Over the past year, the energy industry has experienced a tremendous increase
in the type and amount of information demanded by regulators and the broader market.
A plethora of events, beginning with the California energy crisis, the collapse
of Enron, the Sarbanes-Oxley act, and increased scrutiny of energy trading, among
others, has placed an unprecedented level of disclosure demands upon the industry.

The difficulties companies had in preparing and responding to these new information
demands painfully demonstrated the need for better visibility, adaptability,
and flexibility in those views of the business. Organizations must reach for
an integrated framework for effectively aggregating, analyzing, and sharing
critical information between sources inside and outside the organization, enabling
more informed decision-making.

As personalized, role-based business intelligence and performance management
continues to evolve, analytical applications will be at the forefront of driving
the organization’s core business processes. We will see organizations strive
for an environment that integrates not just financial, but all analytics in
order to thrive in a variety of business conditions.

Drivers for Change

In recent months, credit agencies have downgraded diversified energy companies.
Given the importance of the cost of debt and its relationship to the profitability,
companies are quickly learning the value of providing the rating agencies with
all information that may help avoid an incorrect assessment of its risk. Investors,
too, have had to grapple with understanding the value of companies in this environment.

The capital markets have assumed even greater significance as the industry
moves onto a global footing through consolidation and intense merger and acquisition
activity. The economic downturn and the increasing problems with unbalanced
capital structures due to an overweight of short-term debt makes an accurate
valuation foundation even more critical.

A recently published survey by PricewaterhouseCoopers shows that 70 percent
of energy companies believe the market undervalues them. The capital markets
say they need to have better indicators to fully understand and value companies.

We believe the market will reward companies for improved corporate disclosure.
But this is not just about reporting to investors and other stakeholders. In
the long term, this is about managing the company more effectively.

The last several years have demonstrated the importance of being able to change
business focus toward value-creating activities. An industry and analyst focus
that rewarded the pursuit of aggressive investments such as energy trading are
now penalizing those same investments. A return to the core businesses of generation,
transmission, and distribution will provide the safe harbor and cash flows investors
now seek.

With decreasing access to favorable debt terms, asset sell-offs and divestitures
may become a necessary evil for several market players. An increased cost of
capital is considered unavoidable for most industry players; the question is
who will manage to satisfy the capital market to stay competitive despite significant
debt renewals over the coming year.

Driving Competitive Advantage

The right analytical processes and enabling technology must be in place to
quickly and proactively correct the strategic course in today’s changing environment.
The capability of embedding analytical processes and linked key measures for
decision-making within the management chain will become a requirement for companies
to thrive in a highly competitive and rapidly changing business environment.

Integrating Processes

We began by focusing on integrated business processes associated with value
assessment, strategic planning, operational planning, and performance management
and control cycles. The objective is to design data management systems to verify
that they support the linking of output from strategic and business planning
at an aggregate level, budgeting at a departmental level, or from performance
management at any and all levels.

Another key objective is determining that employees are spending time and resources
on what creates shareholder value in the most efficient way possible. The availability
of decision data is crucial. A framework should identify and leverage information
across the value chain, making the required information available in exactly
the form and frequency needed.

A well-implemented framework will embed decision-making power, ensuring consistency
between the targets set and initiatives implemented and further reducing the
time required to react to changing market conditions. (See Figure 1.)

Figure 1: Data Framework

 

Frameworks should verify that:

• All strategic decisions are based on shareholder value criteria and
on realizing the most value possible from investments in strategic and tactical
initiatives.
• Management processes required to effectively plan, budget, allocate and
manage resources across the organization are in place.
• The strategic message is communicated clearly throughout the organization
by simplifying the information landscape with personalized views that support
stakeholders.
• The required decision-support systems are available on all organizational
levels when required, as required, and with the quality required, leveraging
business intelligence across the enterprise.
• Advanced analytical applications are used efficiently to solve business
problems as they arise or even anticipate problems before they arise.

Integrated Planning

An integrated planning solution describes the set of management processes required
to effectively plan, budget, allocate, and manage resources across the organization.
When a solution is deployed effectively, it is linked to the overall performance
management framework, and verifies that the organization’s relationship between
performance measures and actions are well coordinated.

An effective integrated process will utilize a common set of drivers, performance
measures, and assumptions. These will be shared between business processes and
their associated supporting applications, which will determine that a change
to a single driver or assumption will permeate throughout the entire framework.
For example, the same values should be utilized when determining a calculation
for maintenance cost per line mile, whether producing output from a business
planning application at an aggregate level, a budgeting application at a departmental
level, or from a balanced scorecard application at any and all levels.

When business processes support the capture of statistical and financial results,
analytical forecasting engines can be utilized to provide projections on an
automated basis. This will enable managers and business analysts to engage in
activities that provide greater value.

The business processes covered in an integrated planning framework include
strategic planning, business planning, financial planning and forecasting, budgeting,
and performance measurement.

Integrated and aligned planning processes enable utilities to implement strategic
changes faster and more consistently across business units and functional areas.

The transition from a high investment environment aiming at building new business
areas, such as trading and increasing market share through mergers and acquisitions,
to a cost- and risk-concerned environment moving back to core business areas
requires very efficient and integrated planning processes. Changing direction
is all about speed and agility in determining what will create value, what initiatives
are required, where resources are best used, and supporting a smooth implementation.

Integrated Performance Management

Performance management is best described as an integrated set of activities
to effectively plan, budget, allocate, and manage resources across an enterprise.
It is the process by which a company makes its strategy happen. Effective performance
management drives the company’s operational, financial, and business performance,
helping to ensure that the strategy is delivered efficiently and effectively.

A value-based management approach begins with the identification and decomposition
of the value chain into major activities. Specific business drivers and initiatives
can be targeted as a means to improve value, and can be used as a basis for
planning and performance measurement. Cascading business drivers and initiatives
down and across the organization facilitate a clear focus and an agile strategy
implementation.

There is no shortage of enterprise-wide measures and targets to choose from.
Initially, it is important to stratify measures into two broad categories: enterprise
level, or those used by executives and for business portfolio management; and
operational level, or those used by operational managers and leadership.

While enterprise measures provide the information necessary for major investment
decisions and strategic orientation, operational-level metrics are concerned
with optimization of the business processes and ultimately support the enterprise
measures if aligned correctly.

This approach can also be used to develop tactics for realizing the value of
entering new businesses, integration of merged organizations, or implementation
of cost-cutting or risk-management initiatives. Often, identified business value
opportunities are not driven down through the organization to specific targets
for accountability from individual groups.

A value management approach can help ensure consistency in what external capital
market stakeholders are considering critical and what is measured and targeted
internally. This orientation may promote programs that optimize return on assets
over the long term, even if some short-term initiatives would not be normally
feasible outside of this context. This approach can strengthen the ability to
communicate clearly and consistently to capital market players, potentially
positively affecting credit risk ratings and market capitalization, and thereby
the cost of capital.

Figure 2: Technological Environment

Technological Footprint

In order to optimize the value of processes in the framework, the right technical
solutions must be deployed and tightly integrated. To support a more seamless
flow of information, existing systems often need to be changed to capture new
information or provide better data integration. The challenge is to gain an
understanding of the existing environment, develop a future state technical
framework based on defined process and metric requirements, and develop a phased
plan to migrate to the new state.

Developing a strong technical environment will require a number of data repositories,
analytical calculation engines, and presentation and reporting tools. The right
tool is one that is based on clear requirements. For data repositories, relational
databases are typically used for integrating large amounts of detailed information
from various sources.

Applications that require fast, multi-dimensional access to aggregated information
may utilize online analytical processing databases. The ability to consistently
extract data from various sources for downstream analytical databases and applications
is critical. To support this need, many companies acquire or develop extraction,
transform, and load tools for moving data quickly and accurately between source
and target databases and applications. Analytical calculations are often provided
as part of an analytical application, such as a business modeling or operational
planning tool.

Finally, several types of presentation tools are needed to deliver the right
view of information to the end user. Again, the business process needs should
drive tool requirements. Types of requirements range from ad hoc reporting to
online front ends with the ability to drill down into detailed information for
further investigation or opportunity assessment. Developing the technical environment
based on clearly defined process and technical requirements will support the
right selection and integration of tools.

Market players able to take advantage of these tools and frameworks will place
themselves on the front line in the competition for capital, proving to be among
the best in their market for long-term value creation and risk management.

Columbia Gas Transmission, an operating company of NiSource, Inc., offers a variety
of competitively priced natural gas transportation and storage services built
on a proven record of superior customer service and customer satisfaction. NiSource
is a holding company with headquarters in Merrillville, Indiana, whose core operating
companies engage in natural gas transmission, storage and distribution as well
as electric generation, transmission and distribution.

On average, Columbia Gas Transmission moves more than 3 billion cubic feet
(Bcf) per day of natural gas through a 12,550-mile pipeline network that covers
Midwestern, Northeastern and Mid-Atlantic States. The natural gas is delivered
to local distribution companies and industrial and commercial customers. Columbia
Gas Transmission owns and operates one of North America’s largest underground
natural gas storage systems and uses depleted natural gas production fields
for reservoirs to store natural gas close to major markets throughout its system.
The company’s vast network of underground storage fields combined with its extensive,
reticulated pipeline system allows Columbia Gas Transmission to be flexible
in meeting unexpected customer demands.

As a company whose product can have far-reaching effects on the environment
and whose employees must maintain the highest safety standards, Columbia Gas
Transmission’s equipment must meet the stringent compliance regulations of both
federal and local government. Regulatory agencies such as OSHA, the Department
of Transportation (DOT) Pipeline Safety and the EPA mandate regular relief valve
inspections, fire extinguisher and eye wash station inspections and the monitoring
of exhaust emissions, to name a few. To ensure successful compliance with all
of these various regulations, Columbia Gas Transmission required an automated
system to track work orders, projects, job plans, and equipment conditions.

After comparing several strategic asset management solutions, Columbia Gas
Transmission selected MRO Software’s MAXIMO^® as its
solution for managing and scheduling compliance and maintenance activities.
Using MAXIMO, Columbia Gas Transmission sought to gain an increased understanding
of compliance within its business, and to ensure that all requirements were
being met. The company used MAXIMO to establish several procedures that cover
these issues, allowing employees to easily manage compliance requirements.

“At our company, every employee needs to be responsible for details such as
preventive maintenance and procedure,” said Troy Harlow, senior engineer with
Columbia Gas Transmission. “We use MAXIMO to help our managers determine what
needs to be done, when it needs to be done and who is responsible for it. Prior
to implementing MAXIMO, we used cumbersome forms and various computer applications
to track our regulatory requirements. MAXIMO has enabled us to keep a very close
eye on this very crucial aspect of this business.”

Using MAXIMO, Columbia Gas Transmission decided to automate required DOT tasks
by eliminating manual forms and electronically tracking the work. The company
mandated that these procedures should not be conducted via manual forms. Automating
these procedures gives Columbia Gas Transmission easy access to the backup needed
during audits.

“During a given year, we can have 20 to 30 DOT audits throughout our organization.
Prior to MAXIMO, compiling the data for a DOT audit could take a person a week,”
commented Harlow. “Now MAXIMO helps us compile the necessary information in
just a few hours. Depending on the number of mandated audits, the yearly time
savings can range from 19 to 28 weeks in labor hours alone.”

Columbia Gas Transmission also leverages MAXIMO’s labor module to adhere to
the new Operator Qualification (OQ) regulation — 49 CFR Part 192. The qualification
and training needs of pipeline companies throughout the United States are being
significantly impacted by a regulation enacted by the U.S. Department of Transportation
(DOT), which went into full effect October 28, 2002.

Under the new Operator Qualification (OQ) regulation, operators of gas pipeline
companies must develop and maintain a written qualification program for employees,
contractors, and others who perform specific duties (“covered tasks”) as they
operate and maintain such facilities. The OQ rule was instituted to help ensure
a qualified work force and to reduce the probability and consequences of incidents
due to human error.

“MAXIMO’s labor module helps us adhere to this new regulation,” commented Harlow.
“MAXIMO helps ensure that the technicians performing ‘covered tasks’ such as
valve operation are qualified. MAXIMO tracks the history of each work order
and provides information proving that only qualified operators are completing
these tasks. Based on the day’s work, we also use MAXIMO to efficiently schedule
the qualified operator’s time.”

Columbia Gas Transmission used MAXIMO to implement a standardized company-wide
information system. Using the work order module, users gain instant access to
information (including long descriptions, labor required, and operating procedures)
which notifies the user of regulatory requirements placed on each work order.
Columbia Gas Transmission then compiles a detailed compliance report, which
ensures that all regulatory work is completed correctly, on time, and documented.

The quick and easy access to this information has improved Columbia Gas Transmission’s
facilities’ ability to track regulatory issues and made work management processes
more efficient. The product has also enabled team leaders to elevate their level
of tracking processes onto computers and eliminated the time-consuming procedures
involved in using paper forms.

“We were impressed with MAXIMO’s flexibility,” commented Harlow. “Whenever
a manager discovers another aspect of the business that he or she needs to track,
we are able to plug it into the system without difficulty. Consequently, MAXIMO
has become the warehouse for several required inspections and records within
Columbia Gas Transmission.”

To increase the mobility of its technicians, Columbia Gas Transmission also
deployed the MAXIMO Mobile Suite. Using the mobile technology, technicians monitor,
report, and create work orders on hundreds of miles of lines, substations, and
towers. This technology increases productivity as it brings MAXIMO to the point
of performance. For example, technicians now generate work requests directly
from the field. This mobility eliminates the technician’s travel time and ensures
a quicker resolution to emergencies.

“The MAXIMO Mobile Suite helps support our efforts to eliminate paper work
orders because it provides technicians with the ability to access work orders
and capture performance data remotely and puts information at the their fingertips,”
added Harlow. “This technology also increases the quantity and accuracy of the
regulatory data collected in the field and eliminates duplicate data entry.”

In addition to the MAXIMO labor and work order modules, Columbia Gas Transmission
also uses several additional MAXIMO modules. For example, the preventive maintenance
module outlines the frequency with which certain equipment needs to be serviced.
The module also details which supervisors are charged with the maintenance task
and the specific procedures and standards involved with the upkeep of Columbia
Gas Transmission’s equipment. This interface enables the company to reduce the
overall cost of equipment maintenance by giving supervisors the ability to identify
and address maintenance needs before problems occur.

MAXIMO’s job plan module is described as the repository for the company’s maintenance
procedures. Columbia Gas Transmission uses MAXIMO’s security features, allowing
selected managers to change information in the job plan module. This feature
enables the managers to access updated and reliable information at all times.

“MAXIMO has become our system for nearly all procedures,” said Harlow. “We
currently have 60-70 procedures in our job plan module that are mandated by
the Department of Transportation and our company. MAXIMO gives our department
heads easy access to these procedures. This way there is no confusion and no
excuses for incorrect procedures. In addition, when new employees join our company,
MAXIMO immediately puts all of the rules and regulations at their fingertips.”

Goals:

• Automate DOT Audits

• Adhere to the new Operator Qualification (OQ) regulation — 49
CFR Part 192

• Increase the mobility of its technicians

Results:

• MAXIMO reduced the time needed to compile data for DOT audits from
a week to a few hours, netting a yearly time savings of 19-28 weeks

• Columbia Gas Transmission adheres to the Operator Qualification (OQ)
regulation by using MAXIMO’s labor module to ensure that qualified technicians
perform “covered tasks”

• MAXIMO Mobile Suite eliminates technician’s travel time and duplicate
entry, increases the quantity and accuracy of the regulatory data collected
in the field and ensures a quicker resolution to emergencies

 

To say that the Seabrook nuclear power station has had a tumultuous history
is an understatement. The Boston Globe called it the place where nuclear
power was stopped in its tracks. A half finished containment dome-construction
was halted in 1984 by protests and costs overruns-for the second of two 1,160-MW
reactors planned for the site serves as a monument to the social and economic
problems the nuclear power industry could not overcome. However, a lot has changed
for and at Seabrook since the 1980s.

Today, the plant, which is one hour’s drive north of Boston and two miles inland
of the New Hampshire coast, provides electricity for one million New England
homes from its first and only unit. While memories of the protests and safety
concerns surrounding the station still linger in the minds of local residents,
many have been erased-or at least eased-by a long running program that commits
the staff of Seabrook to strive for excellence. Called “Values For Excellence,”
the program included an initiative to automate and thereby improve the maintenance
elements of the plant’s work, safety, and materials management efforts and purchasing
activities.

Maintenance, Manual

Following startup in 1990, Seabrook’s maintenance program used manual processes
to catalog and store the station’s hundreds of thousands of labor records, job
plans, work orders, equipment lists, and inventory items. The U.S. Nuclear Regulatory
Commission requires all nuclear plants to meticulously maintain detailed records
of all their activities and equipment, right down to the history of all materials
used on site.

Although many of the manual processes had been refined over the past decade,
the explosion of information that needed to be stored called for a new approach,
according to Greg Kann, Seabrook’s electronic work control project manager.
He says that Seabrook wanted to do additional analysis and reporting, but couldn’t
because the manual processes were far too slow and cumbersome. “One of our primary
tactics had been to continuously improve the maintenance processes to world-class
levels. But eventually we realized that that wouldn’t work, and that we needed
to automate them,” explains Kann.

User Acceptance Was Key

Kann knew that to be successful, he needed to put in a system that was going
to be flexible and act as a foundation for future enhancements. “I did not want
to install an automated system and try to re-engineer the maintenance program
at the same time,” he recalls. “We had been making process improvements all
along, so a key objective of the new system was that it would not require re-engineering
of existing processes. User acceptance of new systems is hard enough to achieve,
and introducing new processes at the same time would have met great resistance,”
says Kann.

Another selection criterion for the system was that it be intuitive and use
Windows-like navigation techniques, to minimize training time. In addition to
meeting technical requirements, the automated system would also have to be accessible
to 500 more people who could use it with minimal support.

Many Were Called, One Was Chosen

When Kann went shopping for a solution, he was pleased to find that several
commercial products could do what was required. In the end, however, ease of
use and the ability to be modified easily became the two most important selection
criteria. As the 1990s drew to a close, Kann settled on Maximo 4.1 from MRO
Software, Bedford, Mass. “Maximo is very intuitive and has built-in help features
which address the user acceptance problem. What’s more, the system accommodates
changes easily, has terrific reporting and analysis tools, and provides a strong
foundation for future enhancements,” Kann says.

A Smooth Implementation

Implementation of Maximo began in January 2001 and was completed by last Thanksgiving.
Kann personally installed its work order, equipment, job plan, inventory, preventive
maintenance, and labor modules. He attributes the success of the overall project
to plenty of upfront planning and user training. Populating the system’s data
base seemed daunting at first, because the work records and other documents
that had to be digitized and stored were voluminous, extremely detailed, and
go back 15 years. Because the plan was to give access to Maximo to all personnel
at Seabrook, the implementation had to be methodical and almost flawless so
that it wouldn’t disrupt operation of the existing maintenance system, causing
the new system to make a bad first impression on users.

Looking back now, Kann calls the implementation “a tremendous success. We expect
the help desk to be overwhelmed with calls the first week after going live,
but that didn’t happen. All the hard work that went into planning and training
really paid off, and users had and continue to have nothing but praise for the
new system.

Early Results

Now that the system has been running for over three months, it is really beginning
to shine. The population effort loaded the following into Maximo:

• More than 500,00 work order records, each with more than 150 elements,
for a total of 75-million pieces of data.

• A total of 14,280 preventive maintenance tasks, each with an associated
job plan.

• Some 1,615 labor records and 104,512 location and equipment records,
each with an average of 40 specifications.

Says Kann, “We’re starting to see tangible improvements in our safety, performance,
and maintenance processes. Users are particularly amazed at the software’s reporting
capabilities, which allow them to access key performance indicator reports much
more quickly. In addition, its more accurate scheduling functions have already
served to reduce maintenance backlogs.” All work orders are created and stored
electronically. What’s more, Seabrook can use a job plan library, which allows
users to easily import saved plans into new work orders.

We’re being sold? No Biggie

As part of New Hampshire’s deregulation program, the consortium of utilities
that owns Seabrook will sell the plant, most likely this year. With the pending
sale, you might think that plans for enhancing the maintenance system would
be on hold-but that’s not the case, according to Kann. “We still plan to install
Maximo’s purchasing and inventory modules, and use the software’s linked document
feature to hook the system up to a new electronic document management system
currently in development.”

As for the effect of the sale on staff working on the system, Kann has this
to say. “We think having a world-class maintenance program will make Seabrook
even more attractive to potential buyers. It’s just another example of the “Values
For Excellence” philosophy that suffuses all our operations here at Seabrook.”

by Jon Arnold

Reprinted from EnergyIT, March/April 2002, copyright by The
McGraw-Hill Companies, Inc., with all rights reserved. This
reprint implies no endorsement, either tacit or expressed, of any company, product,
service or investment opportunity.

 

Energy companies transact close to a million dollars a day for physical delivery
in markets run by independent systems operators. The settlement of those transactions
may not occur until months after the power flows. Assuming a conservative error
rate of 2 percent in invoice calculations, a large market participant could be
exposed to losses of tens of thousands of dollars per day without even knowing
it.

Companies will continue to face financial exposure as ISOs evolve to a nationwide
system of regional transmission organizations and/or independent transmission
providers (ITPs). The United States Supreme Court reinforced the Federal Energy
Regulatory Commission’s decision to move quickly toward transmission and energy
markets overseen by RTOs. Markets will come online quickly, and energy companies
need to be ready to do business the minute they do. Just to keep the lights
on around the clock, companies need to schedule the flow.

Companies that invest the time and effort now to understand market dynamics
and the systems needed to support them will be better prepared than those companies
that wait to see how the RTOs will shake out. Bidding and scheduling are mission-critical;
systems will need to be in place quickly once the new RTOs are defined.

FERC is on the fast track toward standard market design, having crisscrossed
the country to garner acceptance. AMR Research expects that many of the market
design issues will be settled and physical markets will be ready to go by early
2005. Energy companies cannot participate in the markets without a bidding and
scheduling system. Such a system is no small order.

For the ISO, RTO, or ITP, the technology is the market mechanism. ISOs have
spent $100 million to $350 million to put together information technology infrastructure,
with IT operating expenses comprising 15 to 26 percent of ISO revenue. Energy
companies must make their own IT investments to meet the data-communication
requirements of ISOs.

No matter how flexible the system is to changes in market rules, companies
will need to configure applications to fit their business requirements.

For example, one generation company found that it could achieve scheduling
efficiencies by looking at its net position while scheduling delivery. A deal
for 100 megawatts of power might require 50 megawatts from one injection point
and 50 megawatts from another, requiring the debooking of the trade deal and
rebooking two 50-megawatt deals, creating opportunities for error. Instead,
this company reworked its business processes and invested in an application
platform to give schedulers the ability to access and translate day-type trading
deals to real-time schedules.

Evidence from AMR Research interviews with energy companies suggests it will
take at least one year to create the business processes and assemble the supporting
architecture for a truly profitable operation.

Market Exposure

In the best of markets, it takes months for daily power transactions to be
completely settled. Initial settlement — the reconciliation between scheduled
and actual delivery and subsequent assignment of charges for maintaining system
balance — comes at three days, final settlement at 45 to 90 days, true-up
in six months, and over a year to resolve disputes over charges. A company that
does not have access to the right data can find itself unaware of its position.

Companies may face penalties when they under- or over-schedule. One generation
and wholesale company that also has a commercial and industrial load was hit
with unanticipated invoices, ranging in the millions of dollars, because the
load scheduled was not meeting what was being consumed through the load-serving
entities (LSEs). The company was not only penalized for under-scheduling, but
it had to pay interest on past penalties accrued, even though true-up was more
than six months later than under-scheduling incidents.

Without timely delivery of meter data, generators and power marketers must
depend on profiling and forecasting to calculate expected settlement. Meter
data is the basis for invoicing determinants, but often it isn’t delivered until
the day after or later. One energy company came closer to forecasting exposure
by taking day-ahead forecasts and rerunning these using day-of weather feeds.

Spreadsheets and back-of-the-envelope calculations are not sufficient to validate
settlements in the new markets. An invoice can hold as many as 1,000 line items.
Energy companies need to deconstruct the ISO invoice so that they can use forecasts
to re-create the invoice they can expect to receive. However, invoicing rules
are a moving target, requiring technology that offers flexibility in changing
business rules.

To understand financial exposure, companies need a fully functional scheduling
and settlement system.

In the most advanced ISOs, generators use Web or extensible markup language
(XML) transactions to communicate bids and schedules to the market, based on
their supply forecasts. Figure 1 shows the optimal flow of interactions for
the RTO. The savvy market participant will create a feedback loop to adjust
future bids and schedules.

Companies need to reproduce the ISO’s complex transmission and energy market
calculations in order to understand their final obligations and exposure. To
get it right, energy companies need to do all of the following:

• Closely forecast, profile, and/or estimate load (profile and forecast).
• Bid into day-ahead or hour-ahead markets (bidding).
• Schedule and adjust schedules to avoid penalties, reduce transmission
costs, and optimize plant operation (schedule delivery).
• Understand capacity obligations established in their contracts (contract
management).
• Interface with the ISO/RTO and/or load-serving entities (ISO interface).
• Calculate potential ISO/RTO exposure (shadow settlement).
• Perform settlement and invoice reconciliation as a basis for disputes
(settlement and invoice reconciliation).

 

Figure 1: Keeping the lights on requires around-the-clock robust systems with
messaging.
© AMR Research, Inc.

Robust Systems

Bidding and scheduling systems must be robust enough to handle hour-ahead
markets. They must operate at all hours with deadlines for flows and submittals
for every hour in the day and notifications requiring response receipts.

Although existing companies rework legacy systems connected to systems by ABB,
Siemens, or Alstom ESCA for mandatory plant dispatch, legacy bidding and scheduling
systems do not work for the new markets. Systems are not built for generators,
power marketers, or distribution companies that have divested of generation.
Also, the new RTO markets go beyond day-ahead bidding and will allow for hour-ahead
adjustments to day-ahead bids.

The volume and complexity of transactions is high. In the Italian market, for
example, a national player will have 5,000 transactions a day and 200 supply
points to inject or take out power. Similarly, a large regional U.S. player
conducts 3,000 transactions a day.

Flexible System

A technology platform that allows changes in business rules provides the most
flexibility. No two ISOs are the same, and RTOs by their nature will also be
different. RTOs will not develop for all regions on the same timetable. Each
region is also likely to have its own demand-side bidding programs or uplift
charges, and existing ISO infrastructure will be incorporated into the new RTOs.

A business process outsourcing (BPO) model works for energy companies dabbling
in more than one market. Using a BPO, an energy company can avoid the investment
and risk for entering new markets. APX, which does not take a position in the
market, provides scheduling and settlement for cents per megawatt hour. APX
has strict security protocols, but companies are reluctant to have proprietary
data hosted outside the four walls.

To handle variation in market rules requires a flexible architecture. Using
XML and open standards, Excelergy’s Energy Trading is an application layer that
sits on top of an integration platform. It is now being used to deliver a trading,
scheduling, and settlement application to American Electric Power. Vendors like
the Structure Group, while not providing the software for volume bidding and
scheduling, offer market connectors for scheduling and settlement applications.

If the promise of SMD is realized and there is greater standardization of communications,
there will be fewer connectors required to operate across markets.

The Price Tag

Expect to pay between $1.5 million and $3.5 million for a complete forecasting,
scheduling, and settlement system.

No one vendor can provide a complete scheduling and settlement system. Different
vendors provide analytic and transactional applications (see Figure 2). Energy
companies will need to assemble a set of applications to achieve visibility
to exposure in the physical markets. The potential of companies serving this
market has been proven by acquisitions in 2002: Henwood Energy Services by Global
Energy Decisions, NewEnergy Associates by Siemens Westinghouse, and RER by Itron.

Load profiling ranges from $300,000 to $500,000 and requires three to six months
to implement, with maintenance at 20 percent and an industry standard of one-to-one
license to implementation. With a longstanding history and deep market penetration
for load profiling and settlement, Lodestar has been able to use this experience
to meet the requirements of the new markets with its Lodestar Profile & Settlement
System. Lodestar’s ground-up, account-level estimation is supplemented by RER
neural network capabilities in the Texas market.

Load-profiling vendors, such as ICF Consulting and Lodestar with BillExpert,
also offer shadow settlement. In addition, the Structure Group offers shadow
settlement for ISO-New England, Electric Reliability Council of Texas (ERCOT),
and New York ISO, among other markets.

Licensing for scheduling and settlement generally runs from $500,000 to $750,000,
although it can go as low as $150,000. For market-specific connectors, add $100,000
to $750,000 more in license fees, depending on the number of markets. Henwood
Energy Services and NewEnergy Associates offer forecasting in addition to scheduling
and settlement. Henwood is known for forecasting and settlement analysis capabilities,
while NewEnergy’s EnergyOffice supports both LSEs and retailers in scheduling
and settlement, as well as transmission congestion forecasting.

A niche player, OATI has a lion’s share of the market for the NERC, tagging
as an application service provider (ASP); OATI also offers transaction management
tools for generators.

More advanced scheduling and settlement systems link pre- and post-trade, connecting
risk management with scheduling and settlement. KWI offers scheduling and settlement
as an adjunct to KW3000 for companies that do not already have the necessary
tools. Caminus, meanwhile, identifies scheduling and settlement as a market
for its seasoned ACES product. It also has an integration platform for its popular
trading, risk, and power-management suites, including Nucleus and Altra Power.

Integrators with experience in this area are SAIC; Cap Gemini Ernst & Young;
AMS (now owned by Wipro); Sapient; IBM Business Consulting Services with its
acquisition of PwC Consulting; and Accenture. Experienced integration platforms
include TIBCO, SeeBeyond, and IBM Websphere.

Recommendations

Energy companies participating in ISO markets do not need to wait for the RTOs;
rather, smart companies will start planning now. In approaching scheduling and
settlement, they should do the following:

• Expect that the market rules will continue to change dynamically, and
negotiate software agreements accordingly. Closely examine maintenance and upgrade
policy and inherent configurability of the application; you cannot afford an
expensive upgrade every time the market rules change.

• Require vendors to use historical data to recreate financial exposure
for a past period. Because of the complexity of charges in different markets,
you need to be assured that the vendor’s packaged applications can accurately
predict your exposure.

• Do not underestimate the importance of program scheduling. Submitting
bids and schedules via a Web site can be labor-intensive. For a small player,
this is not an issue, but for larger market participants, automation is a must.

• Consider the ease of integration of applications before making your
final selection. Rather than separate applications for scheduling and tagging,
consider an application that offers both. However, if your existing tagging
application can integrate easily, you may not need to purchase tagging as part
of your settlement option.

• If and when the market rules resolve and true-up times shorten, you
will still need a means to verify RTO invoice calculations. According to one
ISO staffer, “Although we have fully tested our systems, given the complexity
of the invoicing system, there are opportunities for error.” n

Recent events in the energy marketplace and the failure of unregulated businesses
have put greater emphasis on regulated businesses. Given this backdrop, a proactive,
holistic approach to asset management is needed.

For example, regulators are implementing performance-based rate-making/regulation,
with the initial focus on cost-cutting measures. Research conducted by the META
Group indicates that 75 percent of states are developing such regulatory approaches.

As utilities separate their business units (e.g., generation, transmission,
distribution, retail), no longer are the energy delivery costs and profits overshadowed
by those factors. The groundwork has also been laid for regulatory agencies
to focus on evaluating customer service and service reliability, which is consistent
with the customer’s heightened interest in these areas.

With these considerations, asset-intensive, energy delivery companies must
embrace a comprehensive approach to asset management. This is the only way in
which the balance of cost control, performance requirements, and an appropriate
return on investment can be mutually achieved, not only in the short term, but
also for the long run.

This article explores the basic framework for developing a comprehensive asset
management approach to establishing and measuring the health and wealth of utility
assets.

In this context, health is typically described as the traditional maintenance
management, performance monitoring, replacement, and investment planning based
upon asset operating performance and maintenance cost.

Wealth takes into consideration the revenue associated with a group of assets
along with the cost associated with maintaining their health, and is used in
making enterprise investment decisions.

Top-Down Approach

Asset-intensive companies need to approach asset management with a multifaceted
framework.

To be successful, this process must start from the top down. Specifically,
asset strategy, at a minimum, must address the following:

• Making intelligent decisions regarding the capabilities of the organization
and the roles in which the utility intends to play versus outsource.
• The asset management lifecycle, from concept through retirement and renewal.
• Meeting or exceeding established thresholds for asset and network reliability.
• Meeting or exceeding the increasing demand to provide excellent customer
service.
• Strengthening the link between the asset financial decisions and the
asset physical performance, while running the company as a competitive business.
• Proactively meeting customer and load growth.

While in today’s environment the primary driver for utilities to refocus on
asset management has been cost pressure from limited capital and operations
and maintenance funds, the desired cost cuts may be achieved without achieving
the real goal of excelling at asset management. Utilities should look at this
renewed focus on asset management as an opportunity to be proactive in shaping
the regulatory regime instead of maintaining a reactive environment.

Roles and Relationships

Asset management roles and relationships for transmission and distribution
companies are evolving. Utilities are taking a hard internal look to determine
what they do well at a competitive cost; what key expertise they need to maintain;
and making the decision to outsource non-competitive, non-key expertise roles.

Figure 2 shows what roles lead to asset effectiveness versus cost efficiency.
Depending on the utility’s primary drivers for refocusing on asset management,
this should have a significant influence on which roles the utility wants to
maintain and how it will structure relationships with companies to which they
have outsourced specific roles. Figure 3 provides additional definition of responsibilities
and potential gains associated with each asset role.

Whatever the decision is regarding roles, a key requirement for successful
asset management is that timely communication of the appropriate asset data
and information occur between all involved parties. Thus, as part of the evaluation
process in developing the asset management framework, which party will be responsible
for each role and the implications with regard to systems implementation, integration
and capture/transmittal of asset data must be defined.

Asset Management Lifecycle

In continuing from the top down through the pyramid of Figure 1, understanding
the asset management processes is critical in determining how either legacy
or new enabling technology solutions must be integrated to provide seamless
data upon which to make informed asset management decisions. Utilities must
take a different approach to considering these processes. Historically, utilities
have operated in functional silos, with decisions about engineering, operations,
maintenance, and the like often made independent of fulfilling the actual business
need. For asset management, the utility needs to consider the asset management
lifecycle.

(See Larger Image)

Figure 1: Overall View to Eveloving an Asset Management Framework

Each of the functional areas must determine how they can work together for
each phase of the asset management lifecycle to develop a cohesive solution.
It’s not uncommon for five to 10 years to pass from the time a concept is proposed
to when the actual procurement takes place. For example, a utility may determine,
based on present distribution feeder voltage fluctuations and projected load
growth, that ultimately a new substation is required.

However, based on the expected costs and anticipated load growth projections,
the utility may initially install additional capacitor banks as an alternative.
In making these new asset decisions, operations should be involved in decisions
regarding the success of installing additional capacitor banks. Marketing/sales/retail
should be involved in confirming when the expected load growth will occur. Maintenance
should be involved in the ability to maintain these new assets. And engineering
should be evaluating the vendor product history and determining the procurement,
retirement, and renewal options. Thus, the processes must cut across organizational
boundaries.

Asset and Network Reliability

Both customers and regulators heavily influence established thresholds for
asset and network reliability. As stated earlier, regulators are moving to performance-based
rate-making. Customers are concerned because the company they buy their energy
from and the company that distributes that energy may likely be different, with
the emphasis on and ownership of providing reliable service becoming lost in
the mix.

Traditionally, four primary metrics have been used as a measure of asset/network
reliability and availability.

• SAIDI (System Average Interruption Duration Index) — This
is the average number of minutes in a year that the typical customer is interrupted.
It is the ratio of total service interruption minutes (excluding certain outages)
to the average number of customers.

• SAIFI (System Average Interruption Frequency Index) — This
is the average number of times per year that the typical customer is interrupted.
It is the ratio of total customers interrupted to the average number of customers.

• CAIDI (Customer Average Interruption Duration Index) — This
is the average duration of a customer interruption. It is the ratio of total
service interruption minutes (excluding certain outages) to the total number
of customers interrupted.

• ASAI (Average System Availability Index) — This is the ratio
of the number of SAIDI minutes to the total number of minutes in a year, subtracted
from 100 percent.

 

Figure 2: Major Asset Management Roles and Relationships

 

Focus on Reliability

Of these metrics, only one, SAIFI, provides an indication of reliability. The
other metrics are heavily influenced by the utility’s ability to minimize the
duration of the interruption through prompt identification and repair of the
fault. The emphasis to return or focus on reliability is in part evidenced by
regulators requiring the utilities to report on their 10 worst circuits.

Other metrics often make use of the number of span miles as the denominator
of the metric. At first glance, this may seem reasonable, but one should expect
that both the number of interruptions and outages, as well as the costs associated
with the assets, would be very strongly correlated to the number of span miles
considered in the metric. Additional thought should be given as to when span
miles should be used in a metric, and to interpretation of the results. All
that being said, there still is a lack of focus on how a customer versus a utility
measures reliability.

Figure 3: Asset Role Responsibilites Definitions and Potential Gains

Customer Service

Customer surveys are typically used to measure the extent to which customers
are satisfied with the service provided by the utility. Customer satisfaction
is not necessarily tied to the level of network reliability, and, in fact, it
can be more matched to the investments made in service delivery. A survey conducted
by EPRI subsidiary Primen found that by investing an average of $1.64 per customer
in service delivery, a utility company can achieve an 8 percent increase in
customer satisfaction, while investing $180 per customer in improving distribution
infrastructure only improves customer satisfaction by 5 percent.

This statistic, however, is not to advocate that a utility should focus its
spending on service delivery versus improving distribution infrastructure, but
to understand and strike a balance in making these investment decisions. An
overlapping relationship exists between the customers’ needs, maintaining the
required levels of physical asset reliability and availability, and the impact
that the asset lifecycle process has in each of these areas.

The utility must understand what brings value to the customers and then provide
seamless, consistent, predictable value faster and better than its competition
to earn the customers’ business in the future. Energy price and value, quality
and reliability, and customer service are major components of customer value
and are heavily influenced by the utility’s approach to asset management.

Figure 4: Asset Management Lifecycle

Strengthening the Link

Asset wealth takes into consideration combining the revenue associated with
a group of assets along with the cost associated with maintaining their health
and is used in making enterprise investment decisions. Historically, utilities
have had a wealth of information available regarding an asset’s health. The
use of this information, however, has generally been in a silo approach versus
an overall adoption of the asset management lifecycle.

The difficulty that exists in today’s environment is how to determine at what
level wealth should be attributed to assets. Several approaches exist, including
attributing wealth at the asset class level, by operating district or division,
by customer segmentation, and geographic location. Each of these approaches
has limitations. For example, for a selected portion of the network’s assets,
they will likely cross operating districts, regions, and tax districts, making
the wealth determination more difficult and the ability to manage the assets
from a lifecycle approach more complex.

Although there is no clear asset selection approach free from limitations,
asset segmentation based on the asset’s physical connectivity rather than its
geographical location is very promising. These segments represent planning areas
for the purpose of managing assets from a lifecycle approach, specifically in
the development of area investment plans.

Asset segments can also be aggregated to provide a broader picture. Tools such
as geographical information systems, commonly in place at utilities today, can
readily facilitate this asset segmentation by the assets’ physical connectivity.
To overcome some of the same limitations as described above in the various approaches
to grouping assets, a distribution feeder, for example, which crosses many boundaries,
would be mapped to only one asset segment, with the owner of that segment responsible
for the asset’s lifecycle management.

Asset segmentation allows the utility to measure the performance of each of
these segments in terms of profitability, reliability, and customer satisfaction.
The utility can also appropriate other statistics, such as load growth potential
and importance to the utility through an established priority to these segments
as well, to support decision-making involving asset investment. Additionally,
this approach eliminates some of the influence of using performance measures
that involve span miles with regard to cost and reliability.

Summary

Today’s utilities have much of the needed data available from legacy systems
to make these decisions. To be successful, they must fully define how they want
to manage assets, they must understand the roles and responsibilities they want
to outsource versus perform in house, and they must develop and follow processes
that embed the asset management lifecycle.

Following this approach, the data requirements, the systems architecture, and
the necessary systems to successfully manage the assets can be methodically
defined. ?

The casualties continue to mount in the devastated landscape of the post-Enron
world. We know now that Enron was the beginning of the end of the euphoric, anything
goes, expanding universe of energy, energy trading, and process of restructuring
of electricity and natural gas markets — particularly if the restructuring
initiative is motivated solely by a desire for unfettered competition. The parade
of the 1990s is over, and much of the policy and legal effort is now devoted to
the unpleasant cleanup.

When the investigations and litigation are complete, when the bankruptcy proceedings
grind to completion, and when the politics subside, lasting reforms will remain.
The structure of those reforms across American business in general and the energy
industry in particular are emerging.

This paper notes important developments on two major fronts in response to
the Enron denouement. These two partially parallel and ultimately intersecting
worlds are: a general observation on the reform of the corporate oversight,
accountability, and reporting rules; and key steps by the Federal Energy Regulatory
Commission to reinvigorate compliance with and enforcement of the statutes FERC
administers.

So much has changed in the world of federal regulation of the financial activities
of publicly traded companies, as well as in the federally regulated energy companies,
that entire volumes could be written on these topics alone. This paper will
touch on the highlights and point toward likely further trends, with a special
emphasis on energy players, their activities, and regulation.

New Mandate

The massive reformation under the Sarbanes-Oxley Act of 2002 of the responsibilities
of public companies, the function of boards of directors, and requirements for
auditors and corporate attorneys continues to be implemented through the Securities
and Exchange Commission. The mandate of Congress in the Sarbanes-Oxley Act has
led the SEC to issue regulations embodying numerous sweeping changes to the
American corporate scene — disclosures of deals, contractual obligations,
and contingencies that previously lived in a luxury land off the balance sheet.
Those halcyon days are over, as they are for the auditors and lawyers who created
an environment in which fantasy islands rose from the sea of misleading financial
statements.

New, more vigorous standards of professional conduct are proliferating to meet
new expectations in all aspects of their professional behavior. The pressure
is building for all corporate professionals, and the process has already claimed
high-profile victims in the maelstrom of political intrigue permeating Washington,
including an SEC chairman. If these issues are so toxic as to be capable of
forcing a respected longtime corporate lawyer out of the chairmanship, it is
certain to be treacherous to those lesser mortals who cross into the forbidden
zones that have been created by the post-Enron reforms. This new rigorous regime
is for all of corporate America.

Energy Sector

Now, intensify the scrutiny, suspicion and skepticism about the basic integrity
and transparency of a particular industry. Welcome to the problematic world
of the energy industry. Beleaguered for years by regulation that was unpredictable
except for its unpredictability, the energy industry had, like a newborn colt,
just gotten up on its legs and was taking its halting free-market steps.

Unfortunately, due to greed, confusion, disconnects between and among different
industry segments, even in the same company, far-fetched nightmare became ugly
reality. The much-ballyhooed energy trading business was deconstructed in a
matter of months. Investigations by Congress, the Department of Justice, the
SEC, FERC, the Commodities Futures Trading Commission (CFTC), the states, other
governmental entities worldwide, and other players ensued and are still going
at full force. Every paranoid, sweaty dream of the deregulation unbelievers
about what might happen if the gas and electric industries were set free from
regulation came true.

FERC Under the Microscope

The reaction from political quarters to FERC’s regulatory efforts over Enron’s
empire “before the fall” have been critical.

The General Accounting Office issued a report entitled “Energy Markets: Concerted
Actions Needed by FERC to Confront Challenges that Impede Effective Oversight.”
That report found that FERC faced key challenges in overseeing energy markets
with respect to: changing the commission’s organizational structure to improve
the effectiveness of its oversight program; defining and implementing an effective
approach to overseeing competitive energy markets; and addressing human capital
needs. In addition, the report found that new statutory authority and guidance
from Congress would enhance FERC’s ability to develop, regulate, and oversee
competitive energy markets.

The Permanent Sub-Committee on Oversight and Investigations of the Senate Government
Affairs Committee later issued a report after its investigation of the relationship
between FERC and Enron. That report, one of several oversight reports on the
Enron debacle, found that although FERC did not directly regulate Enron Corp.
(essentially a holding company for the company’s many and diverse operating
subsidiaries) as a corporation, per se, FERC had jurisdiction over many of Enron’s
energy marketing, generation, and transmission subsidiaries and activities.

Jurisdiction Entities

In response to the committee’s request, FERC identified 24 electricity marketers,
generators, or transmitters, 15 gas pipelines, and five oil pipelines that are
or were Enron subsidiaries or affiliates and that either are so-called “jurisdictional
entities” under the Federal Power Act, Natural Gas Act, or Interstate Commerce
Act or are qualified facilities that must be certified by FERC under PURPA.
In addition, Enron appeared to have several other electric affiliates subject
to FERC’s jurisdiction or certification requirements.

Not surprisingly, therefore, FERC had many contacts with Enron concerning Enron’s
FERC-regulated subsidiaries and affiliates over the 10-year period examined
by committee staff. The vast majority of these involved routine matters such
as rate filings, reporting requirements, and system operation. Enron was aggressive
about using, and seeking to use, the regulatory process to further its business
goals and to protect its economic interests in matters within FERC’s purview,
from the promotion of the deregulation of the electric and natural gas markets
to FERC’s response to the California situation. Enron intervened in dozens,
if not hundreds, of proceedings before FERC to this end.

In investigating the role of FERC, the Senate’s investigation identified four
specific areas of concern:

• Enron’s sale and repurchase of certain wind farms.
• The activities of Enron Online, theelectronic trading platform run by
the company.
• Transactions conducted between Enron and certain Enron-affiliated companies.
• The impact of Enron on the California energy price run-up of 2000.

FERC Criticized

The oversight hearing found that FERC had, in the committee staff’s view,
lacked determination to scrutinize the company’s activities. Further, FERC’s
failure to structure the agency to meet the demands of the new, market-based
system that the agency itself has championed was criticized.

The concession was whether the disclosure of any of the individual activities
would have prevented Enron’s collapse; that more proactive, aggressive action
by FERC would have limited some of the abuses that appear to have occurred,
raised questions about Enron’s trading practices and other business activities,
and exposed at least some of the cracks in Enron’s foundation earlier.

Perhaps scrutiny by FERC (or the SEC or others) would have also jolted the
Enron board of directors and Enron itself into acting to change direction. At
a minimum, investors, analysts, and other regulators may have looked more closely
at Enron. As could be expected, FERC has begun to take major steps to prevent
Enron-esque disasters in the future.

FERC Probe

In response to allegations that Enron may have used its market position to
distort electric and natural gas markets in the West, the commission initiated
a fact-finding investigation into whether any entity, including any affiliate
or subsidiary of Enron Corp., had manipulated electric energy or natural gas
prices in the West since the start of 2000. In conducting this investigation,
FERC staff is coordinating closely with the Department of Justice, the SEC,
the CFTC, and the Department of Labor.

During August 2002, FERC staff released an initial report of its investigation.
The report concludes that published indices of electricity and natural gas prices
in or near California during the recent crisis may not be sufficiently reliable
to be used in setting refunds for wholesale power buyers in California. Based
on its staff finding, FERC requested comments on whether it should change the
method for determining the cost of natural gas in calculating the refunds for
power sales in California from October 2000 to June 2001, and if so, what method
should be used.

Investigation continues

FERC pursued a comprehensive investigation of a variety of factors and behaviors
that may have influenced electric and natural gas prices in the West during
2000-2001. The final report will include:

• An explanation of Enron Online operations and the role they played in
the energy markets.
• An analysis of sales data collected from information requests. FERC staff
will explain the results of the statistical analysis of such data, including
findings of how, and to what extent, forward prices directly correlate with
spot energy prices.
• An analysis of wash trades in electricity and natural gas markets in
the West.
• A discussion of FERC staff’s findings on allegations that Williams Co.
had attempted to manipulate natural gas markets in the West.
• An analysis of the relationship between physical and financial natural
gas and electric products.
• Recommended standards and protocols for how to identify and deal with
possible physical withholding.
• Further analysis of the extent to which Enron’s trading strategies had
an effect on other products, such as long-term physical and financial contracts.

General Reforms at FERC

In parallel efforts, FERC approved a final rule directing public utilities,
licensees, natural gas companies, and oil pipelines to report changes in fair
value of certain investment securities, derivatives, and hedging activities.
The treatment is consistent with the reporting standards of the SEC and the
Financial Accounting Standards Board (FASB) and is consistent with the rulemaking
proposed by FERC. The commission severed from the final rule its inquiry whether
independent and affiliated marketers and power producers should be available
for waivers of certain accounting rules on a case-by-case basis.

The final rule imposes more comprehensive reporting requirements that are intended
to enhance the transparency of financial information and facilitate FERC’s knowledge
of the nature and extent to which regulated companies use derivatives and hedging
activities and how those transactions affected utilities’ reported financial
condition.

In recent years, the use of fair value measurements, which assist investors,
creditors, and other users of financial data in making investment and credit
decisions, have grown in importance. As regulated utility industries restructure,
fair value will increasingly provide a relevant measure of economic effects
for a growing number of transactions. The final rule is intended primarily to
address reporting consistency needs, while entities such as the SEC and FASB
search for better ways to estimate the current value of future instruments.

Another step taken is a proposal by FERC to change its Uniform System of Accounts
to establish more transparent, complete, and consistent reporting of liabilities
associated with the retirement of tangible long-lived assets and related capital
costs. An asset retirement obligation is a legal obligation associated with
the retirement or decommissioning of a tangible long-lived asset that an entity
is required to settle by virtue of a law, statute, ordinance, or contractual
obligation. Current FERC regulations do not provide specific direction for the
recording of these costs, which commonly include removing and/or dismantling
the asset. The proposed changes would be consistent with current SEC reporting
requirements.

A New Office

FERC also created a new Office of Market Oversight and Investigations (OMOI)
reporting directly to the commissioners. The OMOI encompasses two units that
function independently but work closely together. The Market Oversight and Assessment
unit reviews developments in the market on a real-time and longer-term basis
and spots irregularities. As problems arise and are identified, an Investigations
and Enforcement unit will bring swift, decisive, and effective enforcement.
The office will hopefully serve as an early warning system to alert FERC when
market problems develop.

The office is working with a variety of entities, including other federal,
state, and provincial regulatory agencies, state consumer advocates, industry
participants, academic institutions and think tanks, financial institutions
(such as ratings agencies), and market monitoring units (MMUs) at regional transmission
organizations and independent system operators, designed to let them know that
FERC is developing a market oversight capability. The OMOI has more than 100
employees budgeted and has attracted sophisticated, dedicated players. Its impact
is already being felt in the regulated community.

Outside FERC

FERC is building on the relationships established over several years of quarterly
meetings with the Department of Justice and the Federal Trade Commission. FERC
and CFTC staff have jointly deposed or interviewed more than 100 individuals
in the Western market investigation. The two agencies have also jointly developed
and shared discovery responses each has gathered from its respective regulated
entities, a major jurisdictional leap.

FERC has entered into information-sharing agreements with Justice, the SEC,
and the CFTC with respect to the investigation, and these agencies are also
coordinated under the Deputy Attorney General for the broader investigatory
efforts of the president’s Corporate Fraud Task Force. FERC legal staff has
coordinated with the CFTC regarding each agency’s respective jurisdiction over
energy market activities. These are important steps to reestablish meaningful
oversight of immensely complex businesses.

Hopefully, FERC’s initiatives will lead to a restoration of faith in the industry
by regulators, investors, and participants. It is a beginning, filled with promise
and peril for all.

Within the energy industry, the merchant sector has gone from one of the most
promising areas to one of the most troubled. Indeed, many have questioned whether
portions of the merchant business can recover from the damage of the past two
years.

In this paper, we are focused on six persistent questions on the future of
energy marketing and trading:

1. What happened? Why did the merchant business model implode?
2. Is the merchant business model still valid?
3. Who will survive?
4. Is there a market to serve?
5. Can the market recover?
6. What are the signs of recovery?

What Happened?

The merchant model has had a fundamental shift with the exit of Enron, which
explains much of the current credit predicament. For all its faults, Enron was
the great liquidity provider and enabler in the power trading markets because
it was on the other side of most trades. Enron held a triple-B credit rating
and, as such, other merchants with similar credit profiles could trade with
Enron without posting onerous amounts of LOCs (letters of credit) or collateral.

However, in a post-Enron world, the liquidity function was transferred to the
banks and exchanges, which have far superior balance sheets and significantly
greater margin requirements. As such, power trading, with its intense volatility
and nascent liquidity, has become a function for big balance sheets. This explains
Aquila’s and El Paso’s decision to close shop or significantly limit their activity
in the power markets. We expect more exits to follow.

Trading up to higher credits and stiffer margin requirements lasted for a short
time, but simultaneously the credit rating agencies (in reaction to the Enron
meltdown) reduced the credit ratings of these companies thus deteriorating their
counterparty-credit profiles. So while liquidity requirements were rising, counterparty-credit
profiles were deteriorating, and the merchants got caught in the middle.

The result is that wholesale power markets have dried up, significantly impairing
merchant economics and dislocating the business model.

Is the Business Model Valid?

The merchant business model can be distilled down to two components: the physical
market and the financial market.

Due to the previously described events that led to the current credit crunch
for most merchants, we expect the model to remain valid but become increasingly
segmented with the merchants focusing on the physical model while financial
intermediaries increase their presence in the financial segment.

The physical market is the foundation of the merchant model and centers around
the logistics and delivery requirements of energy commodities. The physical
model includes procurement of natural gas for eventual delivery or for power
plant fuel, natural gas storage and transportation, electricity generation and
transmission, and multi-commodity and regional arbitrage.

The physical markets will remain an option for all financially feasible merchants;
however, the most successful physical players will incorporate a dynamic energy
infrastructure with regional strength. In other words, in order to maintain
the low-cost/higher-return position in this razor-thin margin business, successful
physical players will need the following:

• Dominant power generation market share in focus regions similar to other
low-margin businesses such as midstream services, whose participants typically
follow an “airline hub and spoke” strategy.

• The ability to source gas at the lowest cost, which necessitates a sophisticated
gas marketing and trading presence (we believe gas trading will remain available
to most merchants given the gas markets’ deep and liquid markets and resulting
reduced liquidity requirements). This is particularly important since fuel is
roughly 85 percent of the cost of running a plant. We believe a preferred profile
entails some ownership of natural gas reserves in combination with contractual
rights in order to offset sourcing/margin risk and being long power.

• A preferred profile also includes an energy sink (i.e., a customer base)
to help offset the natural long position in power. While commercial and industrial
clients are preferable due to the margin associated with structured transactions,
the churn rate is very high relative to residential customers. Furthermore,
regulated customers offer higher margin with lower turnover and commodity risk.
Unregulated retail customer services have not yet panned out as a desirable
business, given that customers are not easily lured away from the incumbent
utility — they also carry low margins and a meaningfully higher commodity
price risk.

• Logistical sophistication, including significant positions in transmission,
pipeline, and gas storage capacity to reach the lowest-cost fuel and highest-profit
end markets, as well as maintaining multi-regional and multi-fuel positions
in order to capture arbitrage opportunities.

• High credit standings as a lower cost of capital is key to returns in a low-margin
business and will also provide preference in capacity contract negotiations.

We believe that the merchant players, marred with excessive debt and limited
access to the capital markets, will have a difficult time surviving in their
current forms and will not be long-term winners in the new market environment.

The financial model is necessary in an open and competitive market. The financial
model includes providing liquidity (market making services), speculative trading
(a.k.a. proprietary trading), structured products (i.e., derivatives), and risk
management services (transferring price risk from large energy consumers to
their balance sheet and then ultimately to the market).

Financial market participants provide liquidity and depth to trading markets,
which allows physical players and large energy consumers to lay off risk through
hedges. Without market liquidity, physical players are forced to seek each other
out on a bilateral contract basis, which has proven extremely inefficient. Like
any other market, middlemen match buyers and sellers, which also supplies reliable
price signals on which economic decisions can be founded.

While we believe bilateral contracts will grow in application as a result of
financiers’ requirements and the recent breakdown in financial markets, our
channel checks overwhelmingly confirm the desire and need for liquid financial
markets in order to manage the significant risk associated with electricity
price volatility. We expect banks, brokerages, hedge funds, and other large
commodity houses to increase their role in the financial power markets.

More important to our thesis than power generation margins has been the outlook
for risk management demand growth. Energy marketing and trading starts with
marketing where long-term contracts and relationships are formed.

Trading for merchants, in our view, is a consequence of the origination business.
Because by definition risk management transfers consumers’ price risk to the
providers’ books, it is now a function for financial intermediaries such as
banks, which have specialized in similar services in other sectors. Only the
merchants with the strongest balance sheets will have the ability to participate
in this segment, which we believe offers the greatest growth and profit potential.
But, as we describe below, this is an area ripe for collaboration among the
financial and physical players.

Who Will Survive?

We continue to believe the merchant model works, albeit the number of companies
with the ability to participate in each step of the value chain has been significantly
reduced. So what does the future hold?

As mentioned, we expect financial institutions to fill the financial trading
void and, to this end, have been stepping up efforts (confirmed by UBS’s purchase
of Enron’s platform). Morgan-Stanley Dean Witter and other brokerages are already
forces in the market; in fact, Goldman Sachs already announced that it is re-upping
its power trading efforts. Foreign energy firms are increasing their presence
in the U.S. wholesale markets demonstrated by RWE’s opening of its trading floor.
Hedge funds such as Citadel and D.E. Shaw are said to have growing interest,
and commodity firms like Cargill and AIG are also mentioned as studying their
options. Domestic utilities and some of the major integrated oil companies have
also expressed interest in building on their participation.

We also see the logic behind joint ventures/partnerships/collaboration among
merchants and financial institutions. It is possible for a model to develop
similar to loan or mortgage origination wherein risk-management deals are underwritten
by the merchants and partner banks, then syndicated to other players, likely
in time tranches.

Merchants had rejected these types of arrangements in the past, wanting to
keep the spoils to themselves, but in today’s dismal reality this structure
offers a lifeline. Alternatively, it is of interest to financial institutions
as they typically lack the physical delivery capability. Moreover, merchants
bring to the table the customer relationships that are invaluable to origination.
The first such partnership was announced by CMS with Capstone Global Energy
and Harvard Management and is, in essence, a credit-support agreement enabling
CMS to pursue longer-term risk-management deals on which the partnership would
have to sign-off.

It is impossible for us to gauge the viability or economics of these structures
from the merchants’ standpoint, but we would assume merchants would be less
profitable than in the past as the financials have the upper hand and will likely
extract more than their pound of flesh. As such, it remains to be seen if the
merchants’ current capital structure can support a JV partnership. Nonetheless,
a JV partnership arrangement would likely save the day and significantly improve
the outlook for some companies as it would reduce the onerous collateral requirements
and provide additional flexibility to trade.

Is There a Market to Serve?

We start from the premise that the wholesale energy markets will survive and
grow from current levels going forward. Founding this belief is the Federal
Energy Regulatory Commission (FERC) accelerating efforts to pry open the wholesale
power arena with the goal of promoting open and competitive markets. FERC’s
ambitions were recently demonstrated by the issuance of its GIGA NOPR, which
is an effort to lay out the rules for an open wholesale power market.

To date, the process of opening power markets unleashed the underlying price
volatility inherent in electricity. While not always the case as demonstrated
in California, typically the end users (large wholesale customers) find themselves
subject to this volatility and, as such, power-risk management demand had begun
to flourish prior to the recent liquidity crisis.

Over the past several years, many utilities have been mandated or have elected
to divest their power generation assets, leaving many naked of power generation.
Without these assets, utilities have created a short position in the most volatile
commodity ever traded, which does not square with their inherently risk-averse
culture.

Furthermore, demand has outstripped supply for many co-ops and munis, and large
commercial and industrial customers have become more aggressive in seeking stable
energy supply deals. This is a huge new market for companies that specialize
in risk-management services.

Unlike many other commodities, power and gas pricing is highly correlated to
weather, which is difficult to predict. Weather has a particularly strong impact
on the price of power because the commodity cannot be stored. In addition, most
power plants are not designed to increase production rapidly to meet sudden
demand spikes.

Weather derivatives, a form of weather insurance for large energy consumers,
remains in a nascent stage. Consumers are offered price visibility within set
parameters for a given period of time. Risk does not disappear; rather, suppliers
transfer consumers’ pricing risk onto their books, which is then offset through
a series of “dirty hedges,” or hedging using highly correlated commodities.
To date, weather derivatives have proven less economic to consumers given their
relatively high cost compared to more standard risk-management methods. Moreover,
the large suppliers of weather derivatives were Enron and Aquila, which have
left the business.

However, weather derivatives could regain some momentum and become another
arrow in risk managers’ quivers if pricing is reduced, which should come with
scale.

The unpredictable nature of weather, combined with the inability to tightly
follow load, should sustain a relatively high level of volatility for the foreseeable
future, in our opinion, which should lead to steady risk-management origination
demand. Unfortunately, supply of this service dried up as providers’ credit
quality dwindled and the trading market evaporated.

We have confirmed through our contacts that demand is currently cocooned and
waiting for current events in the merchant arena to play out. As such, we expect
suppliers to meet the demand attracted by the high margins and profit potential.
The projected growing volume of origination deals implies healthy trading volume
growth given the trading markets’ multiplier effect (velocity).

Can the Market Recover?

While we start with the assumption that the market will redevelop and grow
from current levels, we have dramatically reduced our expectations for the potential
growth of the market and its ultimate size.

Previously, we had estimated the market to grow to $1 trillion-plus by 2005
from $285 billion in 2001 (includes nonregulated generation, gas and power marketing,
and trading). We now see the market growing to about $420 billion in 2007 (see
Figure 1). The primary factor in deflating our projections is an assumed slowdown
in power volume velocity, i.e., the financial-to-physical ratio. We had assumed
power velocity could reach the average for natural gas, which is roughly 10x
and, in fact, it was above trend to meet these expectations.

(See Larger Image)

Figure 1: Wholesale Industry Model                                                                  Source:
Company Reports and Banc of America Securities, LLC

However, given the upheaval in the wholesale power market, we now believe there
will be more reliance on bilateral contracts (direct from plant owner to end
user) and shorter-term deals of one to three years compared to the four to eight
years prior to the market downturn. Given that risk grows in the outer years,
there should be less risk to lay off in the markets. As such, while we see a
return to more liquid power markets, we expect depth only in the near-term market
of one to perhaps three years, thus reducing velocity from previous expectations.
The question remains: When will the recovery begin?

What Are the Signs of Recovery?

Volume growth is an important leading indicator of a recovery, but who or what
will prime the market? Key events we are watching that would imply a recovery
in the wholesale power markets include the following:

• First Mover — We are watching to see which companies take
a leadership role in providing liquidity to the market and what platform is
preferred (i.e., NYMEX, Intercontinental Exchange, or EnronOnline now resident
at UBS). First signs here are Goldman’s efforts to enhance its power trading
efforts.

• JV Announcements — A very strong endorsement of the viability
of this market would be a joint venture announcement from a financial player
with a merchant. The ultimate combination we can imagine would be a name brand
“smart money” player such as Goldman or Berkshire combining their efforts, or
backing the efforts of a top merchant such as Dynegy.

• Smart Money Asset Acquisitions — Having credible acquirers
stepping in would help signal a bottom, in our judgment. While Berkshire Hathaway’s
purchases of pipelines are encouraging, they are “no brainers” in our view.
The real test is, when do parties step up to purchase trading books, tolling
deals, and merchant plants?

• Overhang Resolutions — The largest overhangs facing the
sector and impeding new investment and new entrants, in our view, are the investigative
risks and uncertainties surrounding California. We believe that the resolution
of these issues would help reduce the sector’s taint and encourage new investment.

• New Entrants — Looking for palpable signs of commitments
from those companies said to be building new power-trading operations such as
RWE and Citadel.

• Deeper and Longer Markets — While we are watching for an
increase in volume, we are also monitoring volume in longer-term markets (two
to three years and beyond), which would signify a return of risk-management
origination.

Bottom Line

In conclusion, we believe the market will recover and grow from current levels,
albeit at a more measured pace. The business model remains intact, although
few companies will engage in the full-value chain. Those that are capable, or
desire to participate, are presented with a unique opportunity to expand their
presence on a lower cost basis.

A significant impetus to the recovery of the merchant business model would
be the reopening of the capital markets for the entities in the merchant space.
Over the past year, there has been a significant deterioration in both the market
capitalization and credit spreads of the merchant players.

The type, scope, and frequency of both internal and external risks facing the
energy and utility industry have increased significantly. To meet business objectives,
business leaders must now address new and different forms of business risks. Some
utilities have been able to successfully identify and manage risks during these
turbulent times, but unforeseen events and ever-changing market conditions fundamentally
altered other companies.

Many utilities today face difficulty managing their portfolio of regulated
and unregulated businesses. Traditional risks, within the core-regulated business,
typically include weather, commodity, and supply risks. These risks have for
the most part been successfully mitigated through regulatory devices and managed
through strong internal programs.

The redefined regulatory environment has created some of the new risk factors
that have emerged over the past several years. Retail competition created new
business opportunities to which some utilities funneled significant funding.
With these opportunities came additional risks for market participants that
included customer loyalty, pricing pressures, and regulatory uncertainty. With
lean budgets, low margins, and high expectations, the required risk management
and detailed mitigation plans were often neglected or omitted.

Recent events have compounded risks in the energy and utility industry and
highlighted the vulnerability of the industry’s employees and physical assets
to threats and terrorism. In addition, under the Sarbanes-Oxley Act of 2002,
corporations face harsher civil and criminal penalties if they misrepresent
or incorrectly state their financial earnings. Regulators are pressing companies
for better and more transparent risk reporting and for more formal, integrated,
and comprehensive risk plans.

The message to management and board of directors of both public and private
companies is clear: The bar has been raised and earnings surprises are not acceptable.
It is the responsibility of the board and the executive management team to ensure
that rigorous internal control and risk-management policies, practices, and
procedures are in place and are continuously updated and modified.

In this new and more volatile marketplace, the formulation of a comprehensive
enterprise-wide risk-management strategy (ERM) is a key to business success
and stability. Enterprise-wide risk management is the means to apply active
risk management to all of the risks facing an organization. Many companies understand
this new imperative; a recent survey conducted by The Economist Intelligence
Unit and MMC Enterprise Risk found that 41 percent of companies have some form
of ERM. The survey also found that companies using ERM are more confident in
their ability to manage risk.

Business Objectives

Risk is the level of exposure, both known and unknown, to market uncertainties
that the organization must understand, identify, and effectively manage as it
executes its strategies to successfully achieve its business objectives. In
order for most energy companies to meet their goals and objectives, they must
face new challenges and take greater risks. However, if the risk-management
process is flawed, the company could suffer in the competitive marketplace.

Traditionally, companies adapted a silo approach to risk management. Responsibility
for managing various types of risk was assigned to the business or functional
unit with the greatest exposure. Business risk was assigned to the operating
units; insurable or transferable risk to the corporate risk-management department;
financial risks (market, interest rate, and so on) to treasury; and compliance
risk to legal. In traditional approaches, companies focused primarily on easily
measurable risks. Undefined or ambiguous risks, such as strategic and operational
risks, were often not coordinated or were overlooked. The risk-management strategy
for the individual risk was usually tacked onto existing business processes
without a uniform approach or a common risk language.

Enterprise-wide risk management is a disciplined and integrated approach that
supports the alignment of strategy, process, people, and technology. It allows
corporations to identify, prioritize, and effectively manage their critical
risks.

Enterprise-wide risk management allows the company to identify the risks they
must: transfer through insurance or hedging programs; accept as is; reduce through
rigorous management practices; or simply reject by eliminating the process,
a product, or a geographical zone. Companies can effectively utilize risk as
a competitive weapon and not view it as a threat.

The cornerstone of this process is the creation of an infrastructure that is
the foundation for future work, including:

• Creation of corporate governance and oversight boards
• Explicit description of the company’s risk culture and risk propensity
• Policies and procedures to steer the process
• Common risk language to facilitate management
• Tools, techniques, and methodology to support ERM

The process can be individually tailored to each organization, but will contain
the basic steps necessary to identify, analyze, mitigate, and monitor the risks.
It is used to assess risks and can be applied to the organization as a whole,
to individual business areas, to processes, or to any other initiative where
a focus on the existing or potential critical risks is needed. As this process
is continuously executed within various parts of an organization, the resulting
information and data must be shared and used to continually improve not only
the process, but the effectiveness of the company in managing its risks.

For each key risk in the company, there is a process that continuously identifies,
prioritizes, and manages risk. The first step is for risk owners to identify,
assess, and prioritize the business risks facing the company. After the risks
have been sorted, management analyzes those risks that pose significant threats
or opportunities to the company and then creates strategies to best exploit
or avoid these risks. The strategies are based upon the company’s unique competencies
to manage certain kinds of risk.

Once the strategy has been developed, the company implements processes to measure
performance against the plan, monitors activities against policy, and reports
on the results to executive management and the board. The final piece in the
process is aggregation of the results across the major risk categories and the
integration into the decision-making process.

A critical part of all of these steps is the alignment of critical risks with
the organization’s strategies, goals, and objectives. This allows the organization
to understand, prioritize, and reach consensus on strategic objectives for either
the company as a whole or a specific business process within the company. This
will ensure that the risk-assessment process will be focused on those critical
risks that have the potential to either directly or indirectly impact the company’s
ability to achieve those objectives or to adversely affect the company’s ability
to take advantage of new opportunities.

The final component includes the integration of the results with other management
processes, such as strategic planning, major capital projects, mergers and acquisitions,
and new product development. A common failure of many efforts is the inability
to integrate ERM into the existing management processes. In the absence of such
integration, it can be perceived as a standalone practice without relevance
to company’s critical processes.

Figure 1: Enterprise-wide Risk Management Framework

As risks continue to be identified and assessed across the organization, the
value to management is the ability to review and analyze consolidated risk data
in order to gain a company-wide perspective on specific risk issues or groups
of risks. Risk mitigation strategies can also be reviewed for gaps, duplication
of effort, or for best practices.

Risk output can be utilized as a key driver for strategic planning, identifying
possible initiatives needed to mitigate risks that can impair management’s ability
to meet key objectives. The risk-management process and metrics can also be
integrated with existing quality or process-improvement processes to identify
possible process-improvement projects or to create a more robust quality process.

However, ERM is more than a process for avoiding unfavorable outcomes; it is
anticipatory and proactive. It provides a process and a prospective to actively
support the realization of the company’s strategic objectives. It is not an
obstacle to taking risk. On the contrary, it allows companies to assume additional
risks. After implementing an ERM approach, management fully understands all
critical risks and how they can be proactively managed. It provides them with
tools and techniques to balance realistically the risk/return trade-offs and
to seize quickly the market opportunities.

A common misconception is that it transfers the responsibility for risk from
the line managers to a centralized, bureaucratic unit. The opposite is true.
A universal principle is that risk must be managed by the business unit that
incurs it. A properly functioning system ensures that the line managers understand
their risk management responsibilities, are given the tools to manage the risk
effectively, and are compensated based upon the success of their efforts.

An effective program should have three long-term objectives:

• Optimize the costs and efficiencies of risk management programs. The
new program should eliminate unnecessary controls, consolidate mitigation programs
across all functions, and focus the risk transfer and financing activities.

• Improve business performance. The new program should better align a company’s
risk programs with strategic objectives, provide more accurate measurement and
monitoring techniques, and reduce the volatility of outcomes.

• Establish a sustainable competitive advantage. It would give managers
the tools and processes to identify favorable risk-taking opportunities and
to quickly pursue them.

Organizational Structure

The board and senior management must actively and publicly support the program.
Without the guidance and devotion of upper management, the process will undoubtedly
fail. In addition, the process must be integrated into every aspect of an organization’s
business. If it occurs only within certain departments, the efforts could become
siloed, gaps could occur, there could be a breakdown in the approach, and the
company would not realize the benefits.

To achieve effective results, there needs to be an organized structure allowing
for open communication and discussion, cogent analysis and timely reporting,
and resolute decision-making. Each participant must have an unambiguous and
precise understanding of management responsibilities. Some of the key responsibilities
are:

• The Board of Directors oversees the ERM process. Directors approve
the policies and procedures and the company’s risk tolerances and overall risk
strategy. In the new Sarbanes-Oxley world, a critical role will be to provide
more hands-on oversight to management.

• Executive Management defines the risk priorities; establishes the policies
and procedures and risk-measurement systems; and ensures the alignment of business
planning, risk strategies, and policies.

• The Risk Management Committee should define the roles of those involved.
The committee should establish ways to measure the success of the process. Once
the process is functioning, a key role of the committee should be to collectively
make decisions to manage, mitigate, accept, or transfer the critical risks.

• Risk Owners: Business line managers identify the risk within their
practices and assist executive management in risk prioritization and measurement.

The chief risk officer owns the process and is responsible for overseeing its
day-to-day operation. This officer is vital to the success of the solution because
he should be fully devoted to ensuring the alignment of the process with the
company’s business strategies and objectives. The officer should be responsible
for developing communication and training programs; implementing a common risk
language; designing policies for the plan’s operations; developing management
reports and performance measures; and implementing supporting change programs
and technology support. This chief risk officer:

• Doesn’t directly own responsibility for managing specific risks (other
than the risk he is presently assigned), but operates in a consultative and
collaborative manner.

• Works with others to understand, identify, assess, and improve the
ERM.

• Supports the board, executive committee, and key operating managers
responsible for managing and monitoring risks.

• Prepares consolidated business risk reports (i.e., collects, aggregates,
summarizes, and assesses data regarding risk exposures and performance).

Plan Benefits

As a result of implementing an ERM program, senior management can expect the
following benefits:

• Improved Risk Assessment. It will provide an organization with a means
to understand, identify, and prioritize risks. Through risk mapping, management
will have better knowledge of its critical risks and their potential impact
on the company.

• Increased Risk Awareness. Because associates will have common language
for describing risk and its potential effects, the company will be able to address
uncertainties in a timely fashion before challenges, such as class action lawsuits,
explode and disrupt business.

• Reduced Number of Risk Incidents. An integrated ERM process will reduce
the number of risk incidents because management will be better equipped to handle
emerging challenges.

• Improvement in Risk Measures. Because an ERM process requires more
rigorous risk management, management will have more quantifiable measures of
risk exposures. This will result in better pricing and better capital allocation
decisions.

• Increased Competitive Advantage. Because a company with an ERM will
be more aware of its risks and opportunities, it will maintain a competitive
edge. It will be better equipped to handle challenges in a changing environment.

It is a fundamental tenet of economics that life in a competitive marketplace
comes with both risks and rewards. Partial deregulation of the utility industries
has proven no exception. Utilities are now facing, in some cases for the first
time, the reality that bad things sometimes happen even to good companies.

In particular, utilities operating in competitive energy markets have found
themselves vulnerable to the possibility of purchasing commodities at higher
prices than they are allowed to pass on to consumers, as the California energy
crisis dramatically illustrated.

When a utility finds itself in a bad situation, where can it turn for help?
One important option is Chapter 11 protection under the United States Bankruptcy
Code. Although bankruptcy is always risky, a Chapter 11 reorganization can,
and often does, bring troubled companies back from the brink of extinction.

Chapter 11, however, is not a panacea for every ill. Some situations, including
some commonly encountered by struggling utility companies, are not easily remedied
even with the strong medicine that reorganization can provide.

Chapter 11 provides a process whereby a business may attempt to reorganize
itself by restructuring its debt, business, and assets or by liquidating its
assets in an orderly fashion. It also provides debtors with powerful tools to
cure the underlying causes of its financial problems.

Of course, these benefits come with certain drawbacks, even apart from the
stigma that bankruptcy bears. For instance, Chapter 11 fundamentally changes
the dynamics of operating a company.

Public Process

Bankruptcy is a very public process. It can be very distressing for a company’s
officers to know that a small army of creditors, attorneys, and other interested
parties will publicly debate the company’s past decisions, present proposed
actions and future viability.

Even more disturbing is the realization that the company’s future is almost
entirely dependent on the approval of its creditors. In fact, a company that
has filed for Chapter 11 protection is normally operated by its officers as
a “debtor-in-possession,” which has the primary duty not of maximizing profits
for shareholders, but of maximizing the company’s assets for the benefit of
its creditors — and only then for the benefit of its shareholders if any
value remains.

As an additional challenge to this often-daunting process, industries that
operate under public scrutiny, most notably the utility industries, may find
their attempts to take full advantage of the benefits of Chapter 11 frustrated
by the actions of regulators, state legislatures, and other public actors. On
the other hand, bankruptcy can provide a fresh forum to work out a utility’s
tensions with the public actors who may have become intractable in traditional
regulatory environments.

With all of this in mind, it is useful to review the major lessons learned
from several of the leading utility bankruptcies of the last few years. Recent
utility bankruptcies provide a valuable backdrop against which to evaluate bankruptcy’s
usefulness in new situations. Of course, bankruptcy (like most forms of litigation)
can be unpredictable. As in the stock market, past performance does not necessarily
predict future results. Nonetheless, the questions and answers below provide
utility companies with valuable insight into life after death.

Will state and federal regulatory bodies be allowed to intervene in the
bankruptcy proceeding?
Generally, bankruptcy courts have allowed state public utility commissions
or similar regulatory bodies to participate in utility bankruptcy proceedings.
This means that regulatory agencies will generally be allowed to be heard on
issues that arise during the bankruptcy, as would any other party in interest.

They may even propose a plan of reorganization, as the California Public Utilities
Commission (CPUC) has in the Pacific Gas and Electric (PG&E) bankruptcy, if
the court in its discretion allows. The regulators will generally not, however,
be allowed to vote on a plan of reorganization since they usually are not creditors.

In addition to PG&E, state agencies have been granted party in interest status
in In re Public Service Company of New Hampshire (PSNH), In re Cajun Electric
Power Cooperative Inc. (Cajun), and In re Columbia Gas Systems, Inc (Columbia).

The rationale for including the regulatory entities in the proceedings is well-summarized
by the bankruptcy court in PSNH, which stated that “rather than burdening the
reorganization process of a regulated electric utility, the granting of such
status and rights to the State of New Hampshire should expedite the progress
of this reorganization process.”

Thus, it is very likely that interested regulatory bodies will be heard in
utility bankruptcy cases. By contrast, a utility’s ratepayers themselves will
likely not be allowed to participate directly in the bankruptcy proceedings.
For example, the bankruptcy court overseeing the PG&E bankruptcy ruled early
in that proceeding that adequate representation of creditors did not require
the formation of a ratepayer committee. The court noted that “ratepayers have
other means and other fora to protect their interests,” namely the state regulators.

Can a regulatory body change rates during the pendency of bankruptcy?
Regulators who have power to set utility rates can be expected to continue
“normal rate-making activities” involving the utility, even after the utility
has filed for Chapter 11 protection. The bankruptcy “automatic stay” that generally
stays all actions against a debtor to recover on pre-petition financial obligations
does not generally apply to regulatory rate-making actions. Thus, filing for
bankruptcy most likely does not prevent a regulator from increasing or decreasing
the debtor utility’s rates based on the effects of normal external forces.

On the other hand, bankruptcy courts have been known to enjoin regulators as
in Cajun Electric, where rate cases were seen as oppressive and disruptive to
the reorganization. However, recent United States Supreme Court opinions, which
have expanded traditional notions of state sovereign immunity under the 11th
Amendment, suggest that such injunctions, unless very carefully crafted, may
be beyond the power of the federal courts.

Who will make daily business decisions during the pendency of the bankruptcy?
The Bankruptcy Code generally allows a company operating under Chapter
11 to make so-called “ordinary course of business” operational decisions without
court approval.

In contrast, decisions not in the ordinary course of business (such as the
sale of major assets, re-financing and substantial changes in operations) cannot
be taken without court approval unless no party in interest objects to the proposed
action.

Will regulatory approval be required for the company to exercise powers
granted under the bankruptcy code, such as rejecting contracts?
The Bankruptcy Code grants significant powers to debtor companies that
have filed for protection under Chapter 11 of the Bankruptcy Code. These powers
include the power to avoid and recover “preferential” or “fraudulent” transfers,
as well as the power to assume or reject executory contracts entered into before
bankruptcy. These powers allow companies in Chapter 11 to revisit previous decisions,
effectively allowing them a second chance to make certain critical decisions.
Before exercising these powers bankruptcy court approval is required. But regulatory
approval is not normally required before exercising rights arising under the
Bankruptcy Code.

This issue arose during the course of the Cajun proceedings. An open administrative
docket was sought by the state public service commission to consider whether
Cajun had prudently exercised its contract rejection right, one of the Company’s
core bankruptcy powers, in refusing, for the time being, to reject Cajun’s fuel
supply and fuel transportation contracts. In response, the bankruptcy court
ruled that the commission was enjoined from making such an inquiry. The approval
of the bankruptcy court would be required before the utility could exercise
such a right; however, the approval of the regulatory agency, to its consternation,
would not be required.

Will regulatory approval be required to confirm a plan of reorganization?
Confirmation and consummation of a plan of reorganization are the principal
objectives of a Chapter 11 reorganization case. A plan of reorganization restructures
the company and sets forth the means for satisfying claims against the company.

Confirmation of a plan of reorganization by the bankruptcy court makes the
plan binding, so far as possible, on the world. A requirement of regulatory
approval of part of the plan gives substantial power over the debtor utility’s
future to a regulatory agency.

Here the law differentiates between decisions regarding rate-making itself
and decisions regarding the restructuring of the utility under Chapter 11. The
law requires that any rate changes proposed in a plan of reorganization be approved
by the regulator before they can be implemented.

On the other hand, the law and court decisions suggest that, even though regulatory
agencies will be allowed to participate and be heard in the bankruptcy process,
their authority to approve the restructuring (aside from rate changes) proposed
in a plan is severely limited.

It appears that core bankruptcy restructuring actions (such as transfers of
assets, merger, disaggregation of component entities, and the like), may be
approved by the bankruptcy court irrespective of non-bankruptcy law. At least
this is the current teaching from PG&E. (Nonetheless, PG&E has agreed to comply
with federal, but not state, regulatory approval requirements.)

In December 2001, PG&E presented a plan of reorganization that would disaggregate
the current company into three limited liability companies pursuing four lines
of business: retail gas and electric distribution, electric transmission, interstate
gas transmission, and electric generation. State law prohibited key aspects
of this disaggregation and required the approval of the CPUC prior to any sale,
lease, or spin-off of any of the company’s utility facilities. Based on these
state law requirements, CPUC objected to the proposed reorganization.

In early 2002, the bankruptcy court overseeing the PG&E case issued a decision
rejecting PG&E’s claim that federal bankruptcy law preempts non-bankruptcy laws
otherwise applicable to the proposed restructuring transactions. This decision
was reversed by an order of U.S. District Court for the Northern District of
California, which held:

“The preemption issues raised by reorganization are particularly acute
in the case of a public utility in bankruptcy, as perhaps no other debtor
is subject to as much state regulation as the public utility. But the removal
of the statutory right of approval by state commissions of the restructuring
of public utilities by the 1978 Bankruptcy Reform Act is powerful evidence
that Congress concluded that public utilities should no longer be subject
to the costs, delays and uncertainty accompanying such a requirement.

“The bankruptcy code at one time permitted state regulatory commissions
to wield considerable power over the reorganization of public utilities. But
now — with the exception of the right to approve rate changes —
it does not. Non-bankruptcy laws otherwise applicable to the ‘restructuring
transactions necessary to an effective and feasible reorganization’ are expressly
preempted by the bankruptcy code.”

After the District Court issued its decision, CPUC requested that the decision
be stayed pending an appeal of the decision to the 9th U.S. Circuit Court of
Appeals. The District Court denied CPUC’s request.

As of the date of this article, the decision has not been appealed, although
because the decision is interlocutory, it may be appealed later.

Is Chapter 11 available to help restructure foreign power projects?
Chapter 11 is powerful medicine for the restructuring of financially
troubled power projects. As a result, both lenders and energy companies have
looked toward U.S. bankruptcy law for assistance with the restructuring of troubled
foreign power projects.

The doors of the U.S. Bankruptcy Court are open for the filing of Chapter 11
by companies which have any assets in the United States (even if simply a bank
account), some operations in the United States, or were incorporated in the
United States. Moreover, projects which are in bankruptcy, receivership, or
liquidation overseas, and which do not seek to file Chapter 11, may still obtain
the assistance of the U.S. Bankruptcy Courts in support of the foreign proceeding
— such as by enjoining creditors in the United States from going after
assets within the United States.

While the theoretical possibilities for restructuring foreign power projects
under Chapter 11 are broad, there are many practical impediments. Chief among
these is the difficulty of a United States court effectively protecting or otherwise
asserting jurisdiction over those assets not located here.

Conclusion

At the writing of this article, the bankruptcy court presiding over the PG&E
case had not ruled as to whether the company’s or the CPUC’s plan of reorganization
would be confirmed. This ruling, together with decisions that will be made on
appeal, will cast substantially more light on a Chapter 11 utility’s life after
death. In the meantime, except for rate-making, creditors and courts have the
upper hand over a Chapter 11 utility’s life support. n

Greater recognition of the correlation among the risks in energy marketing activities,
asset management and operations, and the energy regulatory environment is necessary
for companies to better manage risk. These interrelationships have a significant
impact on business performance, financial results, and overall risk profile, so
energy companies need to take an enterprise-wide view of risk management.

To develop an effective enterprise risk management (ERM) framework, energy
companies need to understand the key internal and external factors that determine
exposure, identify the specific elements that affect their business, and define
a management model focused on key risk-management processes and supporting infrastructure.

A comprehensive framework should address the following key questions:

• What are the external and internal risk drivers that impact the company’s
overall risk profile?
• What are the elements of risk created by the risk drivers and how can
they be managed?
• What is the best risk-management operating model to manage the elements
of risk?

Risk Drivers

As in any business activity, risk in the energy industry arises from uncertainty.
The ERM framework defines these uncertainties as risk drivers, and they can
be divided into external drivers that are not within the company’s control and
internal drivers that arise from within the company.

External drivers for an energy company typically include prices and supplies
in the energy markets, the national- and state-level regulatory environments,
financial and regulatory reporting requirements, economic trends, and the types
of customers the company serves and their associated risk profiles. An added
layer of complexity has been added to these external drivers as energy companies
begin to operate in multiple energy markets and/or in multiple regulatory jurisdictions.

Internal drivers typically include the company’s business strategy, operating
model, degree of capitalization, and risk tolerance. Business strategy is a
key driver — for example, if the company’s strategy is to trade energy
only as a hedge rather than for profit or for market-making objectives, this
can significantly reduce the risks associated with trading operations. The risk
tolerance of the organization, as determined by directors and management, is
the linchpin between the business strategy and the actual measurement of the
risk exposure of the enterprise.

Elements of Risk — Financial

Financial risk is defined as the set of risks impacting the overall financial
performance and shareholder value creation capability of the company, including:

• Market risk
• Credit risk
• Liquidity risk
• Interest rate risk
• Currency exposure

Most financial risks are well-documented and do not require further description.
But two types of financial risk merit special mention given the dynamics of
today’s energy markets:

Liquidity Risk

In a wholesale market in which trading activity is significantly contracting,
liquidity risk is an important area of financial risk that can be difficult
to measure and manage. As the number of transactions and creditworthy counter-parties
decreases across commodities and locations, the ability to trade out of existing
unfavorable positions becomes a critical factor in maintaining value in a company’s
trading books and assets.

Liquidity risk must be managed in today’s market by monitoring the depth and
breadth of the market; if the market shrinks significantly, then liquidity risk
may increase to intolerable levels.

Retail Credit Risk

For those energy companies whose unregulated customer base includes retail
commercial and industrial (C&I) customers, the credit risk profile of smaller
C&I customers can be easily overlooked. But it is important to develop a deep
understanding of the small customer base and the credit risk that these types
of customers present — although each customer may be small, taken together
they can present a substantial volume of risk.

One key set of tools in this area is small-business credit-scoring models that
provide late-payment and/or business-failure measures for companies that might
otherwise pass through credit review screens. These models are commonplace in
industries such as financial services, but in many cases have yet to be adopted
by retail energy providers.

Customer and geographic concentration can also present a considerable retail
risk. If a significant portion of an energy company’s sales are concentrated
in a single or small number of customers, or in a particular geographic region,
the loss of one of these customers or a change in the local economy that affects
companies in that area can have an adverse effect on the energy company.

Figure 1: Energy Risk Management Framework

Elements of Risk — Regulatory

Regulatory risk is defined as the set of external regulatory actions and developments
that can substantially impact the financial and operational performance of the
company, including the revenue requirement, cost structure, and operational
processes. Regulatory risk arising from a variety of regulatory bodies is often
overlooked or insufficiently analyzed by energy companies, but must be addressed
to maintain and enhance shareholder value. These agencies include such groups
as FERC, state PUCs, the NRC, the SEC and various environmental agencies on
the state and federal levels.

With these many sources of regulatory risks, energy companies must carefully
determine how they can actively prevent or mitigate the negative impacts that
can result from changes in regulation. Companies should know the impact of the
regulatory market model on their own business models, understand the regulatory
climate in which they operate, and have a plan to shape regulatory policies
that affect them.

Most energy companies that are subject to regulation have a regulatory affairs
group responsible for responding to these needs. Although these groups are usually
effective in monitoring the regulatory environment, there are two typical problems
with the way these groups operate:

Isolation from Other Risk Management

Regulatory risk monitoring and management have traditionally been conducted
separately from the rest of the risk-management function in energy companies.
But this isolation prevents the company from analyzing and managing regulatory
risks in the context of the company’s overall risk profile — reducing the
company’s ability to both understand how regulatory risks are affecting various
activities and to engage in comprehensive risk hedging and management.

Failure to Quantify Regulatory Risks

Regulatory risks have traditionally been monitored and managed with little
or no analytical rigor applied to risk measurement and management.

Energy companies need to recognize that the impact of regulatory risks can
be estimated and analyzed by building relatively simple models that:

• Assign probabilities to the various potential outcomes for each regulatory
scenario.
• Quantify the financial impacts to the company for each regulatory scenario
outcome.
• Calculate the expected results and variance for each regulatory risk
scenario.

Such modeling provides a better understanding of the financial impacts of regulatory
risks and can be combined with other risk modeling to allow for comprehensive
risk hedging and management.

Elements of Risk — Operational

Operational risk is defined as the set of risks to energy company operations
that can impact financial performance, customer reliability, ongoing operations
and business continuity, safety/environmental performance, and overall company
reputation.

Focus areas typically include process capabilities and controls across the
following areas:

• Core operations, including generation, transmission, distribution, and
customer care.
• Key management and governance processes, including planning, forecasting,
management information, and reporting.
• Business continuity and disaster recovery.
• Ongoing vulnerability, security, and safety exposure, particularly in
the information technology and facilities areas.

The risks associated with operations often arise from the management of physical
assets (generation plants, pipelines, transmission and distribution assets,
information technology, and facilities) associated with an energy company’s
core operations. Key processes include outage management, asset management,
field operations, and business continuity. Supporting process effectiveness
and control is critical to managing risks across these processes.

Of course, these processes are very diverse and they require specialized skill
sets to perform, so they are not the primary responsibility of the risk-management
function. Instead, they are the basis for a business partner role in which the
risk-management function provides the framework, policies, and supporting infrastructure
that enable the business to identify, manage, and balance operational risks
within the context of overall corporate objectives and risk tolerance.

Key to the success of the business partner approach, however, is the risk-management
function’s leadership in the area of management information and performance
reporting. The risk-management function must provide two key items to the operational
areas: the risk-management guidance for developing risk metrics; and the means
for timely and accurate reporting on those metrics.

Risk-management staff need not be experts in, for example, outage management
or field operations to contribute significantly to effective risk management
in these areas. But they must be experts in translating the operational performance
information provided by their operational colleagues into reasonable and measurable
risk metrics. And they must develop the processes and systems to track and report
on these operational risk metrics in a manner that is consistent with and integrated
into the performance reporting for other areas of enterprise risk.

Figure 2: Risk Management Trading Model

An Operating Model

In addition to understanding the drivers of risk and identifying potential
risk exposure and areas of focus, effective risk-management programs clearly
define an overall operating model. This operating model defines the role of
the risk-management function, how it interacts with the business and other corporate
functions, the key risk-management processes, and the supporting infrastructure
and analytic requirements.

An effective operating model focuses on a number of key objectives, including:

• Outlining the overall risk-management strategy, objectives, and key
policies for the company.
• Defining the role and responsibilities of the risk-management organization,
how it interfaces with the businesses, the key reporting relationships, and
the skill-set requirements.
• Identifying and defining risk-management processes, activities, and requirements.
• Developing an effective infrastructure that provides information and
insight into business risks.
• Creating a comprehensive risk-management culture throughout the organization
by aligning the risk-management function with business objectives.

Once the operating model has been created, the risk-management organization
can focus on developing a systematic method for addressing enterprise risks.

An important consideration that runs throughout the risk management cycle is
the establishment of risk-performance metrics. Once metrics are established,
risk monitoring and performance analysis at the enterprise level becomes more
manageable and focused. While these metrics must be reassessed on a periodic
basis, once the organization accepts the tracking of financial, operational,
and regulatory risk in terms of tangible and achievable performance metrics,
the benefits to the risk culture for management and staff can be substantial.
By building these metrics into a balanced scorecard that determines financial
rewards, the organization verifies that incentives are aligned with risk-management
priorities.

To be most effective, risk management needs to be woven into the fabric of
the organization. For energy companies, risk management cuts across the marketing,
operations, and regulatory functions. Energy companies that recognize the interrelationships
among the risks in each of these areas have the potential to become more effective
at managing and balancing risks than those that view these related risks in
isolation and can be more successful at instilling a risk-informed culture.

The enterprise risk management framework provides a comprehensive approach
for understanding, measuring, and managing risks across the organization and
should be considered by any diverse energy company conducting business in today’s
challenging energy markets. n