1

We have the energy

to make things better for you, for our investors and for our stakeholders.

2

Forward-Looking Statements Certain of the matters discussed in this presentation about our and our subsidiaries future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on managements beliefs as well as assumptions made by and information currently available to management. When used herein, the words anticipate, intend, estimate, believe, expect, plan, should, hypothetical, potential, forecast, project, variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in filings we make with the United States Securities and Exchange Commission (SEC) including our Annual Report on Form 10-K and subsequent reports on Form 10-Q and Form 8-K. These factors include, but are not limited to: fluctuations in wholesale power and natural gas markets, including the potential impacts on the economic viability of our generation units; our ability to obtain adequate fuel supply; any inability to manage our energy obligations with available supply; increases in competition in wholesale energy and capacity markets; changes in technology related to energy generation, distribution and consumption and customer usage patterns; economic downturns; third party credit risk relating to our sale of generation output and purchase of fuel; adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in funding requirements; changes in state and federal legislation and regulations; the impact of pending rate case proceedings; regulatory, financial, environmental, health and safety risks associated with our ownership and operation of nuclear facilities; adverse changes in energy industry laws, policies and regulations, including market structures and transmission planning; changes in federal and state environmental regulations and enforcement; delays in receipt of, or an inability to receive, necessary licenses and permits; adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry; changes in tax laws and regulations; the impact of our holding company structure on our ability to meet our corporate funding needs, service debt and pay dividends; lack of growth or slower growth in the number of customers or changes in customer demand; any inability of Power to meet its commitments under forward sale obligations; reliance on transmission facilities that we do not own or control and the impact on our ability to maintain adequate transmission capacity; any inability to successfully develop or construct generation, transmission and distribution projects; any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers; our inability to exercise control over the operations of generation facilities in which we do not maintain a controlling interest; any inability to recover the carrying amount of our long-lived assets and leveraged leases; any inability to maintain sufficient liquidity; any inability to realize anticipated tax benefits or retain tax credits; challenges associated with recruitment and/or retention of key executives and a qualified workforce; the impact of our covenants in our debt instruments on our operations; and the impact of acts of terrorism, cybersecurity attacks or intrusions. All of the forward-looking statements made in this presentation 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, results of 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 presentation apply only as of the date of this presentation. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even in light of new information or future events, unless otherwise required by applicable securities laws. The forward-looking statements contained in this presentation 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.

3

GAAP Disclaimer PSEG presents Operating Earnings and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) in addition to its Net Income reported in accordance with accounting principles generally accepted in the United States (GAAP). Operating Earnings and Adjusted EBITDA are non-GAAP financial measures that differ from Net Income. Non-GAAP Operating Earnings exclude the impact of returns (losses) associated with the Nuclear Decommissioning Trust (NDT), Mark-to-Market (MTM) accounting and material one-time items. Non-GAAP Adjusted EBITDA excludes the same items as our non-GAAP Operating Earnings measure as well as income tax expense, interest expense and depreciation and amortization. The last three slides in this presentation (Slides A, B and C) include a list of items excluded from Net Income/(Loss) to reconcile to non-GAAP Operating Earnings and non-GAAP Adjusted EBITDA with a reference to those slides included on each of the slides where the non-GAAP information appears.

Management uses non-GAAP Operating Earnings in its internal analysis, and in communications with investors and analysts, as a consistent measure for comparing PSEGs financial performance to previous financial results. Management believes non-GAAP Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating operating performance because it provides them with an additional tool to compare business performance across companies and across periods. Management also believes that non-GAAP Adjusted EBITDA is widely used by investors to measure operating performance without regard to items such as income tax expense, interest expense and depreciation and amortization, which can vary substantially from company to company depending upon, among other things, the book value of assets, capital structure and whether assets were constructed or acquired. Non-GAAP Adjusted EBITDA also allows investors and other users to assess the underlying financial performance of our fleet before managements decision to deploy capital. The presentation of non-GAAP Operating Earnings and non-GAAP Adjusted EBITDA is intended to complement, and should not be considered an alternative to, the presentation of Net Income, which is an indicator of financial performance determined in accordance with GAAP. In addition, non-GAAP Operating Earnings and non-GAAP Adjusted EBITDA as presented in this release may not be comparable to similarly titled measures used by other companies. Due to the forward looking nature of non-GAAP Operating Earnings and non-GAAP Adjusted EBITDA guidance, PSEG is unable to reconcile these non-GAAP financial measures to the most directly comparable GAAP financial measure. Management is unable to project certain reconciling items, in particular MTM and NDT gains (losses), for future periods due to market volatility. Guidance included herein is as of February 23, 2018. These materials and other financial releases can be found on the PSEG website at www.pseg.com, under the Investors tab. From time to time, PSEG, PSE&G and PSEG Power release important information via postings on their corporate website at http://investor.pseg.com. Investors and other interested parties are encouraged to visit the corporate website to review new postings. The email alerts link at http://investor.pseg.com may be used to enroll to receive automatic email alerts and/or really simple syndication (RSS) feeds regarding new postings at http://investor.pseg.com/rss

http://www.pseg.com/http://investor.pseg.com/http://investor.pseg.com/http://investor.pseg.com/rss

PSEG STRATEGY:

GROWING A HIGH-QUALITY, FINANCIALLY SOUND ENERGY INFRASTRUCTURE COMPANY

E X E C U T I V E V I C E P R E S I D E N T A N D C H I E F F I N A N C I A L O F F I C E R

Dan Cregg

V I C E P R E S I D E N T I N V E S T O R R E L A T I O N S

Kathleen Lally

Ralph Izzo C H A I R M A N , P R E S I D E N T A N D C H I E F E X E C U T I V E O F F I C E R

5

Operational Excellence: Improving reliability and customer service as we control costs in a low price environment Financial Strength: Strong financial position supports investment program Disciplined Investment: Program focused on achieving objectives

through infrastructure investment that meets customer and shareholder needs

Robust pipeline of opportunities Results: Double digit growth in rate base

and net income at PSE&G Reconfiguration of Powers generating

fleet: higher quality, more efficient Annual growth in common dividend Strong credit metrics

DISCIPLINED INVESTMENT

OPERATIONAL EXCELLENCE

FINANCIAL STRENGTH

ENGAGED WORKFORCE

PSEG Strategy - Delivering Value

6

Two strong businesses A stable platform, each with growth opportunities

Strategy: Investment program enhances competitive position with addition of efficient, clean, reliable CCGT capacity Value Proposition: Provides substantial free cash flow and upside from market rule improvements

Assets $12B Net Income $479M Non-GAAP Operating Earnings* $505M

Regional Competitive Generation

Strategy: Investments aligned with public policy and customer needs

Value Proposition: A $11.5 - $13.2 billion infrastructure program with opportunities to expand, producing 7% - 9% annual rate base growth through 2022

Assets $29B Net Income $973M Non-GAAP Operating Earnings* $963M

Electric & Gas Delivery and Transmission

2017 2017

ASSETS AND NET INCOME ARE FOR THE YEAR ENDED 12/31/2017. PSE&G AND POWER DO NOT ADD TO TOTAL DUE TO ENTERPRISE / OTHER ACTIVITY. *SEE SLIDE A FOR A RECONCILIATION OF NET INCOME TO NON-GAAP OPERATING EARNINGS, SLIDE B FOR RECONCILIATIONS FOR PSE&G AND PSEG POWER, AND SLIDE C FOR ENTERPRISE/OTHER.

7

Delivering on commitments and realizing growth

Operational Excellence

PSE&G: 16 consecutive years of recognition as the most reliable utility in the Mid-Atlantic region

PSEG Power: Improved nuclear capacity factors to ~94% in 2017; Fleet moving towards improved efficiency and environmental position

PSEG Long Island: Improved customer service and reliability while managing costs PSEG: Maintaining focus on efficiency, resiliency and customer satisfaction

Financial Strength

Non-GAAP Operating Earnings for 2017 exceeded the mid-point of guidance range Cash flows and business mix support strong credit ratings and ability to fully fund

robust investment pipeline without issuing new equity PSEG is a net beneficiary of recent tax legislation Increased dividend in February 2018 14th increase in last 15 years

Disciplined Investment

PSE&G capital program drives continued rate base growth over the 5-year period (2018-2022) with investments in Transmission, Electric and Gas distribution, Gas System Modernization Programs (GSMP), Energy Strong and Clean Energy

Power capital program, focused on completing construction at Keys, Sewaren and Bridgeport Harbor, will improve fleet efficiency and geographic diversity

8

$1.42 $1.44 $1.48 $1.56

$1.64 $1.72

0.0

1.0

2.0

2012 2013 2014 2015 2016 2017

$/sh

are

Focus on earning our cost of capital has provided for growth in operating earnings* and dividends

Non-GAAP Operating Earnings*

$2.44 $2.58

$2.76 $2.91 $2.90 $2.93

0.0

1.0

2.0

3.0

2012 2013 2014 2015 2016 2017

$ EP

S

2012-2017 CAGR ~4%

*SEE SLIDE A FOR ITEMS EXCLUDED FROM NET INCOME TO RECONCILE TO NON-GAAP OPERATING EARNINGS.

Dividends

2012-2017 CAGR ~4%

9

PSEG Policy and Regulatory focus on mechanisms that provide customers with clean, affordable, resilient energy supply

NJ Distribution Base Rate Proceeding Requested ~1% increase in revenue primarily to recover investments, partially offset by

benefits related to tax reform Long-Term Infrastructure Investment Platform BPU approved policy providing for constructive investment recovery mechanism

encouraging investment in long-term infrastructure

Preserve the Value of Nuclear Supply Pursuing legislative strategy that recognizes the value of nuclear energy under terms

and conditions that are affordable for customers and provide the proper incentives for long-term operation

Ensure Federal Regulatory and Policy Framework Advocate for rules that preserve benefits of competitive markets while also recognizing

the value of clean energy, supply diversity and grid reliability

PUBLIC SERVICE ELECTRIC & GAS

11

Electric Gas

Customers Growth (2013 2017)

2.2 Million 0.6%

1.8 Million 0.6%

2017 Electric and Gas Sales 40,740 GWh 2,397M Therms*

Sales Mix (2017)

Residential 32% 59%

Commercial 58% 37%

Industrial 10% 4%

* GAS FIRM SALES ONLY.

PSE&G New Jerseys largest: Electric and Gas Distribution utility Transmission business Investor in renewables and energy efficiency Appliance service provider

46% 51%

3%

PSE&G 2017 Rate Base

$17.0B

Distribution Transmission Clean Energy

12

PSE&G Investment Delivering growth

-

100

200

300

400

500

600

700

800

900

1,000

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

2013 2014 2015 2016 2017

Distribution Transmission Clean Energy Non-GAAP Operating Earnings

$ Millions $ Millions

Rate

Bas

e Non-GAAP

Operating Earnings

Our rate base is roughly balanced between federal and state jurisdictions Non-GAAP operating earnings growth aligned with rate base growth

5 year CAGR Rate Base = 13% Operating Earnings = 13%

13

~23%

~44%

~33%

2018-2022E PSE&G Capital with Program extensions by Recovery Method

$11.5B - $13.2B

Traditional Recovery Mechanisms Distribution Base Rates

FERC Formula Rates Transmission

Developing investment opportunities with near-contemporaneous recovery mechanisms

Clause Recovery Mechanisms Infrastructure / Clean Energy

E = E S T I M A T E . D A T A A S O F F E B R U A R Y 2 0 1 8 . I N C L U D E S A F U D C .

$13B plan includes program extension filings comparable to current investment levels:

GSMP II Energy Strong (ES) II Clean Energy Future (CEF) filing

expansion of current energy efficiency programs

electric vehicle programs energy storage LED streetlights

Broad opportunity set of investment potential driven by customer expectations and public policy

14

-

200

400

600

800

1,000

1,200

2012 2013 2014 2015 2016 2017

Distribution Transmission

Cost control actions: PSE&G is utilizing the Lean Six Sigma discipline to achieve costs savings

and process improvements Regular organizational refinement to streamline processes Continued focus on vendors, ensuring maximum value Successful management of pension

$Mill

ions

5-year CAGR = 0.1% PSE&G O&M Expense

Operational Excellence O&M costs

Demonstrated ability to control O&M, preserving earnings and returns in a low sales growth environment

15

0

5,000

10,000

15,000

20,000

25,000

30,000

2017 2018E 2019E 2020E 2021E 2022E

Transmission Distribution Clean Energy

Year-end Rate Base

Continued strong rate base growth -- off a higher base $ Millions

E = ESTIMATE. HASHED PORTION OF THE CHART REPRESENTS EXTENSIONS OF DISTRIBUTION CLAUSE PROGRAMS INCLUDING GSMP II, ES II AND A LARGE CLEAN ENERGY PROGRAM

~$13B capital plan + ~$1B of tax reform impacts =Sustained Rate Base growth of 7% - 9%

16

PSE&G Investment Evolution: System needs, customer expectations and public policy objectives drive need for continued and increasing Distribution investments

2013 - 2017 Infrastructure Clauses focused on hardening

and resiliency Solar 4 All and Solar

loans Energy Efficiency

2018-2022E Complete hardening,

begin system modernization, expand

efficiency program Transition from Energy Strong to Life cycle and

automation work Accelerate GSMP

Solar landfills Extend and broaden

Energy Efficiency EV Infrastructure and

Battery storage

Utility of the Future

Electric Infrastructure Life cycle programs,

distribution automation, EV Charging

Gas Infrastructure GSMP Acceleration and

Resiliency CNG Charging

Distributed energy resources Solar 4 All, Microgrids,

Batteries, Fuel Cells

Energy Efficiency Hospitals, Municipalities, Universities, Low Income

Programs, EE for All (Residential, Small C&I), AMI,

Bill Education

Utility of the Future represents potential investment opportunity to sustain annual rate base growth into the next decade

PSEG POWER

18

Power has generating assets in three competitive markets

ISO New England

New Haven

Bethlehem Energy Center (Albany)

Conemaugh

Keystone

Peach Bottom

Bergen Kearny Essex

Sewaren (incl. Sewaren 7, under construction)

Linden + Linden VFT

Burlington

Hope Creek Salem

Yards Creek

New York ISO

PJM

Keys Energy Center (under construction)

Bridgeport (incl. Bridgeport Harbor 5, under construction)

Major assets located near key load centers

Constructing three new, highly efficient combined-cycle units

Positioned to benefit from market volatility

Additional generation assets: Solar (414 MWDC /325 MWAC) Kalaeloa, HI (104 MW)

19

27%

62%

10%

20

53%

31%

10%

4% 2%

46%

47%

6%

21

Powers fleet is well-located with access to shale gas production

PSEG Power procured approximately 360 BCF in 2017 with approximately 50% going towards PSE&Gs utility gas customer usage

PSEG Powers gas for PJM generation was ~65 BCF in 2017, of which >85% was supplied by Northeast Shale gas

PSEGs Total PJM Gas Procurement

0%

50%

100%

2010 2011 2012 2013 2014 2015 2016 2017

Shale Non-Shale

Pipeline Takeaway Capacity Growth 2016-2020E

Significant amount of new pipelines have already been built and more are in construction / development

Gas production and pipeline takeaway capacity expected to be more balanced in 2018 timeframe

New England 0.9 bcf/d

Southeast 6.3 bcf/d

Midwest 6.0 bcf/d

Gulf Coast 6.0 bcf/d

NJ/NY 1.9 bcf/d

Total Expected Capacity Growth of

21.1 BCF

E = ESTIMATE.

Chart1

01

0.090.91

0.280.72

0.620.38

0.780.22

0.860.14

0.920.08

0.940.06

Shale

Non-Shale

Sheet1

ShaleNon-Shale

20100%100%

20119%91%

201228%72%

201362%38%

201478%22%

201586%14%

201692%8%

201794%6%

ShaleNon Shale

201060%40%

201160%40%

201260%40%

201360%40%

201460%40%

Sheet1

Shale

Non-Shale

Sheet2

Sheet3

22

$Mill

ions

2012 to 2017 CAGR: (1.1%)

Power O&M Expense*

*EXCLUDES IMPACTS FROM STORM RECOVERY COSTS AND THE HUDSON/MERCER EARLY RETIREMENT.

Power has demonstrated its ability to control O&M

$0

$500

$1,000

$1,500

2012 2013 2014 2015 2016 2017

Chart1

1048

1155

1148

1182

1070

989.2

O&M(w/o Sandy)

Sheet1

O&M(w/o Sandy)TotalO&MPension

20081,047.01,054.01,043.510.5

20091,030.01,045.0979.665.4

20101,030.01,046.0993.552.5

20111,091.011021073.128.9

20121,048.01,056.01,004.151.9

20131,155.0

20141,148.0

20151,182.0

20161,070.0

2017989.2

To resize chart data range, drag lower right corner of range.

2008200920102011201220132014201520162017CAGR 10 - 16CAGR 12-17

1,047.01,030.01,030.01,091.01,048.01,155.01,148.01,182.01,070.0989.20.6%-1.1%

1,054.00.6%- 0

1,060.70.6%1,030.02.4%

1,067.50.6%1,054.72.4%

1,074.30.6%1,080.02.4%

1,081.10.6%1,106.02.4%

23

Powers capital needs decline following construction of new capacity, enhancing free cash flow

EXCLUDES NUCLEAR FUEL. INCLUDES IDC. E=ESTIMATE. DATA AS OF MARCH 9, 2018. *UPDATED TO REFLECT RECENT CANCELLATION OF NUCLEAR CAPITAL PROJECTS AT SALEM THAT ARE NOT REQUIRED FOR REGULATORY COMPLIANCE OR SAFE OPERATION.

Power Capital Investment*

PSEG FINANCIAL REVIEW & OUTLOOK

25

Strong financial position driven by PSE&G with meaningful contribution from Power

2017 Financial Position

Earnings Delivered on 2017 guidance under challenging conditions

Increased PSE&G earnings contribution

Investment Executed major PSE&G capital program balanced between

Transmission and Distribution

Focused on completion of Powers construction program

Cash Flow and Credit Metrics

PSEG business mix yields net benefits from recent tax reform

Produced stable and strong PSE&G cash from operations

Maintained strong credit metrics

Dividends Increased common dividend by 4.7% or $0.08 per share

26

Power 33%

PSE&G 65%

2018E Non-GAAP Operating Earnings Guidance

Contribution*

2018-2022E Total Capital**

~$13.2B

~$1.5B

8% annual growth in rate base with

expansion/extension of existing programs

Completion of capital program for new combined cycle

plants

*BASED ON THE MID-POINT OF NON-GAAP OPERATING EARININGS GUIDANCE OF $3.00 TO $3.20 PER SHARE. **INCLUDES ALL PLANNED SPENDING. E = ESTIMATE. INCLUDES AFUDC AND IDC.

Investment programs provide opportunity for growth

Enterprise/ Other

2%

27 1 ) I N C L U D E S I S S U A N C E S , R E D E M P T I O N S , C A S H P O S I T I O N A N D T R E A S U R Y S H A R E S 2 ) A D J U S T E D T O S H I F T C U M U L A T I V E E N E R G Y E F F I C I E N C Y C A P I T A L S P E N D F R O M C A S H F R O M

O P E R A T I O N S ( P E R G A A P ) T O G R O W T H I N V E S T M E N T . E = E S T I M A T E .

PSEG Consolidated 2018E 2022E Sources and Uses of Cash

Cash Impact from Tax Reform is Manageable

Sources Uses

Net Debt(1) Shareholder Dividend

Cash from

Operations(2) (Excluding Tax

Reform Impact)

Cash from

Investment(2)

Tax Reform PSE&G Uses

Meaningfully Offset by Power Sources

28

Total Incremental Investment Capacity (PSEG and Power)

Power PSEG

Estimate (Including Tax

Reform) Low - Forties ~20%

Tax Reform Impact ~5% ~(2%)

Minimum Threshold 30% High - Teens

Average Funds From Operations / Debt 2018E 2020E

Excess Investment Capacity of nearly $1B after tax reform and continued investment

E=ESTIMATE.

$0.0

$1.0

$2.0

Excluding TaxReform

Power/OtherTax Reform

PSE&G TaxReform

Including TaxReform

($ Billions)

Incremental capacity invested in PSE&G would be matched with utility debt

29

Tax reform and growth in utility infrastructure investment drives increase in earnings

PSEG 2018 non-GAAP Earnings Guidance +6% over 2017

Non-GAAP Operating Earnings* Contribution by Subsidiary 2017 Actual and 2018 Guidance

* SEE SLIDES A, B AND C FOR ITEMS EXCLUDED FROM NET INCOME (LOSS) TO RECONCILE TO OPERATING EARNINGS (NON-GAAP). ** BASED ON THE MID-POINT OF 2018 NON-GAAP OPERATING EARNINGS GUIDANCE OF $3.00 - $3.20 PER SHARE. E = ESTIMATE.

2017 2018E**

$2.93

$3.00 - $3.20E

PSE&G represents approximately two-thirds of 2018 Operating Earnings Guidance

30

2018 Operating Earnings Guidance -- PSE&G expected to contribute two-thirds of operating earnings

*SEE SLIDES A ,B AND C FOR ITEMS EXCLUDED FROM NET INCOME/(LOSS) TO RECONCILE TO NON-GAAP OPERATING EARNINGS FOR PSEG, PSE&G, PSEG POWER AND ENTERPRISE/OTHER. **BASED ON THE MID-POINT OF 2018 NON-GAAP OPERATING EARNINGS GUIDANCE OF $3.00 - $3.20 PER SHARE. E= ESTIMATE. GUIDANCE INCLUDED HEREIN IS AS OF FEBRUARY 23, 2018.

PSEG Non-GAAP Operating Earnings

$ Millions (except EPS) 2018E Guidance

PSE&G $1,000 - $1,030

PSEG Power $485 - $560

Enterprise/Other $35 - $35

Operating Earnings* $1,520 - $1,625

Operating EPS* $3.00 - $3.20E

Non-GAAP Operating Earnings* Contribution by Subsidiary

31

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

$2.00

$2.20

2013 2014 2015 2016 2017 2018E

$1.80

PSE&G EPS

($/S

hare

)

Annual Dividend Per Share (2013-2018E CAGR: 4.6%)

Opportunity for consistent and sustainable dividend growth

$1.44 $1.48

$1.56 $1.64

$1.72

PSE&G 2018

Operating Earnings Guidance

Range

E=ESTIMATE.

32

PSEGs Value Proposition A stable platform with a $13-$15 billion infrastructure investment

pipeline providing opportunity for growth

PSE&G Delivering on promise for rate base growth through disciplined investment, customer satisfaction and safety

PSEG Power Efficient, low-cost, clean fleet advantaged by asset diversity, fuel mix and location

Focus on providing strong, sustainable returns of invested capital through operational excellence, regulatory and legislative mechanisms

111-year record of paying common dividend with opportunity for

consistent, sustainable growth

Strong balance sheet Financial strength supported by stable credit rating and investment profile

PSEG APPENDIX

34

PSE&G Distribution Base Rate Case Filing Dockets ER 18010029 (Electric) and GR 18010030 (Gas) Filed January 12, 2018; Anticipate new rates Fourth Quarter 2018 Test year July 1, 2017 through June 30, 2018 (with certain pro forma adjustments) Rate base of $9.6B ($5.6B E; $4B G) as of December 31, 2018 ROE request of 10.3%; Capitalization structure with 54% equity Requested Increase: ~1% relative to overall revenue O&M and Sales are roughly flat to last rate case eight years ago Capital recovery beyond clauses and $125M increase in Depreciation rate Decoupling of revenues from sales volumes Taxes lower tax rate and flow back of deferred taxes to offset storm costs and

reduce impact on customer bills Pending updates:

Taxes - BPU order to lower rates effective April 1 will accelerate savings planned in rate case; update for other tax impacts such as loss of bonus depreciation

9x3 update to be filed in May Overall bill for the typical PSE&G residential customer, even after consideration

of the ~1% request, would remain ~20% lower than bills after last base rate case

35 *FOR ALL YEARS THE BILLING ASSUMES 7,200 KWH FOR ELECTRIC AND 1,010 THERMS FOR GAS ANNUALLY. E = ESTIMATE ** COMPARED AGAINST 12 REGIONAL UTILITIES AS OF SEPTEMBER 1, 2016, FOR A CUSTOMER THAT USES 500 KILOWATT-HOURS AND 100 THERMS IN A MONTH.

$0

$500

$1,000

$1,500

$2,000

2010 2018E 2010 2018E

Electric Gas

Distribution Clauses Supply CPI

$1,346$1,253

$1,330

$903

(7%)

(32%)

Regional price comparison** - Gas is 2nd lowest and Electric is lower than average Distribution revenue component is the lowest in the state for Gas and second lowest for Electric

Combined electric and gas bills declined ~20% since our last rate case

Provided Gas bill credits totaling ~$670 per customer since 2012

Continued investment at the current rate of growth would take about a decade to equal the 2010 bill rates (adjusted for growth in CPI/disposable income)

Customers bills are materially lower, supporting needed investment in the system

PSE&G Typical Residential Customer Bills*

Chart1

2682488301346

2961278301516

3391658271330

403984011499

$1,346

$1,253

$1,330

$903

Distribution

Clauses

Supply

CPI

AllCharts

Rick Charts for RI - Theme = Investing in Infrastucture while containing Customer Bills

ElectricGas

Brian Davis Chart for RL

AllCharts

2987.051153.121650.1147.8171.8818.122008200846.01

3000.26344780351160.321567.4747.8174.5617.962009200946.81

3051.43230272031162.661356.2347.8186.8418.642010201054.63

3138.26353114321133.541156.7947.8171.636.642011201160.99

3199.96007074331090.131089.2735.8676.436.762012201276.09

3245.88614573381096.111064.0523.8986.5627.8420132013112.8

3301.82070468911075.311061.53084.4424.6820142014152.13

3353.60791121931089.51919.91084.8424.6800173.81

3415.16634138161078.31861.0200-1.1200199.49

3477.93580960081077.11846.6500020.81.72228.87

3546.63504414031072.67845.0900028.316.64254.91

3616.43626756761072.35844.8700028.337.42285.97

CPI

Customer Bill - Electric

Customer Bill - Gas

Transitional Energy Facility Assessment

Securitization

Non-Utility Generation

Energy Strong

CIP III

Transmission

RI Slide Info

Total Gas & Electric Typical Customer Bills with Eliminating Items

Item2008200920102011201220132014201520162017E

Electric$1,199.13$1,207.13$1,217.29$1,194.53$1,166.22$1,208.91$1,227.44$1,260.92$1,284.92$1,252.12

Gas$1,650.11$1,567.47$1,356.23$1,156.79$1,089.27$1,064.05$1,061.53$919.91$874.15$861.02

E TEFA$22.27$22.27$22.27$22.27$16.70$11.13$0.00$0.00$0.00$0.00

G TEFA$25.54$25.54$25.54$25.54$19.16$12.76$0.00$0.00$0.00$0.00

Tot TEFA$47.81$47.81$47.81$47.81$35.86$23.89$0.00$0.00$0.00$0.00

Securitization$71.88$74.56$86.84$71.60$76.40$86.56$84.44$80.08($11.92)$0.00

NUG$18.12$17.96$18.64$36.64$36.76$27.84$24.68$24.28$13.16($1.12)

EEE Ext II (Elec)$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00

EEE Ext II (Gas)$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00

Tot EEE EXT II$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00

NOTE: For all years the 2012 billing determinants (7,200 kWh for electric and 1,010 therms for gas annually) have been utilized.

NOTE2: 2008 rates are as of December 31. 2009 - 2016 electric rates for each year are as of June 1.2016. 2017E electric rates include Energy Strong rates to be effective March 1 and BGS Auction rates to be effective June 1. 2009 - 2017E gas rates are as of January 1. 2017.ElectricGas

20102018E20102018E

Total E$1,311.40$1,321.92$1,345.04$1,325.04$1,296.08$1,334.44$1,336.56$1,365.28$1,286.16$1,251.00Distribution$268$296$339$403

Total G$1,675.65$1,593.01$1,381.77$1,182.33$1,108.43$1,076.81$1,061.53$919.91$874.15$861.02Clauses$248$127$165$98

Total E&G Combined$2,987.05$2,914.93$2,726.81$2,507.37$2,404.51$2,411.25$2,398.09$2,285.19$2,160.31$2,112.02Supply$830$830$827$401

CPI$1,346$1,516$1,330$1,499

Typical Residential Electric Annual Bills by Component1

Year22008200920102011201220132014201520162017E

Distribution3$286.16$288.04$295.76$303.88$303.64$300.24$287.32$292.92$297.04$304.08

Clauses4$141.04$144.12$161.20$175.60$188.92$208.68$195.48$185.68$70.36$64.40

Supply$884.20$889.76$888.08$845.56$803.52$825.52$853.76$886.68$918.76$882.52

Total Annual Bill$1,311.40$1,321.92$1,345.04$1,325.04$1,296.08$1,334.44$1,336.56$1,365.28$1,286.16$1,251.00

1Typical Residential Electric customer using 750 kWh per summer month and 7,200 annually

22008 represents rates as of December 31, 2008. .All rates for each subsequent year are as of June 1. 2017 electric rates include Energy Strong to be effective March 1, and BGS Auction rates to be effective June 1.

3Distribution Charges include Service and Distribution Charges

4Clauses include the Societal Benefits Charge, Non-utility Generation Charge, Securitization Transition Charge, System Control Charge, Solar Pilot Recover Charge, and Green Programs Recovery Charge

Typical Residential Gas Annual Bills by Component1

Year22008200920102011201220132014201520162017E

Distribution3$420.69$420.69$429.67$443.63$442.61$470.51$446.49$401.31$415.57$465.54

Clauses4$57.46$57.82$55.30$64.88$58.98$56.88$65.62$62.22$53.38$52.70

Supply5$1,197.50$1,114.50$896.80$673.82$606.84$549.42$549.42$456.38$405.20$342.78

Total Annual Bill$1,675.65$1,593.01$1,381.77$1,182.33$1,108.43$1,076.81$1,061.53$919.91$874.15$861.02

1Typical Residential electric customer using 165 therms per winter month and 1,010 annually

22008 represents rates as of December 31, 2008. All other subsequent years are rates as of January 1.

3Distribution Charges include Service, Distribution, Balancing Charges, Margin Adjustment Charge, and Weather Normalization Charge

4Clauses include Societal Benefits Charge and Green Programs Recovery Charge

5Supply Charges do not include bill credits of approximatley $581 from 2012 to current.

Distribution3

Clauses4

Supply

2008

2008

2008

2009

2009

2009

2010

2010

2010

2011

2011

2011

2012

2012

2012

2013

2013

2013

2014

2014

2014

2015

2015

2015

2016

2016

2016

2017E

2017E

2017E

286.16

141.04

884.2

288.04

144.12

889.76

295.76

161.2

888.08

303.88

175.6

845.56

303.64

188.92

803.52

300.24

208.68

825.52

287.32

195.48

853.76

292.92

185.68

886.68

297.04

70.36

918.76

304.08

64.4

882.52

Distribution3

Clauses4

Supply5

2008

2008

2008

2009

2009

2009

2010

2010

2010

2011

2011

2011

2012

2012

2012

2013

2013

2013

2014

2014

2014

2015

2015

2015

2016

2016

2016

2017E

2017E

2017E

420.69

57.46

1197.5

420.69

57.82

1114.5

429.67

55.3

896.8

443.63

64.88

673.82

442.61

58.98

606.84

470.51

56.88

549.42

446.49

65.62

549.42

401.31

62.22

456.38

415.57

53.38

405.2

465.54

52.7

342.78

RI Slide Info

Distribution

Clauses

Supply

CPI

Summary - BD INFO

Item2008200920102011201220132014201520162017201820192020

Customer Bill - Electric$1,153.12$1,160.32$1,162.66$1,133.54$1,090.13$1,096.11$1,075.31$1,089.51$1,078.31$1,077.11$1,072.67$1,072.35$1,070.39

Customer Bill - Gas$1,650.11$1,567.47$1,356.23$1,156.79$1,089.27$1,064.05$1,061.53$919.91$861.02$846.65$845.09$844.87$843.61

Transitional Energy Facility Assessment$47.81$47.81$47.81$47.81$35.86$23.89$0.00$0.00$0.00$0.00$0.00$0.00$0.00

Securitization$71.88$74.56$86.84$71.60$76.40$86.56$84.44$84.84$0.00$0.00$0.00$0.00$0.00

Non-Utility Generation$18.12$17.96$18.64$36.64$36.76$27.84$24.68$24.68($1.12)$0.00$0.00$0.00$0.00

Energy Strong$0.00$0.00$20.80$28.30$28.30$28.30

CIP III$0.00$0.00$1.72$16.64$37.42$59.14

Transmission$46.01$46.81$54.63$60.99$76.09$112.80$152.13$173.81$199.49$228.87$254.91$285.97

CPI$2,987.05$3,000.26$3,051.43$3,138.26$3,199.96$3,245.89$3,301.82$3,353.61$3,415.17$3,477.94$3,546.64$3,616.44$0.00

Total E$1,311.40$1,321.92$1,345.04$1,325.04$1,296.08$1,334.44$1,336.56$1,372.84$1,276.68$1,313.90$1,341.58$1,372.32$1,084.39

Total G$1,675.65$1,593.01$1,381.77$1,182.33$1,108.43$1,076.81$1,061.53$919.91$861.02$861.25$876.03$896.59$917.05

E&G Combined$2,987.05$2,914.93$2,726.81$2,507.37$2,404.51$2,411.25$2,398.09$2,292.75$2,137.70$2,175.15$2,217.61$2,268.91$2,001.44

TEFA - E$22.27$22.27$22.27$22.27$16.70$11.13$0.00

TEFA - G$25.54$25.54$25.54$25.54$19.16$12.76$0.00

ES - E$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$7.92$14.00$14.00$14.00

ES - G$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$0.00$12.88$14.30$14.30$14.30

Historic Electric Total Bill$1,199.13$1,207.13$1,217.29$1,194.53$1,166.22$1,208.91$1,227.44$1,372.84

Notes:

2008 bill based on actuals as of December 1

2009-2015 hitoric bills based on rates in effect June 1 for Electric; Jan 1 for Gas

2016-19 forecasted bill based on adjusting the 6-1-15 bill for the components listed below; all other components (such as BGSxTrans, BGSS and SBC) were assumed constant

2019 Typical Bill does not include any estimated impact from the 2017 rate case filing; therefore, issues that will be resolved in the next rate case such as storm cost amortization are not included in the chart above

2016-20 Forecasted Changes to 2015 Bill - Electric

STCAssumes STC rate goes to zero by 1-1-16$0.00$0.00$0.00$0.00$0.00

NGCAssumes the NGC goes to zero by 6-1-16 as the last NUG contract expires at the end of April 2016;$0.00$1.12$1.12$1.12$1.12

GPRCBased on latest forecast sent to the BPU with actual results through September 2014$0.00$0.00-$4.64-$5.32-$6.72

SPRCBased on latest forecast sent to the BPU with actual results through September 2014$0.00-$1.60-$2.00-$2.00-$2.04

ESBased on revenue requirements in the Plan. Makes the simplifying assumption that the revenues were derived from rates effective on January 1$0.00$7.92$14.00$14.00$14.00

TransmissionBased on forecast from R. Marinelli using the "Current" Allocation Methodology; Peak Load and RS Obs/kWh assumed the same as in 2015$0.00$25.68$55.06$81.10$112.16

EEEXIIBased on settlement bill impacts submitted with the Stipulation on 2-20-15; initial impact added to the 2015 current bill$0.00$0.00$0.40$1.00$1.36$0.84

2016-20 Forecasted Changes to 2015 Bill - Gas

WNCAssumed to be 0 in 2016 forward$0.00-$14.89-$14.89-$14.89-$14.89

GPRCBased on latest forecast sent to the BPU with actual results through September 2014$0.00-$0.10-$2.46-$3.20-$3.66

ESBased on revenue requirements in the Plan. Makes the simplifying assumption that the revenues were derived from rates effective on January 1$0.00$12.88$14.30$14.30$14.30

EEEXIIBased on settlement bill impacts submitted with the Stipulation on 2-20-15; initial impact added to the 2015 current bill$0.00$0.00$0.62$1.42$1.94$1.14

CIP IIIBased on revenue requirement file as of 2-20-15; Makes the simplifying assumption that the revenues were derived from rates effective on Jun 1$0.00$1.72$16.64$37.42$59.14

RS

Typical Residential Customer based on 2012 Billing Determinants

SeasonkWh MonthMonths / SeasonTotal

Summer75043,000

Winter52584,200

Total127,200

CURRENT BILL

Rates Effective 6/1/2017 (Includes rates as of 2/1 AND 3/1 ES, & BGS Auction Results effective 6/1 )Distribution per kWh

SummerWinterSummerWinterTotal

SvcOverOverSTC-TotalOverOverTotalDelivery

Chg0-6006000-600600SBCNGCSTC-TBCMTC TaxSPRCGPRCDelivery0-6006000-600600Supply& Supply

Current Rate2.430.0409340.0450180.0356360.0356360.007881-0.000155000.0000730.0011480.1218030.1315490.1217350.121735

Annual Units122,4006004,20007,2007,2007,2007,2007,2007,2002,4006004,2000

Annual Bill$29.16$98.24$27.00$149.68$0.00$56.76-$1.12$0.00$0.00$0.52$8.24$368.48$292.32$78.92$511.28$0.00$882.52$1,251.00

Distribution$304.08

Clauses$64.40

Supply$882.52

Total$1,251.00

CHANGES TO CURRENT BILL20162017201820192020Notes

Energy Strong$0.00$7.92$14.00$14.00$14.00Revenue requirements from approved roll-ins through 3/1/2016 and plan for remaining roll-ins; rate design based on 2012 billing determinants.

SBC$0.00$0.00$0.00$0.00No change has been forecasted

NGC*$1.12$1.12$1.12$1.12Contracts expire in April 2016; all that remains is St. Lawrence credit

STC$0.00$0.00$0.00$0.00Expires at the end of 2015

SPRC-$1.60-$2.00-$2.00-$2.04Latest forecast used for Cumulative Rate Impact in the EEE Ext II filing

GPRC$0.00-$4.64-$5.32-$6.72Latest forecast used for Cumulative Rate Impact in the EEE Ext II filing; assumes EEE Ext II approved as filed

EEEXII$0.00$0.40$1.00$1.36$0.84From Stipulation submitted 2-20-15

Transmission$25.68$55.06$81.10$112.16

FORECASTED BILL20162017201820192020

Electric$1,078.31$1,077.11$1,072.67$1,072.35$1,070.39Assumes no rate case, including no impact from the amortization of storm prudenct costs and forecasted STC overcollection refund

TEFA$0.00$0.00$0.00$0.00

STC$0.00$0.00$0.00$0.00$0.00Supply assumed unchanged except for changes in Transmission and RPS standards as described below

NGC-$1.12$0.00$0.00$0.00$0.00

ES$0.00$7.92$14.00$14.00$14.00

CIP III

Transmission$173.81$199.49$228.87$254.91$285.97

Total$1,251.00$1,284.52$1,315.54$1,341.26$1,370.36

Diff

%

St. Lawrence Credit*

Credit w/SUT (9/1/2014)-0.000044

Annual kWh7,200

Credit w/SUT (9/1/2014)-0.3168

McFadden, Michael:ES Electric Roll-in 3 reflected in the 2016 total current bill ($1,243.60)

Zarra, David J.:Represents ES roll-in 4 (9/1/2016) & ES roll-in 5 (3/1/2017)

Zarra, David J.:includes ES roll-in 6 (9/1/2017)

RSG

Typical Residential Customer based on 2012 Billing Determinants

SeasonThermsBalancing ThermsMonths / SeasonTotal ThermsTotal Balancing Therms

Summer2861680

Winter1651374660548

Shoulder9163218263k

Total121,010611

CURRENT BILL

Rates Effective 1/1/2015

Svc ChgDist ChgBal ChgWNCGPRCSBCMAC/RACTotal DeliveryBGSSTotal Delivery + Supply

Current Rate5.840.3289800.0902630.0243620.0049810.047232-0.0067740.339408

Annual Units121,0106116111,0101,0101,0101,010

Annual Bill$70.08$332.26$55.17$14.89$5.02$47.68-$6.86$518.24$342.78$861.02

Distribution$402.34

Clauses$60.73

Generation$397.95

Total$861.02

CHANGES TO CURRENT BILL20162017201820192020Notes

Energy Strong0$12.88$14.30$14.30$14.30Revenue requirement based on approved roll-in 1 and plan for roll-ins 2 & 3; rate design based on 2012 billing determinants.

WNC-$14.89-$14.89-$14.89-$14.89Assumed to be 0 as we cannot forecast the weather for 2018

MAC$0.00$0.00$0.00$0.00No change has been forecasted

SBC$0.00$0.00$0.00$0.00No change has been forecasted

GPRC-$0.10-$2.46-$3.20-$3.66Latest forecast used for Cumulative Rate Impact in the EEE Ext II filing

EEEXII$0.62$1.42$1.94$1.14From Stipulation submitted 2-20-15

CIP III$1.72$16.64$37.42$59.14

FORECASTED BILL

Gas$861.02$846.65$845.09$844.87$843.61

TEFA$0.00$0.00$0.00$0.00$0.00

STC

NGC

ES$0.00$12.88$14.30$14.30$14.301.3

CIP III$1.72$16.64$37.42$59.142/3 CP3.52.2

Transmission

Total$861.02$861.25$876.03$896.59$917.05

McFadden, Michael:Only for November

GPRC-SPRC2

Revenue Requirement

CA-EEEE-EEXT-EDRS4ASLIIS4AESLIIITotalkWh ForecastRate w/o SUTRate w/SUT

Current Rate0.0026650.002852

Proposed Rate in 2014 Filing0.0026720.002859

Jan-16Oct 15 - Sep 16$2,017,283$8,655,645$10,775,863$3,397,820$32,543,433$15,184,512$12,384,337$785,324$85,744,21841,470,1210.0020680.002213

Jan-17Oct 16 - Sep 17$2,017,730$2,431,493$12,675,486$3,060,299$30,596,979$14,904,714$13,478,228$3,005,656$82,170,58641,470,1210.0019810.00212

Jan-18Oct 17 - Sep 18$1,937,353$119,119$11,339,055$2,657,366$27,117,685$14,637,481$11,711,946$4,740,855$74,260,85941,470,1210.0017910.001916

Jan-19Oct 18 - Sep 19$1,765,229($555,544)$5,308,501$2,009,298$24,580,440$14,352,562$10,177,130$5,326,424$62,964,04041,470,1210.0015180.001624

Jan-20Oct 19 - Sep 20$986,634($867,613)$934,426$1,541,367$22,918,755$13,753,045$8,843,447$3,547,226$51,657,28841,470,1210.0012460.001333

Revenue Requirement

CA-GEEE-GEXT-GDRS4ASLIIS4AESLIIITotalkWh ForecastRate w/o SUTRate w/SUT

Current Rate0.0066990.007168

Proposed Rate in 2014 Filing0.0065780.007038

Jan-16Oct 15 - Sep 16$3,320,119$4,733,218$4,111,074$12,164,4112,770,8820.004390.004697

Jan-17Oct 16 - Sep 17$3,792,777$1,416,524$5,121,166$10,330,4682,770,8820.0037280.003989

Jan-18Oct 17 - Sep 18$3,926,210$66,521$5,100,965$9,093,6962,770,8820.0032820.003512

Jan-19Oct 18 - Sep 19$3,628,866($296,621)$2,536,479$5,868,7232,770,8820.0021180.002266

Jan-20Oct 19 - Sep 20$2,796,322($498,503)$581,786$2,879,6052,770,8820.0010390.001112

SPRCkWh ForecastRate w/o SUTRate w/SUT

Current Rate0.0004540.000486

Proposed Rate in 2014 Filing0.0002500.000268

Jan-16Oct 15 - Sep 16$8,128,44541,470,1210.0001960.00021

Jan-17Oct 16 - Sep 17$8,029,78941,470,1210.0001940.000208

Jan-18Oct 17 - Sep 18$7,858,87041,470,1210.000190.000203

Jan-19Oct 18 - Sep 19$7,638,72541,470,1210.0001840.000197

Jan-20Oct 19 - Sep 20$7,218,54841,470,1210.0001740.000186

Electric Rate w/SUT

GPRC0.0028520.0028590.0022130.002120.001916

SPRC0.0004860.0002680.000210.0002080.000203

RS Typical Bill

20152016201720182019

GPRC20.5620.5615.9215.2413.84

SPRC3.521.921.521.521.48

Gas

GPRC Rate0.0071680.0070380.0046970.0039890.003512

GPRC RS Typical Bill7.227.124.764.023.56

EEEXII

EEEXII Stipulation

Rates (w/o SUT)RS Typical Bill Increase

ElectricGasElectricGas

Jun-16Initial Period0.0000540.000536$0.40$0.62

Jun-17Oct 16 - Sep 170.0001370.001282$1.00$1.42

Jun-18Oct 17 - Sep 180.0001810.001785$1.36$1.94

Jun-19Oct 18 - Sep 190.0001140.001047$0.84$1.14

Jun-20Oct 19 - Sep 200.0001050.000758$0.80$0.84

20152016201720182019

Electric Typical Bill Increase from 2015$0.40$0.40$1.00$1.36$0.84

Gas Typical Bill Increase from 2015$0.62$0.62$1.42$1.94$1.14

Initial PeriodOct 16 - Sep 17Oct 17 - Sep 18Oct 18 - Sep 19Oct 19 - Sep 20

Revenue Requirements201520162017201820192020

Electric$0$4,787,529$5,515,562$3,588,945$2,001,630$2,818,606

Gas$0$1,849,653$3,045,806$2,302,007$1,273,072$924,974

kWh/Therms

Electric66,931,97041,805,04741,805,04741,805,04741,805,047

Gas3,839,3082,796,4462,796,4462,796,4462,796,446

Rates

Electric0.0000720.0001320.0000860.0000480.000067

Gas0.0004820.0010890.0008230.0004550.000331

RS Typical Bill

Electric$0.52$0.96$0.64$0.40$0.52

Gas$0.46$1.10$0.82$0.46$0.32

TransDetail

2015 Transmission Forecast - Current Allocation Methodology

(Millions of dollars)201420152016201720182019

ATRR from Davis file 2-10-20157369181,0441,1981,3341,495

Total Costs Borne by PSE&G Customers6057248359581,0671,197

RS Typical Bill Impact$152.13$173.81$199.49$228.87$254.91$285.97

RS Typical Bill Increase from 2014$21.68$47.36$76.74$102.78$133.84

Differnce in Costs Borne to PSE&G Customers - Current vs. Forcasted Methods - $M0-92-96-100-113

Total Elec RS Bill$1,372.84$1,291.40$1,324.46$1,357.26$1,386.36

Trans % of Total RS Bill12.7%15.4%17.3%18.8%20.6%

2015 Transmission Forecast - Forecasted Allocation Methodology

(Millions of dollars)201420152016201720182019

ATRR from Davis file 2-10-20157369181,0441,1981,3341,495

Total Costs Borne by PSE&G Customers6057249271,0541,1671,310

RS Typical Bill Impact$152.13$173.81$221.46$251.81$278.80$312.97

RS Typical Bill Increase from 2014$21.68$69.33$99.68$126.67$160.84

$21.97$22.94$23.89$27.00$0.00

% of Total RS Bill12.7%17.1%19.0%20.5%22.6%

2014 Transmission Forecast

(Millions of dollars)201420152016201720182019

ATRR from Davis file 2-10-20157368871,0161,1611,2981,452

Total Costs Borne by PSE&G Customers6058319381,0581,1721,279

RS Typical Bill Impact*$154.27$326.13

RS Typical Bill Increase from 2014**$171.86

* Typical bill impact in 2014 Transmission Forecast is different due to rounding and an update in the RS kWh forecast used to set the transmission rate/kWh

** Only looked at 2019 impact in 2014

Transmission

Transmission Impact to Typical Residential Customer

RetailForecast

200820092010201120122013201420152016201720182019Source

1Total Transmission Costs Borne by PSE&G Customers$192,355,042$205,561,580$246,095,234$307,048,033$442,724,207$576,466,387$691,643,662$835,000,000$958,000,000$1,067,000,000$1,197,000,000NITS Rate only through 2015; NITS+TEC from R. Marinelli for 2016-2019

2Network Service Peak Load (NSPL)10,654.009,686.7010,761.4010,933.3010,469.8010,414.409,515.209,515.209,515.209,515.209,515.20NSPL; assumed constant from 2015-2019

3$/MW/yr$17,631.00$18,054.73$21,221.01$22,868.33$28,083.75$42,285.83$55,352.82$72,688.29$87,754.33$100,681.02$112,136.37$125,798.72= ln 1 / ln 2 [Rnd 2]

4$/MW/mo$1,469.25$1,504.56$1,768.42$1,905.69$2,340.31$3,523.82$4,612.74$6,057.36$7,312.86$8,390.09$9,344.70$10,483.23= ln 3 / 12 [Rnd 2]

5NITS Rate per kW of Trans. Obl.$1.4693$1.5046$1.7684$1.9057$2.3403$3.5238$4.6127$6.0574$7.3129$8.3901$9.3447$10.4832= ln 4 / 1000 [Rnd 4]

6NITS Rate per kW of Trans. Obl. w SUT$1.5722$1.6099$1.8922$2.0391$2.5041$3.7705$4.9356$6.4814$7.8248$8.9774$9.9988$11.2170= ln 5 * 1.07 [Rnd 4]

Rate Schedule RS

7Trans Obl - MW4,404.04,406.04,286.84,265.24,409.44,284.74,430.43,579.23,579.23,579.23,579.23,579.2From BGS-FP Spreadsheets for Rates effective June 1 of that year

8Total Annual Energy - MWh13,246,99613,496,22413,307,20513,336,02213,416,60213,062,96713,022,43412,129,95012,129,95012,129,95012,129,95012,129,950From BGS-FP Spreadsheets for Rates effective June 1 of that year

NITS Energy Charge

9$/MWh$5.8615$5.8942$6.8362$7.3139$9.2298$13.8699$18.8317$21.4482$25.8938$29.7081$33.0882$37.1196= ln 3 * ln 7 / ln 8 [Rnd 4]

10$/kWh$0.005862$0.005894$0.006836$0.007314$0.009230$0.013870$0.018832$0.021448$0.025894$0.029708$0.033088$0.037120= ln 9 / 1000 [Rnd 6]

11TEC Adder $/kWh$0.000110$0.000182$0.000256$0.000603$0.000647$0.000771$0.000915$0.001113$0$0$0$0From D. Zarra for historic; in line 1 for forecast

12Total Transmission Rate $/kWh$0.005972$0.006076$0.007092$0.007917$0.009877$0.014641$0.019747$0.022561$0.025894$0.029708$0.033088$0.037120= ln 10 + ln 11

13Total Transmission Rate wSUT $/kWh$0.006390$0.006501$0.007588$0.008471$0.010568$0.015666$0.021129$0.024140$0.027707$0.031788$0.035404$0.039718= ln 12 * 1.07 [Rnd 6]

14Annual Avg kWhrs7,2007,2007,2007,2007,2007,2007,2007,2007,2007,2007,2007,2002012 AWN Typical Residential Annual usage

15Transmission NITS Annual Bill$46.01$46.81$54.63$60.99$76.09$112.80$152.13$173.81$199.49$228.87$254.91$285.97= ln 13 * ln 14 [Rnd 2]

Increase from 2008$0.80$8.62$14.98$30.08$66.79$106.12$127.80$153.48$182.86$208.90$239.96

&R&"Arial"&12&D &T

McFadden, Michael:Included in Total Transmission Cost Borne by Ratepayers provided by Rich

CIPIII

Typical Bill Impacts

Rate Schedule RSG

Year to Year impacts

If YourAnd YourThen YourAnd YourAnd Your

MonthlyAnnualPresentProposedYourPercentCumulativeCumulative

Winter ThermThermAnnual Bill (1)Annual Bill (2)IncreaseIncreaseAnnualPercent

Use is:Use Is:Would Be:Would Be:Would Be:Would Be:Impacts ($)Increase

2016Year 11651010919.91921.631.720.191.720.19

2017Year 21651010921.63936.5514.921.6216.641.81

2018Year 31651010936.55957.3320.782.2237.424.07

2019Year 41651010957.33979.0521.722.2759.146.43

2020Year 51651010979.051,001.3322.282.2881.428.85

2021Year 616510101,001.331,023.1121.782.18103.2011.22

Then YourAnd Your

If YourAnd YourPresentProposedAnd Your

AnnualMonthlyMonthlyMonthlyYourPercentCumulativeCumulative

ThermWinter ThermWinter Bill (1)Winter Bill (2)IncreaseIncreaseMonthlyPercent

Use Is:Use is:Would Be:Would Be:Would Be:Would Be:Impacts ($)Increase

2016Year 11010165146.99147.270.280.190.280.19

2017Year 21010165147.27149.702.431.652.711.84

2018Year 31010165149.70153.103.402.276.114.16

2019Year 41010165153.10156.643.542.319.656.57

2020Year 51010165156.64160.293.652.3313.309.05

2021Year 61010165160.29163.853.562.2216.8611.47

(1)This customer includes Delivery Rates and Basic Gas Supply Service (BGSS-RSG) and assumes they

receives BGSS-RSG service from Public Service. Year 1 are current rates effective 1/1/2015 and

all subsequent years are previous years proposed rates.

(2)Same as (1) except includes requested changes

CPI

CPI

NJ NY

2008235.7821$2,987.05

2009236.8251.001.0044235777$3,000.26

2010240.8641.021.0215538082$3,051.43

2011247.7181.051.0506230331$3,138.26

2012252.5881.071.0712777057$3,199.96

20131.41.08665281.0866527664$3,245.89

20141.71.10537845191.1053784519$3,301.82

20151.61.12271569311.1227156931$3,353.61

20161.81.14332412961.1433241296$3,415.17

20171.81.16433799551.1643379955$3,477.94

20182.01.18733701951.1873370195$3,546.64

20192.01.21070496561.2107049656$3,616.44

Chart -Brian Davis

1153.121650.1147.8171.8818.122008200846.012987.05

1160.321567.4747.8174.5617.962009200946.813000.2634478035

1162.661356.2347.8186.8418.642010201054.633051.4323027203

1133.541156.7947.8171.636.642011201160.993138.2635311432

1090.131089.2735.8676.436.762012201276.093199.9600707433

1096.111064.0523.8986.5627.8420132013112.83245.8861457338

1075.311061.53084.4424.6820142014152.133301.8207046891

1089.51919.91084.8424.6800173.813353.6079112193

1078.31861.0200-1.1200199.493415.1663413816

1077.11846.6500020.81.72228.873477.9358096008

1072.67845.0900028.316.64254.913546.6350441403

1072.35844.8700028.337.42285.973616.4362675676

1070.39843.6100028.359.1420200

Customer Bill - Electric

Customer Bill - Gas

Transitional Energy Facility Assessment

Securitization

Non-Utility Generation

Energy Strong

CIP III

Transmission

CPI

Sheet1

36

Full Requirements Component Capacity Markets/RPM Growing Renewable Energy/Transmission Component for Market Risk

New Jersey BGS accounts for ~10 TWh of our hedging Retail marketing will complement BGS

Latest auction results reflect mix of lower prices for energy and higher transmission costs

NOTE: BGS PRICES ARE QUOTED IN $/MWH AND REFLECT PSE&G ZONE; RESULTS FROM THE 2016-2018 AUCTIONS WILL BE THE NEW BLENDED PRICES BEGINNING JUNE 1, 2018.

Three-Year Average Round the Clock

PJM West Forward Energy Price

Capacity Load shape Transmission Congestion Ancillary services Risk premium Green

2014 2015 2016 2017 2018

$99.54

~ $59 ~ $62 ~ $63

$97.39

$38 -

$39 $32

- $33

~ $58

$96.38

$/M

Wh

$90.78

~ $61

$30 -

$31

$91.77

$37 -

$38

$33 -

$34

Chart1

38.559

37.562

33.563

32.558

3060

East

West

Sheet1

200520062007200820112012201320142015201620172018

East45.1470.557.8868.545.6837.539.538.537.533.532.530

West20.2732414348.6246535962635860

37

2020 Onward, RPM Auctions include 100% Capacity Performance and will be impacted by changes in: Net CONE Demand Response Rules PJM Parameters Environmental Retirements Load Forecasts

*PSEG POWERS AVERAGE PRICES AND CLEARED CAPACITY (MW) REFLECT BASE AND INCREMENTAL AUCTIONS. DELIVERY YEARS RUN FROM JUNE 1 TO MAY 31 OF THE NEXT CALENDAR YEAR.

PJMs RPM Auction Results*

Delivery Year 2016/2017 2017/2018 2018/2019 2019/2020 2020/2021

Powers Average Prices ($/MW-day) $172 $177 $215 $116 $174

Rest of Pool Prices ($/MW-day) $59 $120 $165/$150 (CP/Base) $100/$80 (CP/Base)

$77 (CP)

Powers Cleared Capacity (MW) 8,700 8,700 8,650 8,900 7,800

ISO New Englands Forward Capacity Market Auction Results

Delivery Year 2016/2017 2017/2018 2018/2019 2019/2020 2020/2021

Powers Average Prices ($/MW-day) $104 $232 $315 $231 $195

Powers Cleared Capacity (MW) 777 848 831 1,333 1,333

Capacity Markets provide a solid and continuing revenue stream

Bridgeport Harbor 5 cleared the 2019/2020 auction and receives $231/MW-day for seven years

38

PSEGs longer-term outlook is influenced by Powers hedge position and investment at PSE&G

2018E 2019E Each $0.75/mcf Change in Natural Gas Each $2/MWh Change in Spark Spread Each $5/MWh Change in Dark Spread Each 1% Change in Nuclear Capacity Factor

Segment EPS Drivers

Each $100 Million of Incremental Investment Each 1% Change in Sales Electric Gas Each 1% Change in O&M Each 20 basis point Change in Distribution ROE Each 20 basis point Change in Transmission ROE

$0.01

$0.01 $0.01 $0.01 $0.02 $0.02

$0.04 $0.08 $0.02 $0.01

$0.02 $0.04 $0.00 $0.01

$0.01

$0.01 $0.01 $0.01 $0.02 $0.02

Sensitivities derived from typical annual market variability

POWER EARNINGS SENSITIVITIES UPDATED FOR DECEMBER 31, 2017 PRICE CURVES AND EPS IMPACT ASSUMES NORMAL MARKET COMMODITY CORRELATION AND DEMAND. PSE&G DISTRIBUTION ROE SENSITIVITIES EXCLUDE ENERGY STRONG AND GSMP. E = ESTIMATE.

2020E

$0.13 $0.09 $0.03 $0.01

$0.01

$0.01 $0.01 $0.01 $0.02 $0.02

39

Tax Cuts and Jobs Act: PSEG is well positioned given positive non-utility contribution to earnings and a strong balance sheet

OUR ESTIMATES AND ANALYSIS ARE PRELIMINARY. THE SEC HAS PROVIDED COMPANIES ONE YEAR TO FINALIZE 2017 ACCOUNTING REQUIREMENTS. FURTHER ADJUSTMENTS IN 2018 MAY BE REQUIRED.

Federal Tax Reform PSE&G PSEG Power Enterprise/Other

Reduction of Corporate Tax Rate to 21%

Customer rates lowered with reduction in tax rate Return of excess deferred tax liability impact on cash and rate base growth dependent on payback period Estimated excess deferred tax balance of $2.1 Billion at YE 2017

After-tax earnings and cash flow increase One-time, non-cash earnings benefit from reduction in deferred tax liability reflected in 2017 GAAP results: $588 Million

After-tax earnings and cash flow increase One-time, non-cash earnings benefit from reduction in deferred tax liability reflected in 2017 GAAP results: $147 Million

Expensing of Capital Expenditures

Bonus depreciation eliminated post 2017 Rate base growth increases by ~1%/year through 2022 relative to prior tax rules

100% expensing -- cash flow increases

Interest Disallowance Rule 30% Limitation Based on Tax EBITDA

Not applicable

Well positioned given low debt balance

Well positioned given low debt balance

40

Tax reform impacts PSE&G Lowered federal corporate tax rate from 35% to 21%

Lowers costs and annual revenue requirements by ~$275M Updated Transmission Formula rate lowered by $148M effective 1/1/2018 Incorporated ~$130M reduction into Distribution base rate case filing

Lower tax depreciation benefits (no bonus depreciation, lower tax rate)

Excess deferred taxes due to lower tax rate of ~$2.1B Protected ~$1.6B Flow back period over the lives of the assets (ARAM method) Unprotected ~$0.5B Flow back period will be addressed with the BPU and FERC

Financial impact Rate base growth - Lower deductions and planned flow back increases rate base by >$1B

Average annual earnings increase by ~$20M in 2019 growing to ~$30M in 2022

Investment program and metrics to support strong credit rating is maintained

PSEG EXECUTIVE PROFILES

42

CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

Ralph Izzo

Ralph Izzo was elected chairman and chief executive officer of Public Service Enterprise Group Incorporated (PSEG) in April 2007. He was named as the companys president and chief operating officer and a member of the board of directors of PSEG in October 2006. Previously, Mr. Izzo was president and chief operating officer of Public Service Electric and Gas Company (PSE&G).

Since joining PSE&G in 1992, Mr. Izzo was elected to several executive positions within PSEGs family of companies, including PSE&G senior vice president utility operations; PSE&G vice president appliance service; PSEG vice president - corporate planning; and PSE&G vice president - electric ventures. In these capacities he broadened his experience in the areas of general management, strategic planning and finance.

Mr. Izzo is a well-known leader within the utility industry, as well as the public policy arena. He is frequently asked to testify before Congress and speak to organizations on matters pertaining to national energy policy.

Mr. Izzos career began as a research scientist at the Princeton Plasma Physics Laboratory, performing numerical simulations of fusion energy experiments. He has published or presented over 35 papers on magnetohydrodynamic modeling. Mr. Izzo received his

Bachelor of Science and Master of Science degrees in mechanical engineering and his Doctor of Philosophy degree in applied physics from Columbia University.

He also received a Master of Business Administration degree, with a concentration in finance from the Rutgers Graduate School of Management. He is listed in numerous editions of Whos Who and has been the recipient of national fellowships and awards. Mr. Izzo has received honorary degrees from the New Jersey Institute of Technology (Doctor of Science), Thomas Edison State University (Doctor of Humane Letters), Bloomfield College (Doctor of Humane Letters), Rutgers University (Doctor of Humane Letters), and Raritan Valley Community College (Associate of Science).

Mr. Izzo is on the board of directors for the New Jersey Chamber of Commerce, the Edison Electric Institute (EEI), the Nuclear Energy Institute (NEI) and the New Jersey Performing Arts Center. He is also a member of the Board of Trustees of Peddie School and the Princeton University Andlinger Center for Energy and the Environment Advisory Council, as well as a member of the Visiting Committee for the Department of Nuclear Engineering at MIT. Mr. Izzo is a former member of the Columbia University School of Engineering Board of Visitors. In addition, he is a former chair of the Rutgers University Board of Governors and the New Jersey Chamber of Commerce.

43

EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED, PUBLIC SERVICE ELECTRIC AND GAS COMPANY, PSEG POWER LLC AND PSEG SERVICES CORPORATION

Daniel Cregg

Daniel J. Cregg was named executive vice president and chief financial officer for Public Service Enterprise Group Incorporated (PSEG) and its subsidiaries in October 2015.

Mr. Cregg is responsible for all financial functions, including Internal Audit Services, Investor Relations and Corporate Development. Given the array of financial instruments which serve as the primary means of selling wholesale energy to customers, Mr. Cregg also has responsibility for the Risk Management function, which provides independent oversight of the PSEG Power trading organization. In addition to finance, Mr. Cregg is responsible for the Strategy and Planning function. He is a member of PSEGs Executive Officer Group.

Prior to his current position, Mr. Cregg was vice president finance for PSE&G, a role he assumed in June 2013. In 2006, Mr. Cregg was named vice president finance for PSEG Power. In that capacity and in previous financial roles for Power, Mr. Cregg held leadership positions related to financial reporting and forecasting, investor communications, financings, rating agency interactions,

external reporting, cash forecasting, financial valuations, competitive intelligence, and fundamental market modeling, with critical responsibilities in Powers development and strategic planning activities.

Previously, Mr. Cregg was director of PSEG corporate development. He joined PSEG in 1991 with overall responsibility for tax planning, strategy and compliance for PSEG Energy Holdings, including domestic and international tax structuring work for PSEG Global and PSEG Resources.

Before joining PSEG, Mr. Cregg spent five years with the accounting and consulting firm of Deloitte and Touche, providing consulting services to a wide range of clients with an emphasis on the energy industry.

Mr. Cregg holds a Master of Business Administration degree from the Wharton School of the University of Pennsylvania and is a graduate of Lehigh University, where he received a bachelors degree in accounting.

44

Reconciliation of Non-GAAP Operating Earnings

PLEASE SEE PAGE 3 FOR AN EXPLANATION OF PSEGS USE OF OPERATING EARNINGS AS A NON-GAAP FINANCIAL MEASURE AND HOW IT DIFFERS FROM NET INCOME. A

45 PLEASE SEE PAGE 3 FOR AN EXPLANATION OF PSEGS USE OF OPERATING EARNINGS AS A NON-GAAP FINANCIAL MEASURE AND HOW IT DIFFERS FROM NET INCOME/(LOSS). B

Reconciliation of Non-GAAP Operating Earnings for PSE&G and PSEG Power

46 PLEASE SEE PAGE 3 FOR AN EXPLANATION OF PSEGS USE OF OPERATING EARNINGS AS A NON-GAAP FINANCIAL MEASURE AND HOW IT DIFFERS FROM NET INCOME/(LOSS). C

Reconciliation of Non-GAAP Operating Earnings for PSEG Enterprise/Other

PSEG Investor SummaryForward-Looking StatementsGAAP DisclaimerPSEG STRATEGY: Growing A high-quality,Financially Sound energy infrastructure companyPSEG Strategy - Delivering ValueTwo strong businesses A stable platform, each with growth opportunitiesDelivering on commitments and realizing growthFocus on earning our cost of capital has provided for growth in operating earnings* and dividendsPSEG Policy and Regulatory focus on mechanisms that provide customers withclean, affordable, resilient energy supplyPublic ServiceElectric & GasSlide Number 11PSE&G Investment Delivering growthDeveloping investment opportunities with near-contemporaneous recovery mechanismsOperational Excellence O&M costsContinued strong rate base growth -- off a higher basePSE&G Investment Evolution: System needs, customer expectations and public policy objectives drive need for continued and increasing Distribution investments PSEG PowerPower has generating assets in three competitive marketsPower has a diverse fleet of generating assets which enables it to respond to market needsSlide Number 20Powers fleet is well-located with access to shale gas productionPower has demonstrated its ability to control O&MSlide Number 23PSEGFINANCIALREVIEW & OUTLOOKStrong financial position driven by PSE&G with meaningful contribution from PowerInvestment programs provide opportunityfor growthCash Impact from Tax Reform is ManageableExcess Investment Capacity of nearly $1B after taxreform and continued investment PSEG 2018 non-GAAP Earnings Guidance +6%over 2017 Slide Number 30Slide Number 31PSEGs Value PropositionPSEGAPPENDIXPSE&G Distribution Base Rate Case FilingCustomers bills are materially lower, supporting needed investment in the systemSlide Number 36Slide Number 37PSEGs longer-term outlook is influenced by Powers hedge position and investment at PSE&GSlide Number 39Tax reform impacts PSE&GPSEG EXECUTIVE PROFILESSlide Number 42Slide Number 43Reconciliation of Non-GAAP Operating Earnings Slide Number 45Slide Number 46