unions, in May 2018 with one union and in April 2021 with four unions. We believe we maintain satisfactory relationships with our employees.regard to capacity market designs.
Federal Regulation
FERC
Capacity Market Issues—PJM
December 31, 2016 Form 10-K page 16. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. However, aspects of FERC’s order are currently pending appeal in the Court of Appeals for the D.C. Circuit (D.C. Circuit). The CP product will be implemented fully for the 2020-2021 Delivery Year. FERC has approved changes to the CP construct that will enhance the participation of intermittent and DR resources (“seasonal resources”). Specifically, FERC approved PJM’s modifications to the aggregation rules to improve the ability of seasonal resources to participate. However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions. We do not expect action on the complaints before the upcoming base residual auction in May 2017.
Capacity Market Issues—ISO-NE
December 31, 2016 Form 10-K page 17. An emerging issueISO-NE’s market for installed capacity in PJM involvesNew England provides fixed capacity payments for generators, imports and DR. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the impactlocational value of subsidized generationresources on RPM market outcomes. In particular, FirstEnergy Corp. (FE)the system and American Electric Power (AEP) have proposedcontains incentive mechanisms to enter into power purchase agreements (PPAs) with their non-utility generation affiliates providing for above-market purchases from certain coal plants andencourage availability during stressed system conditions. ISO-NE also employs a nuclear plant (in FE's case). The Ohio Public Utility Commission (PUCO) recently approved the PPAs on termsmechanism, similar to PJM’s CP mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance. One aspect of the terms sought by those companies. The Dayton Powercurrent market design that we do not support and Light Company has recently also filed for comparable arrangements covering generating plants that it owns. The subsidies under these contracts would likely enable the affected generators to submit bids into PJM capacity markets that are not reflective of their actual costs of operation and may prevent uneconomic generating facilities from retiring. Either of these conditions could artificially suppress capacity market prices, especially given that PJM’s currently effective “minimum offer price rule” (MOPR) which applies only to new gas-fired units would not apply to these plants. On April 27, 2016, FERC issued orders finding that the PPAs should be reviewed to determine whether they comport with the Commission’s standards for contracts. In another proceeding at FERC, certain parties are claiming that PJM should be directed to expand the MOPR to apply to existing contracts, including the FE and AEP PPAs.
We are unable to predict the results of these pending proceedings or any future related proceedings or to calculate the potential impacts on our business.
Capacity Market Issues—ISO-New England
December 31, 2015 Form 10-K page 18. In March 2015,challenging in conjunction with other companies, we filed a petition for review with the D.C. Court of FERC's ruling acceptingCircuit is the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources. On
Price Formation Initiatives
December 1, 2015, following a request by31, 2016 Form 10-K page 18. Power has been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for a voluntary remand of the order, the D.C. Court remanded the case to FERCsetting prices for additional consideration. However, on April 8, 2016, FERC issued an order reinstating the exemption. We are currentlyenergy in the processday-ahead and real-time markets administered by PJM and other system operators. FERC recently issued a notice of analyzing this development.proposed rulemaking (NOPR) proposing that RTOs/ISOs modify their rules governing fast-start resources. Fast-start resources typically are committed in real-time, very
close to the interval when needed and can respond quickly to unforeseen system needs. However, without fast-start pricing, some fast-start resources are ineligible to set prices due to inflexible operating limits. As a result, prices may not reflect the marginal cost of serving load. In December 2015, ISO-NE fileda separate proceeding, PJM has submitted a proposal that wouldat FERC’s request to modify its rules to allow resource ownersmarket sellers to submit bids into the capacity auction reflectingday-ahead offers that vary by hour and to allow market sellers to update their desire to retire a resource. In April 2016,offers in real time on an hourly basis under certain circumstances. FERC has accepted thePJM’s proposal subject to a compliance filing by ISO-NE.which will become effective on November 1, 2017. We remain concernedbelieve that the new rules may be disruptive to efficientboth changes will improve price formation in the capacity market.
Reactive Power Rates
December 31, 2015 Form 10-K page 19. In June 2015, Power submitted a tariff filing with FERC to increase Power’s rates for reactive supplyenergy and voltage control service from approximately $27 million per year to about $39 million per year. Following settlement discussions with FERC Trial Staff, Power agreed to accept an overall rate of $34 million per year, which FERC approved in February 2016. FERC had earlier referred the filing to the FERC Office of Enforcement for its evaluation, which remains pending.
Long-Term Capacity Agreement Pilot Program Act (LCAPP)
December 31, 2015 Form 10-K page 21. In 2011, the State of New Jersey enacted the LCAPP to subsidize approximately 2,000 MW of new natural gas-fired generation. The LCAPP provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey EDCs.
In 2013, the U.S. District Court in New Jersey found that the LCAPP was unconstitutional and declared the LCAPP null and void. This federal court decision was subsequently challenged on appeal in the U.S. Third Circuit Court of Appeals (Third Circuit). The State of Maryland also took similar action to subsidize above-market new generation. This action was also determined to be unconstitutional in 2013 in the U.S. District Court in Maryland and such decision was challenged in the U.S. Fourth Circuit Court of Appeals (Fourth Circuit). Both appeals were denied. These denials were challenged on appeal to the U.S. Supreme Court. On April 19, 2016, the U.S. Supreme Court issued its ruling upholding the Fourth Circuit decision. The Supreme Court’s ruling upholds FERC’s authority to foster competitive wholesale electricity markets and provides guidance to states in balancing their interests to encourage and support the development of renewables and other generating facilities. On April 25, 2016, the U.S. Supreme Court denied the request to hear the appeal of the Third Circuit decision.ancillary services markets.
Transmission Regulation—Transmission Policy Developments
December 31, 20152016 Form 10-K page 18. In August 2016, PJM announced that it had suspended the Artificial Island transmission project and would be performing a comprehensive analysis to support a future course of action. In March 2017, PJM staff made its final recommendation to the PJM Board with respect to the project. Under the recommended project, PSE&G will construct necessary upgrade work in Hope Creek, at a cost of approximately $130 million. In April 2017, the PJM Board announced that it would be lifting the suspension and approved the staff recommended project. The PJM Board also stated that it would be analyzing project beneficiaries from an alternate perspective to potentially devise an alternative cost allocation methodology for stability projects.
Transmission Regulation—Con Edison Wheeling Agreement
December 31, 2016 Form 10-K page 19. In April 2013,2016, Con Edison informed PJM initiatedthat it would allow its first "open window" solicitation processWheeling Agreement to allow both incumbentsexpire effective as of May 1, 2017. The Wheeling Agreement enables Con Edison to move 1,000 MW of power from southeastern New York across the PSE&G system for delivery into New York City. NYISO and non-incumbentsPJM submitted proposed tariff provisions in January 2017. The proposal concerns future operational procedures and transmission planning assumptions associated with the opportunityaffected transmission lines. FERC accepted the proposal, subject to submit transmission project proposals to address identified high voltage issues at Artificial Island in New Jersey. In April 2016, PSE&G accepted construction responsibility forrefund, effective May 1, 2017. We cannot predict the three componentsimpact of the project thatproposal on energy prices or transmission planning at this time. Both PSE&G and the BPU protested certain aspects of the proposal. In a related filing, PJM submitted a proposal to FERC revising the cost responsibility assigned to it, based on having reached agreement with PJM regarding an estimate forcertain entities, including PSE&G, due to the project base cost of $273 million, plus risk and contingency for a total project cost of up to $340 million. PSE&G continues to work with PJM to optimize the scope and costtermination of the project.
On April 1, 2016, PJM filed at FERCWheeling Agreement. Also, PSE&G will continue to incorporate a voltage threshold into PJM’s RTEP process to exempt, except under certain circumstances, reliability violations on facilities below 200 kV from PJM’s proposal window process.recover the costs associated with the new arrangement through its formula rate. We generally support this reform as a measure to improve the efficiency of the open window procedure that will permit transmission developers to focus on the projects most likely to benefit from a competitive process.
In June 2015, a transmission developer filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. According to the complaint, PJM and certain transmission owners wrongfully inflated the scope and associated costs of mitigation work needed to accommodate the developer’s proposal in order to prevent it from pursuing its projects. Although not named as a respondent in the complaint, PSE&G is identified as one of the companies claimed to have been involved. The developer subsequently amended its complaint to add additional claims. Motions are pending before FERC seeking to dismiss both the original and the amended complaint. We are unable tocannot predict the outcome of this proceeding.
State Regulation
Energy Efficiency Program (Energy Efficiency 2017)
In March 2017, we filed a petition with the BPU for our Energy Efficiency 2017 program, requesting extension of three Energy Efficiency Economic sub-programs (multi-family, direct install and hospital efficiency) and the addition of two new sub-programs (smart thermostat and residential data analytics). The petition requested additional capital expenditures of approximately $74 million, additional administrative and other costs of $22 million and information technology system enhancement costs of $3 million. We proposed to recover our investment in these proceedings.sub-programs under the same clause recovery process as currently approved. This matter is pending.
There are several matters pending before FERC that concern
Environmental Matters
Climate Change
CO2 Regulation under the allocation of costs associated with transmission projects being constructed by PSE&G contending that insufficient levels of costs are being allocated to PSE&G. Projects involved includeClean Air Act (CAA)
December 31, 2016 Form 10-K page 23. In March 2017, the Artificial Island project, the Bergen-Linden project in New Jersey and a smaller project in Sewaren, New Jersey. On April 22, 2016, FERC issued orders denying the complaints and leaving the current cost allocation in effect as to the Artificial Island and Bergen-Linden projects. Due to an intervening FERC order concerning the allocation of costs for projects constructed to meet local reliability requirements, FERC directed that allPresident of the Sewaren costs be allocatedUnited States issued an Executive Order that instructed the EPA to PSE&G. Itreview the New Source Performance Standards that establish emissions standards for CO2 for certain new fossil power plants and the Clean Power Plan, a greenhouse gas emissions regulation under the CAA for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. Upon completion of the review, the EPA is anticipated that additional proceedings are likelyexpected to occur.suspend, revise or rescind the rules as appropriate. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.
Water Pollution Control
Steam Electric Effluent Guidelines
December 31, 2016 Form 10-K page 23. In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-
Compliance—Reliability Standardsowned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.
In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and is acting promptly to issue an administrative stay of the compliance dates in the rule that have not yet passed pending judicial review. The deadlines that are expected to be stayed include the BAT limitations and pretreatment standards for each of the following waste streams: fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater. Power is unable to determine how this will ultimately impact compliance requirements or the financial impact it may have on the company.
Waters of the United States
December 31, 2015 Form 10-K page 21. FERC is considering whether to direct the North American Electric Reliability Council (NERC) to develop a new reliability standard to provide security controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to bulk electric system operations. If adopted, compliance with these new standards would be expected to impose additional obligations and costs on transmission providers.
State Regulation
BPU Cybersecurity Requirements for Regulated Entities
In March 2016 the BPU issued an Order for the regulated electric, natural gas, and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The Order requires these regulated utilities, including PSE&G, to implement a cybersecurity program that defines and implements organization accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems.
New Jersey utilities, including PSE&G, are required to be compliant with these requirements by October 31, 2017. We are currently evaluating the requirements. For a discussion of the risks associated with cyber threats, see Part I, Item 1A. Risk Factors—"Cyber security attacks or intrusions could adversely impact our businesses." in our 2015 Annual Report on
Form 10-K.
Environmental Matters
Air Pollution Control
Hazardous Air Pollutants Regulation
December 31, 2015 Form 10-K page 24. In February 2012, April 2014, theEnvironmental Protection Agency(EPA) EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sourcesa proposed rule to clarify the definition of waters of the United States under the National Emission Standard for Hazardous Air Pollutants (NESHAP)CWA programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. The final rule was published in June 2015 and various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the CAA. The MATS established allowable levels for mercuryfinal rule as well as which court has jurisdiction over the rule. The U.S. Supreme Court is expected to rule on the question of jurisdiction by June 2017. Some states, including New Jersey, are subject to state requirements beyond thoseimposed under federal law. While we do not anticipate material impacts to projects in New Jersey, the new definition could impose requirements in other hazardous air pollutantsstates and went into effect in April 2015. regions that could impact the development of renewables.
In February 2017, the President of the United States issued an Executive Order that instructed the EPA to review the rule and issue a proposal to redefine “Waters of the United States.”
Endangered Species Act
December 31, 2016 Form 10-K page 25. In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plantsSierra Club and remanded the matter backanother environmental group submitted to the D.C. Court. On December 15, 2015,NJDEP a sixty-day notice of intent to sue alleging the D.C. Court remandedagency has caused violations of the MATSEndangered Species Act by allowing our Mercer generation station to operate in a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a permit renewal action for Mercer which addresses the alleged Endangered Species Act violations. In March 2017, we submitted our Incidental Take Permit to the EPA without vacatingNational Marine Fisheries Service outlining operation and monitoring requirements through retirement of the rule. On April 15, 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to the U.S. Supreme Court's Mercer generation station on
June ruling. We do not expect this Supplemental Finding to impact operation of our facilities.1, 2017 and subsequent decommissioning.
A listing of exhibits being filed with this document is as follows:
|
| | |
| a. PSEG: | | |
| Exhibit 12: | | Computation of Ratios of Earnings to Fixed Charges |
| Exhibit 31: | | Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
| Exhibit 31.1: | | Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
| Exhibit 32: | | Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code |
| Exhibit 32.1: | | Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code |
| Exhibit 101.INS: | | XBRL Instance Document |
| Exhibit 101.SCH: | | XBRL Taxonomy Extension Schema |
| Exhibit 101.CAL: | | XBRL Taxonomy Extension Calculation Linkbase |
| Exhibit 101.LAB: | | XBRL Taxonomy Extension Labels Linkbase |
| Exhibit 101.PRE: | | XBRL Taxonomy Extension Presentation Linkbase |
| Exhibit 101.DEF: | | XBRL Taxonomy Extension Definition Document |
| | | |
| b. PSE&G: | | |
| Exhibit 12.1: | | Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements |
| Exhibit 31.2: | | Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
| Exhibit 31.3: | | Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
| Exhibit 32.2: | | Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code |
| Exhibit 32.3: | | Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code |
| Exhibit 101.INS: | | XBRL Instance Document |
| Exhibit 101.SCH: | | XBRL Taxonomy Extension Schema |
| Exhibit 101.CAL: | | XBRL Taxonomy Extension Calculation Linkbase |
| Exhibit 101.LAB: | | XBRL Taxonomy Extension Labels Linkbase |
| Exhibit 101.PRE: | | XBRL Taxonomy Extension Presentation Linkbase |
| Exhibit 101.DEF: | | XBRL Taxonomy Extension Definition Document |
| | | |
| c. Power: | | |
| Exhibit 12.2: | | Computation of Ratios of Earnings to Fixed Charges |
| Exhibit 31.4: | | Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
| Exhibit 31.5: | | Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
| Exhibit 32.4: | | Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code |
| Exhibit 32.5: | | Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code |
| Exhibit 101.INS: | | XBRL Instance Document |
| Exhibit 101.SCH: | | XBRL Taxonomy Extension Schema |
| Exhibit 101.CAL: | | XBRL Taxonomy Extension Calculation Linkbase |
| Exhibit 101.LAB: | | XBRL Taxonomy Extension Labels Linkbase |
| Exhibit 101.PRE: | | XBRL Taxonomy Extension Presentation Linkbase |
| Exhibit 101.DEF: | | XBRL Taxonomy Extension Definition Document |
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
| (Registrant) |
| | |
| By: | /S/ STUART J. BLACK |
| | Stuart J. Black Vice President and Controller (Principal Accounting Officer) |
Date: April 29, 201628, 2017
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
PUBLIC SERVICE ELECTRIC AND GAS COMPANY |
| (Registrant) |
| | |
| By: | /S/ STUART J. BLACK |
| | Stuart J. Black Vice President and Controller (Principal Accounting Officer) |
Date: April 29, 201628, 2017
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
PSEG POWER LLC |
| (Registrant) |
| | |
| By: | /S/ STUART J. BLACK |
| | Stuart J. Black Vice President and Controller (Principal Accounting Officer) |
Date: April 29, 201628, 2017