Allegheny Power 2014 Annual Report Download - page 33

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The following tables summarize the price and volume factors contributing to changes in revenues:
Source of Change in Revenues
Increase (Decrease)
MWH Sales Channel: Sales Volumes Prices
Gain on
Settled
Contracts Capacity Revenue Total
(In millions)
Direct $ (629) $ 75 $ — $ — $ (554)
Governmental Aggregation (73) 72 — — (1)
Mass Market 1 3 — — 4
POLR (3) 47 — — 44
Structured Sales 176 (75) — — 101
Wholesale (17) — (21) 156 118
The Direct, Governmental Aggregation and Mass Market customer base was 2.1 million as of December 31, 2014, compared to
2.7 million as of December 31, 2013, reflecting the segment's efforts to reposition its sales portfolio to more effectively hedge its
generation as discussed above. Additionally, although unit pricing was higher year over year in the Direct, Governmental Aggregation
and Mass Market channels noted above, the increase was primarily attributable to higher capacity expense as discussed below,
which is a component of the retail price. The increase associated with capacity was partially offset by lower energy pricing built into
the retail product at the time customers were acquired for 2014 sales. Beginning in the fourth quarter of 2011, when there was a
significant decline in energy prices, CES’ 2014 retail sales position was approximately 30% committed, whereas its 2013 retail sales
position was approximately 60% committed, resulting in a greater proportion of 2014 sales and unit prices being impacted by the
decline in the energy prices. Additionally, higher Direct unit prices were impacted by approximately $33 million of ancillary pass
through revenues associated with PJM expenses incurred in January 2014.
During January 2014, given higher customer usage associated with extreme weather conditions and unit unavailability, including
the Beaver Valley Unit 1 outage, CES (including FES) was required to purchase higher volumes of power. These extreme weather
events, which included the polar vortex, caused an increase in the demand for electricity and natural gas throughout the PJM
Region. Average prices during first quarter 2014 were nearly $68 per MWH, or double the three-year average of about $34 per
MWH. Furthermore, prices during the 10 highest-price, most volatile days in the first quarter where the average round-the-clock
day-ahead price at AD Hub was between $100 and $500 per MWH and more specifically on January 7, 2014, when real-time prices
exceeded $1,800 per MWH significantly impacted the results. Increased customer demand that was unhedged and replacement
power requirements due to the timing of unplanned outages and derates contributed to purchasing additional volumes at these
higher prices. Furthermore, in order to maintain system reliability, PJM incurred higher ancillary service costs, such as synchronous
and operating reserves, throughout these extreme conditions. Approximately $800 million in ancillary service charges for the month
of January 2014 were billed to all LSEs serving customers throughout the PJM Region based on load served, including FES. Certain
of these costs are considered a "pass-through" event under existing contracts and were billed to commercial and industrial customers
in 2014.
The increase in POLR revenues of $44 million was due to higher rates associated with the capacity expense component of the rate
discussed above, partially offset by lower sales volumes. The increase in Structured Sales revenues of $101 million was due to
higher sales volumes, partially offset by lower unit prices primarily due to market conditions related to extreme weather events in
January 2014 that reduced the gains on various structured financial sales contracts.
Wholesale revenues increased $118 million primarily due to an increase in capacity revenue from higher capacity prices, partially
offset by a decrease in short-term (net hourly positions) transactions. The decrease in Wholesale sales volumes was due to lower
generation available to sell primarily as a result of the Harrison/Pleasants asset transfer and the deactivation of certain power plants
in 2013. Capacity revenue is expected to increase in 2015 due to the results of the 2015/2016 PJM BRA, and decrease in the years
shortly thereafter. The following tables summarize the PJM BRA capacity clearing prices by planning year and BRA capacity revenue
by calendar year, excluding the impact, if any, of future incremental auctions or other future capacity transactions.
Planning Year - June 1 through May 31
$/MWD 2013 - 2014 2014 - 2015 2015 - 2016 2016 - 2017 2017 - 2018
RTO $28 $126 $136 $59 $120
MAAC $226 $136 $167 $119 $120
ATSI $28 $126 $357 $114 $120