VIA FEDEX OVERNIGHT Esq. Case 15-2002-E-P

Gary A. Jack Senior Corporate Counsel

VIA FEDEX OVERNIGHT

Jacqueline Roberts, Esq. Consumer Advocate Division 700 Union Building 723 Kanawha Boulevard, East Charleston, WV 25301

Telephone 304 534 7409 Fax 330 315 9939

March 28,2016

Re: Monongahela Power Company and The Potomac Edison Company IRP Case No. 15-2002-E-P

Dear Ms. Roberts:

Enclosed please find the responses of Monongahela Power Company and The Potomac Edison Company to the CAD’S First Data Request in the above-referenced matter.

Please note that the Confidential Exhibits are in a sealed envelope and should be treated as such according to the Protective Agreement.

Sincerely,

Gary A. Jack Senior Corporate Counsel WV State Bar No. 1855

GAJ : dml

Enclosure

cc: Certificate of Service Ingrid Ferrell, Executive Secretary (via FedEx wlenc.)

CONSUMER ADVOCATE DIVISION’S FIRST REQUEST FOR INFORMATION MONONGAHELA POWER COMPANY and THE POTOMAC EDISON COMPANY

CASE NO. 15-2002-E-IRP

MON POWEWPE

QUESTION NO. 1

Please provide the following charts/graphs in color: Figures 3 through 6 and Figures 16 through 18.

RESPONSE:

Please see attached.

1

Mon Power/PE 2015 Integrated Resource Plan

Figure 3-Mon Power’s Supercritical Units Capacity Factor

Supercritical Utilization 100%

70% E 60% 3 50% ‘t E 40%

5 30%

20% 10%

0%

Y

+FTMl + FTM2

H A M

+ HAR2

b H A R 3

2 006 83% 83% 82% 87% 72%

=-- T L

2007 2ma 2009 2010 2011 2012 2013 2014 67% 75% 41% 68% 71% 76% 81% 64% 75% 65% 44% 63% 76% 38% 83% 78% 82% 76% 51% 78% 64% 52% 79% 76% 71% 78% 61% 69% 69% 55% 63% 75% 87% 75% 62% 72% 59% 65% 77% 71%

3.2 Hydro Generation

The Bath County Pumped Storage Station (“Bath County”), which went into operation in 1985, is located in Virginia and is jointly owned by Dominion and the former operating companies of the Allegheny Power System, and is managed by Dominion Generation. Bath County has 6 generating units and has an ICAP (PJM) generating capacity of 3,003 MW. Mon Power owns 16.25% (488 MW) of Bath County. Since Bath County is a pumped storage hydro unit, SOX and NOx controls are unnecessary.

3.3 PURPA Generation

The Public Utility Regulatory Policies Act of 1978 (“PURPA”) was implemented to encourage, among other things:

1. The conservation of electric energy; 2. Increased efficiency in the use of facilities and resources by electric

utilities; 3. Equitable retail rates for electric consumers;

!3sEkqY Mon Power/PE 2015 Integrated Resource Plan

4.2 Load and Demand Forecast Trends

4.2.1 Historical Load Forecast and Actual Loads

Figure 4 below shows historical information including the past forecast, actual load, actual weather normalized loads, and Mon Power load during the PJM peak. The graph shows that Mon Power’s actual load peaks occur during the winter months. It also indicates that actual load peaks in the previous two winter peaks exceeded the forecast by 134 MWs in 2014 and 130 MWs in 2015.

Figure 4 - Mon Power’s Historical Loads

, - HISTORIC LOADS xnn

3030

2500

I 2030 3 ’ 1500

1030

5m

0

3 !

J I CALENDAR YEARS

16

mE!EqY Mon Power/PE 201.5 Intemated Resource Plan

4.2.2 Forecast Loads

Figure 5 below shows load forecast for winter and summer peak demand using normalized weather, with the summer peak demand generally consistent with PJM’s peak demand.

Figure 5 -PEAK FORECAST

3500

3400

3300

3200

$ 3100

3WO

2800

2700

FORECASTED LOADS - CALENDAR YEARS

I Forecasted Summei Pezk (MW] I Foretasted Winter Peak (Ivl\N]

5.0 PLANNING OBJECTIVES

The primary purpose of the Plan is to evaluate the Companies’ capacity and energy needs and to evaluate the potential alternatives to meet those needs. The Plan incorporates a number of constraints, including requirements from PJM, and assumptions related to capacity needs, energy outlook, reserve requirements, market pressures, economic conditions, and regulatory drivers. These constraints and assumptions are discussed in greater detail below.

17

FHstE- Mon Power/PE 2015 Integrated Resource Plan

Figure 6 - Mon Power Capacity Position

z 6100

3300 3700 3500 3300

3 100 7410

2700 2 son

I 3

1

Mon Power's decreasing ability to meet its hourly capacity and energy obligations through its physical assets would, absent acquisition of additional resources, increases Mon Power's customer's exposure to market volatility risk and fluctuating rates.

Mon Power is and will continue to be committed to providing the resources that best match the needs of its customers in a cost effective and reliable manner.

The Plan recognizes that additional capacity resources will be needed in 2016, with the shortfall exceeding 700 MW by 2020.

5.3.1 Changes to PJM Reliability Pricing Model

PJM made a FERC filing with proposed changes to their capacity market that would create a Capacity Performance product. FERC has approved the filing with minor modifications. The changes to the capacity market are designed to provide greater assurance of delivery of energy and reserves during emergency conditions by providing higher capacity revenues and more stringent non- performance charges. PJM proposed these changes after resource performance fell far below expected levels during the winter of 2014. The past RPM

19

Mon Power/PE 2015 Integrated Resource Plan

Figure 16 - Levelized Cost for Power Generation Technologies

7.1 New Baseload Generation Plants

The most common intermediate and base load duty generation options are coal, nuclear and natural gas combined cycle.

The cost of constructing a new nuclear plant is the highest among the three alternatives. This high cost is due to the large capital outlay required to build such a plant and long permittingkonstruction timelines. Additionally, no new nuclear plants may be built in West Virginia under W. Va. Code $16-27A-2 until a national depository that permanently stores used radioactive material is established and successfully operated for two years.

The levelized cost shown for constructing a new coal plant assumes that the plant would he a supercritical pulverized coal unit without CCS technology. However, if the EPA’s rules setting GHG emissions for new fossil generation are promulgated and enforced, it will limit emissions to roughly 50% of a typical uncontrolled plant. To date, no CCS technology has been proven to effectively capture carbon or to effectively sequester COz on a large plant scale.

Natural gas combined cycle has the lowest levelized cost ofthe new build options, primarily because of its lower construction costs of approximately $I ,000/kW.

FBSm!zp Mon Power/PE 201 5 Intenrated Resource Plan

Natural gas has the additional advantage of the shortest build time (approximately 4 years) and least amount of expected opposition in terms of permitting approval. Recent low natural gas commodity prices also add to the appeal of this option.

A key driver to the cost of a natural gas combined cycle unit is fuel commodity price. Fuel cost directly affects the dispatch cost of the unit but also affects the utilization of the plant (capacity factor). A sensitivity analysis of fuel price and capacity factor is shown in Figure 17 below. Note that the base case input is a levelized Henry hub price of %3.36/mmBtu (Current 2015 forwards value) and a capacity factor of 67%.

Figure 17 - Levelized Cost for Combined Cycle Henry Hub Gas Priee

Levelired Cost Sensitivities - Combined Cycle

+50% Capauty Fadw + 75% Capaffly Fadu - 90% Capacity Fad0

120

110

100

90

80 70

110 - 100 - 90 80 70

- -

60 -

50 .

40 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00

40 .L-----l 50

$2.00 $3.00 $4.00 $5.00 $6.00 $7.00 2015 Henty Hub Gas Price, 5Immbtu

Inherent in any new construction solution is the risk of uncertain construction costs that could occur due to unforeseen obstacles, cost overruns, and siting and permitting risks and delays.

54

!-E&@ Mon Power/PE 201 5 Integrated Resource Plan

Figure IS - Levelized Cost for Coal Sensitivities

Levelized Cost Sensitivities -Existing Super Critical Pulverized Coal

50% Capscity FBdW - 90% Capacity Fada

+75% Capacity Fadw

2015 Delivered Coal Price, SlmmBtu

1.4 Demand Side Resources

Because of the significant nature of Mon Power’s capacity shortfall, demand side resource options will not meet Mon Power’s obligations. DR programs rely on finding eligible customers and then getting them to participate and pledge capacity for numerous years based on the customers own economics and not based upon Mon Power’s reliability requirements. Programs to reduce demand cannot consistently and reliably fulfill the long term need for supply side resources on this scale.

Mon Power does offer interruptible service for large retail customers of 5,000 kVa or greater. However, there has been little customer interest in these programs. Similarly, evolving market-based PJM programs cannot meet planning requirements. For both Company and PJM options, risk of customer non- performance is high due to customers’ economic decisions relative to participation on a given day or for a given year.

56



QUESTION NO. 2

Have the Companies issued an RFP for the purchase or acquisition on the 850 MW of capacity referred to on page 5? If so, please provide a copy of the RFP and any responses thereto.

RESPONSE:

An RFP has not been issued.

2

CONSUMER ADVOCATE DIVISION'S FIRST REQUEST FOR INFORMATION MONONGAHELA POWER COMPANY and THE POTOMAC EDISON COMPANY


QUESTION NO. 3

If the Company has not issued an RFP, please describe the Companies' current timeline for the issuance of an RFP in compliance with the Stipulation and Order in Case No. 12-1571-E-PC.

RESPONSE:

The conditions of the Stipulation and Order in Case No. 12-1571-E-PC have not yet been met. The order requires an RFP to be prepared and submitted to the Commission and the Parties for their review and comment once the Companies determine in any annual PJM Base Residual Auction ("BRA") that their combined capacity obligations for the delivery year covered by the BRA ("Delivery Year') exceed the Companies' owned or contracted-for capacity resources for the Delivery Year by 100 MW or more. The most recent BRA conducted for the 2018/2019 delivery year resulted in an estimated capacity obligation of 3,067 MW with capacity resources of 3,355 MW. Because this did not result in a deficiency of at least IOOMW, the condition has not been met. The companies will continue to monitor the results in subsequent BRAS to determine when this condition is met.

3



QUESTION NO. 4

Please explain how the Actual Summer Peaks for 2012 and 2013 in the table on page 16 can be lower than the values for MP Peak at PJM Peak.

RESPONSE:

The 2010-2015 data previously provided in Figure 4 - Mon Power’s Historical Loads (IRP, page 16), has been corrected below to provide retail peak data for the combined West Virginia territory, which includes Monongahela Power, Potomac Edison-West Virginia, and Monongahela Power’s West Virginia Power (which is located in the AEP zone).

As can be seen in the revised table below, FirstEnergy’s West Virginia territory is winter- peaking. PJM peaks occur during the summer period. The West Virginia peaks coincident at the time of the PJM summer peak hours, which are now correctly shown in the chart and table below, were lower than the West Virginia peaks that were non- coincident with the PJM peak.

The actual and weather-normalized 2015 winter season peak data is not yet available, since the 2015 winter peak period Dec 1, 2015 thru Mar 31, 2016 is not yet complete. The 2014 winter peak data shown below is for the Dec 2014 thru Mar 31, 2015 period.

HISTORIC FORECAST AND ACTUAL LOADS

3W0

IOU0

5CU

0 2013 2c



Note: The Seasonal winter peak follows the seasonal summer peak. The summer season is June through September and the winter season is December through March of the following year. For example. the 2015 summer peak period is June 1, 2015 thru September 30, 2015, and the 2015 winter peak period is Dec 1,2015 thru Mar 31. 2016.

5



QUESTION NO. 5

With regards to the table on page 16, do the Companies calculate MP Peak @ PJM Peak on a weather-normalized basis? If so please provide the weather-normalized peaks for 2012 through 2015.

RESPONSE:

FirstEnergy does not calculate weather-normalized peaks coincident with the PJM peaks.

6



QUESTION NO. 6

Please provide the base case levelized coal price and capacity factor for the Companies' Existing Plant alternative.

RESPONSE:

Levelized coal price is $2.57/MMBtu. Capacity factor is 67%.

7



QUESTION NO. 7

Please provide the annual forecasted market prices of electricity used to derive the levelized price range of $72-$76/MWH in Figure 6.

RESPONSE:

See attached confidential file.

8



UCAP Obligation (Includes West Virginia

QUESTION NO. 8

Final Zonal Capacity Price ($/MW) Total West Virginia

Please provide all purchases and sales into the PJM capacity market commencing with the delivery years 2013 through the most current. When the BRA results for 2018-2019 are available, please provide that information as well.

Delivery Period June 1,2012 -May 31, 2013 June 1,2013 - May 31, 2014 June 1, 2014 -May 31, 2015 June 1, 2015 - February 2016

RESPONSE:

- Power Load)- APS Zone i AEP-Zone Expense

2,851 $ 16.74 $ 17,425,629 2,812 $ 28.45 $ 29,199,456

137,363,118 2,931 $ 128.38 $ 3,015 $ 135.81 $ 112,184,456

The table below represents the PJM capacity market purchases for West Virginia. For the 2015-2016 delivery year actual expenses are shown through February 29,2016, the most current expense period available.

Please see "Q8 Confidential Generation PJM Market results.xlsx" for sales results.

9

Re: Monongahela Power Company and The Potomac Edison Company Case No. 15-2002-E-P

CERTIFICATE OF SERVICE

I hereby certify that on this 28" day of March, 2016, a copy of the foregoing was sent

by US . Mail, First Class, to:

John R. Auville, Staff Attorney Public Service Commission of West Virginia

PO Box 812 Charleston, WV 25323

VIA FEDEX OVERNIGHT Esq. Case 15-2002-E-P

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