IEEE Power & Energy Magazine - November/December 2017 - 85

transmission owners and customers. These revenues support
transmission investment, maintenance, and operations. The
Federal Energy Regulatory Commission (FERC) approves
the transmission tariffs for interstate transmission, and it
also regulates regional transmission organizations (RTOs).
Provisions for wind and other renewable energy resources
are included in the tariff.
The details are different for every system operator in the
United States; but, given its size and similarities to other large
system operators, the Midcontinent Independent System Operator (MISO) provides a good example with which to describe
the typical U.S. planning process. Historically, in MISO, about
85% of the revenue for transmission has come from state regulation and about 15% from FERC regulation. RTOs collect the
revenues for federally regulated transmission and distribute
these to the transmission owners. FERC Order 1000 addresses
interregional studies for cost-allocated transmission. Planning
processes must determine what transmission is to be constructed and what transmission is to be cost-allocated according to the tariff. MISO and others have a bidding process to
select the constructor of the cost-allocated lines.
The MISO Board of Directors planning principles provide
general guidance to the planning process. Specific planning
criteria and both reliability and economic planning standards
developed by the North American Electric Reliability Corporation (NERC) are the foundation for reliability requirements,
together with specific local criteria that may require performance beyond what NERC standards demand. Economic criteria are developed (with FERC approval) by RTO staff and
stakeholders or by utilities.
Many RTOs and utilities use a reliability method to justify transmission expansion. Justification based on reliability generally means that the transmission expansion needs
to meet NERC and local criteria. The lowest-cost option is
generally chosen, but there may be factors other than cost
involved in the transmission expansion decision.
Generally, there is no cost allocation associated with reliability-justified projects. If there is significant congestion on
the transmission system, transmission expansions to address the
congestion are proposed by stakeholders; RTO staff members
evaluate these proposals and determine a project to recommend.
An alternate planning process uses production cost simulations (PCSs) to identify projects based on economic justification; these projects may not be required based on reliability
justification alone. For example, MISO's multivalue projects
(MVPs) cost US$6.5 billion, with the last of the lines due
to be completed in 2021. These projects, with a benefit-tocost ratio of 1.8:1, mitigated most of the congestion in MISO
and thus significantly improved market efficiency for the
northern and central regions. They are designed to deliver
21,000 MW of wind from renewable energy zones across
the MISO footprint; they also improve reliability and replace
some reliability-justified transmission expansion. The MVPs
are being constructed under a cost-allocation tariff provision that was in place prior to FERC Order 1000. The MVP
november/december 2017

process mined the potential value for transmission expansion from the MISO north and central areas to operate in a
single balancing area (BA) market.
Prior to the MVPs the MISO transmission system was built
to serve 26 utility BAs, not to operate as a market. The MVPs
converted the transmission system in the MISO north and central areas to operate as a central dispatched market. As a result,
there are now fewer opportunities to identify MVPs that can
be economically justified in MISO. MISO reliability-based
transmission has resulted in approximately US$15 billion of
planned transmission expansion since 2003. MISO's transmission expansion plan reports and similar reports for other RTOs
provide annual information about the state of transmission planning and construction.

Europe
European transmission system operators (TSOs) collaborate
with ENTSO-E on the joint development of a long-term network plan for the European high-voltage grid, published in
even years. Planning takes two years and is performed in
three main steps.
First, relevant visions of the future are developed in cooperation with the European Network of TSOs for Gas, ensuring joint
and consistent assumptions behind the long-term development
plans for both energy infrastructures. Information and data are
exchanged throughout the process of developing these plans on
time horizons extending to 2030 and 2040, respectively.
This vision-development step includes extensive stakeholder involvement throughout all phases, from draft storylines down to concrete numbers for all types of generation
and demand, each aiming to fulfill European energy targets.
Location adjustments for renewable energy sources (RES)
reflecting meteorological relationships are considered (see
the "Meteorological Influences" section), as well as the
potential changes resulting in the thermal power plant fleet
(accounting for cross-border resource sharing, because the
sizes of European countries differ). The various visions are
based on climate information (i.e., temperature-dependent
demand and wind, solar, and hydro production data) from the
previous 35 years. These data are adjusted to reflect assumptions regarding technology developments and scaled to fit the
developed visions.
Based on these visions, in a second step, the needs for both
electric and gas infrastructures are identified. For electricity,
hourly marginal system costs are simulated using, in parallel, several market simulation tools (some deterministic, others probabilistic) that complement each other to capture the
specifics of different European areas (some including more
stochastic elements than others). The resulting main flows
across the European Union (EU) system are analyzed and
evaluated for security of supply, RES integration, and socioeconomic welfare (SEW); iterations between market and
network simulations evaluate if (and how) required market
flows can be transported through the grid and which expansions are needed, taking into account the associated costs. The
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