Transcript New Wave Energy Corp.

Market Report- The Polar Vortex & Its Aftermath
March 31, 2014
What makes up your Energy Bill?
 Generally your Energy
Bill is composed of 3
basic components:
 Energy rate (cost of fuel,
fixed or variable)
 Capacity
 Ancillary Services
Energy
Rate
Capacity
Ancillary
Services
Energy Rate
 The Energy Rate is the cost per
kWh or mWh for the “juice”
itself and is paid for by a
Supplier, EDC, or Utility
Company and then transferred
to the customer at a prevailing
market Rate.
 This rate can also be fixed
through a third-party Supplier,
but cannot be fixed through an
EDC or a Utility Company
 The Energy Rate composes
approx. 68% of the supply
portion of a customer’s
invoice*.

Capacity Component
The NYISO administers a capacity market to
ensure that sufficient resources are available to
meet projected load on a long-term basis

Capacity is one of the cost components that
comprises a customer’s overall invoice beyond their
energy rate
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The capacity price is based upon the price of the
capacity product and the peak usage of your
facilities (i.e. meters)
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Because the capacity product is a market-based
product the price for capacity can change based
upon the forces of supply and demand . Also a
Customer’s custom capacity tag may changed
based on demand curves as determined by the
Utility

It’s important to understand that all consumers in
New York pay an capacity tag for their facility
separate from the energy rate itself– every supplier
(competitive energy services company or utility)
must meet the same capacity requirement as
determined by NYISO rules.
Capacity accounts for roughly 25% of a customer’s
supply invoice*
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Capacity Costs- Responsibility & Obligations
 Who Pays for Capacity Costs?
 So, who actually pays for the insurance of having the necessary electricity generating
capacity available? Ultimately, it’s the consumers who pay the capacity costs based on the
auction clearing price for their zone. Energy suppliers (also known as Load Serving
Entities) charge their customers based on the approved capacity rate. This charge may be
in a separate line item on the bill or incorporated into a line item with other charges. The
supplier then pays the ISO/RTO for the capacity required to cover the MWs they are
contracted to serve and the ISO/RTO in turn pays the participating generators and
demand response suppliers.
 Determining Capacity Obligations
 Capacity obligations in many markets are generally determined by an end-user’s peak load
contribution (PLC), Installed Capacity (ICAP) or peak monthly demand during a specific
timeframe. When the end-user takes supply from an LSE, the local utility provides the PLC
to suppliers. Here are some examples of how end-users’ PLCs and ICAPs are determined.
 In New York and New England (NYISO & ISO-NE) markets, an end-user’s ICAP is
determined by their usage during the “peak hour from the previous year.” The peak hour is
the hour during which the usage was the highest across the ISO, as published by the
ISO. Once a customer’s ICAP is established, it is set for the planning year. The planning
year is May 1-April 30 in NYISO and June 1-May 31 in ISO-NE.
Components of Wholesale Electricity
Ancillary & Pass-through Charges
Overall Components resulting in
Supply Invoice:
Locational Based Marginal Price (LBMP, Energy
Rate): equal to the cost of energy
production
Transportation (losses and congestion) cost
NYPA Transmission Adjustment Charge (NTAC):
flat per MW charge to compensate the New York
Power Authority for transmission system operation
and maintenance
Reserve: market-based payment to generators
providing short-term (10 and 30 minute) reserve
power .
 Regulation: market-based payment to generators
helping to maintain frequency in real-time
Local Reliability Charge
Outages
Recovery Charges
NYISO Cost of Operation: flat per MW fee to cover
the cost of operating the NYISO
Uplift: charge for resources that must be
committed outside of market mechanism
Voltage Support: flat per MVAr payment to
generators with the ability to maintain voltage
Black-Start: cost-based payment to generators with
the ability to restart after a black-out
Capacity Charge
Ancillary Services compose roughly 8% of your
invoice*
January 2014- March 2014
What is the Polar Vortex?
 As defined by
accuweather.com:
 A polar vortex is a very rare event. It
is a large pocket of very cold air,
typically the coldest air in the
Northern hemisphere, which sits
over the polar region during the
winter season.
 The frigid air found its way into the
United States when the polar
vortex was pushed South, reaching
southern Canada and the northern
Plains, Midwest and northeastern
portions of the United States.
Polar Vortex: A Catastrophic Event

Polar Vortex (PV) 2014
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Winter 2013 experienced a record-breaking cold front, also named the polar vortex. The storm was an
extreme weather pattern that affected nearly 80% of North America. Based on statistics gathered from
more than 4000 energy measurement points at over 250 sites across North America, we have determined
that wholesale power prices increased due to many factors. Notably: volatile and extreme natural gas
pricing fluctuation, generation supply shortages, and infrastructure strain and congestion.
Some of the data findings include:
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10% of facilities had malfunctioned heaters or boilers during the Vortex
There was a 30% increase in off-hour energy consumption
364% increase in grid costs and significant strain on market operating ability
Spike of electric rates in NYISO pricing from $36.00/mWh to over $600.00/mWh
Power price increase driven by gas spike in New York (NYMEX)
Capacity costs exceed hedging mechanisms
Higher costs and fees imposed by overall Grid to all Market Participants
Major transmission line failures an grid constraints
Heavy Congestion
Major Outages
2013/14 Regulatory impositions exacerbated overall unpredictable circumstances of the PV
A Snapshot
Summary- 5 Major Cold Snaps
 Winter 2013-2014 included five (5) major “Cold Snaps” --
including three (3)Polar Vortexes that extended across much
of the country.
 JAN 7, 2014- On January 7, the NYISO set a new record
Winter Peak load of 25,738 MW. (This is the actual physical
load, not adjusted for Demand Response, which had been
activated at the time.)
 25,541 MW -- Prior record winter peak load set in 2004-26,307 MW -- “1 in 10” Forecast Winter Peak for 2013-14
 Many other ISOs and utilities set record Winter Peaks,
including PJM, MISO, TVA, and Southern Company.
As reported directly from the NYISO’s Winter 2013/14
Operating Performance Presentation
As reported directly from the NYISO’s Winter 2013/14
Operating Performance Presentation
As reported directly from the NYISO’s Winter 2013/14
Operating Performance Presentation
As reported directly from the NYISO’s Winter 2013/14
Operating Performance Presentation
As reported directly from the NYISO’s Winter 2013/14
Operating Performance Presentation
Summary
 Winter 2013-2014 included five (5) major “Cold Snaps” including Polar Vortex
conditions that extended across much of the country
 On January 7, the NYISO set a new, all-time Winter Peak load of 25,738 MW
25,541 MW Prior winter all-time peak load set in 2004
 26,307 MW “1 in 10” Forecast Winter Peak for 2013-14
 Many other ISOs and utilities set all-time Winter Peaks, including PJM, MISO,
TVA, and Southern Company
 The Winter of 2013-2014 has been characterized by many days of gas prices
exceeding oil prices -- resulting in high levels of economic scheduling of oilfired generation
 The majority of oil-fired generation was able to be replenished by either barge
or truck deliveries at rates close to their oil-burn rates
 The cooperation and accuracy of the daily fuel inventory information from
Generating Stations was excellent
The Polar Vortex fundamentally changed the energy industry for the
early months of 2014 due mostly to system-wide constraints and
failures.
The Polar Vortex resulted in:
Imposition of drastically higher costs and fees assessed by grid operators
Several Major ‘High Impact’ Adjustment Events
Several Major Outages and Transmission line failures and trips
Several Market Participants Defaulting/Failing to pay system
A Comparison from Nov 2013- February 2014
Market Performance Highlights
November 2013
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LBMP for November is $43.27/MWh; higher than $39.83/MWh in October and lower than $50.16/MWh in
November 2012.
– Day Ahead and Real Time Load Weighted LBMPs are higher compared to October.
November 2013 average year-to-date monthly cost of $58.14/MWh is an increase from $45.14/MWh in
November 2012.
Average daily sendout is 421 GWh/day in November; higher than 407 GWh/day in October 2013 and higher
than 410 GWh/day in November 2012.
Natural gas prices were higher compared to the previous month, and distillate prices were lower compared to
the previous month.
– Natural Gas (Transco Z6 NY) was $3.79/MMBtu, up from $3.63/MMBtu in October.Jet Kerosene Gulf Coast was
$21.01/MMBtu, down from $21.33/MMBtu in October.
– Ultra Low Sulfur No.2 Diesel NY Harbor was $21.03/MMBtu, down from $21.38/MMBtu in October.
• Uplift per MWh is lower compared to the previous month.
– Uplift (not including NYISO cost of operations) is ($0.06)/MWh; lower than $0.16/MWh in October.
• The Local Reliability Share is $0.19/MWh, lower than $0.38 in October.
• The Statewide Share is ($0.25)/MWh, lower than ($0.21)/MWh in October.
– TSA $ per NYC MWh is $0.00/MWh.
– Total uplift costs (Schedule 1 components including NYISO Cost of Operations) are lower than October.
Market Performance Highlights
December 2013
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LBMP for December is $66.39/MWh; higher than $43.27/MWh in November and $44.67/MWh
in December 2012.
– Day Ahead and Real Time Load Weighted LBMPs are higher compared to November.
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2013’s average monthly cost of $59.04/MWh is a 30% increase from $45.28/MWh in 2012.
Average daily sendout is 450 GWh/day in December; higher than 421 GWh/day in November
2013 and 434 GWh/day in December 2012.
Natural gas and distillate prices were higher compared to the previous month.
– Natural Gas (Transco Z6 NY) was $5.55/MMBtu, up 46.5% from $3.79/MMBtu in November.
– Jet Kerosene Gulf Coast was $21.93/MMBtu, up from $21.01/MMBtu in November.
– Ultra Low Sulfur No.2 Diesel NY Harbor was $21.80/MMBtu, up from $21.03/MMBtu in
November.
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Uplift per MWh is lower compared to the previous month.
– Uplift (not including NYISO cost of operations) is ($0.25)/MWh; lower than ($0.06)/MWh in November.
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The Local Reliability Share is $0.12/MWh, lower than $0.19 in November.
The Statewide Share is ($0.37)/MWh, lower than ($0.25)/MWh in November.
– TSA $ per NYC MWh is $0.00/MWh.
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Total uplift costs (Schedule 1 components including NYISO Cost of Operations) are lower than
November.
Market Performance Highlights
January 2014
 LBMP for January is $183.25/MWh; 176% higher than $66.39/MWh in December
2013 and 130% higher than $79.77/MWh in January 2013.
– Day Ahead and Real Time Load Weighted LBMPs are ~170% higher compared to December.
 January 2014 average year-to-date monthly cost of $185.55/MWh is a 125% increase
from $82.34/MWh in January 2013.
 Average daily sendout is 475 GWh/day in January; higher than 450 GWh/day in
December 2013 and 453 GWh/day in January 2013.
 Natural gas prices were higher compared to the previous month, and distillate
prices were mixed compared to the previous month.
– Natural Gas (Transco Z6 NY) was $27.43/MMBtu, up 394% from $5.55/MMBtu in December.
– Jet Kerosene Gulf Coast was $21.65/MMBtu, down from $21.93/MMBtu in December.
– Ultra Low Sulfur No.2 Diesel NY Harbor was $22.26/MMBtu, up from $21.80/MMBtu in
December.
 The Local Reliability Share is $1.38/MWh, higher than $0.12 in December.
 Total uplift costs (Schedule 1 components including NYISO Cost of Operations) are
included separately.
Market Performance Highlights
February 2014
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LBMP for February is $123.16/MWh; 33% lower than $183.25/MWh in January 2014 and 44%
higher than $85.76/MWh in February 2013.
– Day Ahead and Real Time Load Weighted LBMPs are lower compared to January.
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February 2014 average year-to-date monthly cost of $157.40/MWh is an 85% increase from
$85.08/MWh in February 2013.
Average daily sendout is 460 GWh/day in February; lower than 475 GWh/day in January 2014
and higher than 453 GWh/day in February 2013.
Natural gas prices were lower compared to the previous month, and distillate prices were
higher compared to the previous month.
– Natural Gas (Transco Z6 NY) was $11.64/MMBtu, down 58% from $27.43/MMBtu in January.
– Jet Kerosene Gulf Coast was $21.96/MMBtu, up from $21.65/MMBtu in January.
– Ultra Low Sulfur No.2 Diesel NY Harbor was $23.10/MMBtu, up from $22.26/MMBtu in January.
• Uplift per MWh is lower compared to the previous month.
– Uplift (not including NYISO cost of operations) is $0.25/MWh; higher than in January.
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The Local Reliability Share is $0.73/MWh, lower than $1.38 in January.
The Statewide Share is ($0.49)/MWh, higher than ($1.73)/MWh in January.
– TSA $ per NYC MWh is $0.00/MWh.
– Total uplift costs (Schedule 1 components including NYISO Cost of Operations) are higher than January.
Unprecedented High
Impact Adjustments
absorbed by Market
Participants.
Spanning from December 2013
through March 2014, the
NYISO Market issued several
major high impact
adjustments to be included
within Supplier invoices.
The level of these
adjustments exceeded
anything seen in the past.
December 2013
January 2014
February 2014
*Since our inception into the Market we have never seen ICAP Penalties reported. In February
2014, twenty-five (25) ICAP Penalties were assessed.
March 2014
April 2014
During the effected months, the NYISO experienced an
unprecedented number of forced outages and transmission line
failures, trips, and unit suspensions. These outages resulted in
catastrophic system constraints leading to increased costs in
services and an overall increase in power rates due to an
overburdened system.
Causation: NYISO Outages
Summary
 The majority of gas-only generators connected to interstate pipelines was
not economically scheduled during these five cold snaps due to the extremely
high gas prices.
A limited amount of gas-fired generation capability connected to the NYC
LDC gas systems was able to secure gas in response to NYISO or TO requests for
operation during these cold snaps.
The primary operational issues during the first three cold snaps were cold
weather equipment issue and gas-only generator outages
The primary operational issues during the last two cold snaps were oil
inventory monitoring and management.
Major Event: On Monday, January 6, 2014, NYPA 345kV Y49 cable tripped early
in the morning and remained out-of-service through January 16 (10 days).
Outages as defined by NYISO Scheduling Manual
(Issued 10/2013, Effective 11/1/2013)
 Transmission Facilities Outages Impact on Congestion Settlements
Transmission facility outages can have an impact on congestion settlements
related to the Day-Ahead Market and TCC Auction settlements, as described in
Attachment N of the NYISO Open Access Transmission Tariff (available from
the NYISO Web site at
http://www.nyiso.com/public/markets_operations/documents/tariffs/index.jsp)
. Attachment N defines the congestion rent shortfall charges and congestion
rent surplus payments to TOs, resulting from transmission facility outages and
returns-to-service.
 Outages of transmission and generation facilities affect the reliability of the
power system. Consequently, the NYISO is assigned the responsibility to
coordinate outages to maintain reliable operation of the NYS Power System in
accordance with Good Utility Practice and the Reliability Rules as established
by the New York State Reliability Council (NYSRC).
Jan 6 &7- Highest level of forced
Outages
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Generally, many Independent System Operators (ISOs)
experienced high levels of forced outages on Jan. 6 and 7 (Figure
4). Additionally, winter peak demand hit records or near-records
in all eastern ISOs. Many ISOs were forced to issue emergency
alerts and call reserves or reduce voltage. This raises the question
as to whether the system operated reasonably well under
extreme circumstances or, alternatively, whether changes in the
resource mix with coal retirements, increased reliance on natural
gas, increased reliance on summer-only resources (notably
demand resources, but also increasingly generation), and
increased penetration of intermittent supply, combined with
market structure changes, may be inadvertently compromising
grid reliability and/or resulting in very high prices that might be
avoided. We believe this question can be answered only with
detailed forensic evaluation, and this activity should be
undertaken in the near-term.
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Natural gas prices in New England and eastern New York
reached record highs on Jan. 7. While there are unconfirmed
reports of some wellhead freeze-off in the Marcellus area and the
Texas Eastern Transmission compressor station in Pennsylvania
was out of service for a portion of the day, there appear to have
been no major gas supply disruptions during the cold snap; in
other words, the high prices at New England and eastern New
York hubs were due to high demand and pipeline constraints,
not an interruption of upstream gas supplies.
Increased Transmission Costs due to Outages and Grid Constraint
Transmission Usage Charge
Transmission Usage Charge (TUC) payments are made by the Transmission Customer to cover the cost
of Marginal Losses and, during periods of time when the transmission system is constrained, the
marginal cost of congestion. The TUC is equal to the product of: (1) the Locational Based Marginal
Pricing (LBMP) at the Point of Withdrawal (POW) minus the LBMP at the Point of Injection (POI) (in
$/MWh), and (2) the scheduled or delivered Energy (in MWh).Transmission Customers pay the TUC
monthly, based on the aggregate hourly Day-Ahead schedules and Real-Time operation. Charges depend
primarily on the amount of energy involved and the LBMPs at the POI and the POW.
Transmission congestion results from physical limits on how much power the New York electric grid
can reliably transfer. Congestion adds to the costs of electricity by limiting the ability of lower-cost power
to be transmitted to consumers. Solutions to congestion may include building or upgrading transmission
lines and related facilities, building less expensive power generation next to the load or employing
measures to reduce demand for electricity in the congested area. (http://readme.readmedia.com/NYISOto-Host-Forum-on-Transmission-Congestion-Study/7518674)
Should they occur, who Pays these increased costs?- Suppliers & Consumers
The NYISO charges each Transmission Customer, which has a bilateral transaction accepted by the
NYISO, a TUC. The TUC is charged and payable monthly. The TUC consists of a Marginal Losses
Component and a Congestion Component. It is assessed on an Energy (MWh) basis to all Transmission
Customers undertaking bilateral transactions, including transactions to supply Load within the New York
Control Area (NYCA), Wheel-Throughs, and Exports. There is an exception. Parties using Grandfathered
Rights will not have to pay the Congestion Component of the TUC, but will be assessed charges as
specified in section 6 of the NYISO Transmission Services Manual
Outage Notification Example
(Jan 14)
Major Event- NYPA 345kV Y49 cable tripped
Line Outage 1/6/2014-1/16/2014
OUT for 10 Days
Major Event- NYPA 345kV Y49 cable tripped
 On Monday, January 6, 2014, NYPA 345kV Y49 cable tripped
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early in morning and remained out-of-service through January 16.
Any transmission unit, cable, or line that is responsible for
servicing the overall system ranging from 345kV-765kV is
considered a major and fundamental asset
If one of these assets fails, it is considered a near catastrophic
event to the overall system
NYPA 345kV Y49 cable tripped on January 6, 2014 and the outage
lasted for 10 days through January 16, 2014!
This major line outage led to significant constraints on other grid
resources and effectuated increased imposition of fees and
charges and significantly impacted operating costs for Market
Participants
Preparation & Response
New Wave’s Approach to the Polar
Vortex
 Mitigated costs to our Customer base:
 Increased rates to in proportion to market swings to cover costs and ensure
profits
 Had various hedges in place regarding capacity and other services to mitigate
exposure
 We maintained rates for our customers from $.10/kWh-.$145/kWh
 Participated in conference calls with the NYISO and all major NY Utility
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Companies within our service territory
Issued System Alerts via system-wide e-mail to our customer base and through
other means
Issued a system-wide website alert, utilizing our website “Ticker”
Issued Daily Market reports to our Customers
Issued and advance Polar Vortex Alert and Consumer Mitigation Suggestions
Issued a Market Report & Summary (Q1-Partial)- February 20, 2014
Posting of various updates on Social Media (Facebook & Twitter)
Various news articles, resources, and references sent to Customers
System Alert E-mail example
Polar Vortex Alert example
Pertinent Regulatory Bodies
 In addition to the Utility Companies, the NYISO, and the NYS DPS--- other regulatory
bodies that can impact the market include, but are not limited to:
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New York Independent Systems Operator (NYISO)
New York Control Area (NYCA)
New York Power Authority (NYPA)
Federal Energy Regulatory Committee (FERC)
Northeast Regulatory Committee (NERC)
Mid-west ISO (MISO)
Environmental Protection Agency (EPA)
US Energy Institute Administration (EIA)
 These government and quasi-government entities have the ability to issue mandates,
orders, edicts, legislation and other impositions that effect overall system and
commodity costs. Many orders were issued over the course of the first quarter of 2014,
which often exacerbated the unpredictably of the Polar Vortex effect on Market
Participants and Ratepayers.
 An abridged selection of these various issuances can be viewed on the following slides.
NYISO Regulatory filings (Jan ‘14) example
FERC Regulatory filings (Jan ‘14) example
EPA Regulatory filings (Jan ‘14) example
Various Links to Resources and News Articles
Energy Resources
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New Wave Energy Corp.
NYMEX Settlement
New York Independent Systems Operator (NYISO)
CME Group- Natural Gas Settlement
National Grid (NIMO)
New York State Electric & Gas (NYSEG)
Rochester Electric & Gas (RGE)
National Fuel Gas (NFGDC)
Federal Energy Regulatory Committee (FERC)
United States Environmental Protection Agency (EPA)
National Oceanic and Atmospheric Administration (NOAA)
US Energy Information Administration
Polar Vortex in the News
 How the Polar Vortex Impacted Energy Prices, Grid
Reliability
 Times Union- STICKER SHOCK- Cold weather
pushing up electricity rates
 National Grid bills surge: The Real Deal
 Kennedy calls for creation of utility consumer advocate
to blunt rate hikes
 Seven scary things to know about your February
electric bill