DISTRIBUTION SYSTEM INFRASTRUCTURE PROJECT TECHNICAL PLAN

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Delivering quality at a great value – yesterday, today and tomorrow…

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Forward-Looking Statement

The following infrastructure plan was developed utilizing the most accurate system information available, which included historical maintenance and inspection results and system performance data along with estimated system component inventories. At the time this plan was developed, an actual system inventory did not exist. A complete system inventory and field inspection are part of the overall infrastructure plan, which will largely drive replacement and maintenance activity through the implementation of the plan. The implementation of the infrastructure plan was deemed too important to be postponed until an independent system inventory could be obtained, which would have yielded more accurate replacement and maintenance estimates. It is anticipated that actual inventory and inspection results may deviate from original estimates. As this occurs, adjustments to the infrastructure plan will be evaluated and implemented as required. This plan contains forward-looking statements that may fall within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance, and often contain words such as “anticipates,” “may,” “will,” “should,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “targets,” “will likely result,” “will continue” or similar expressions.

The plan is based upon our current expectations as of the date hereof unless otherwise noted. Our actual future needs and performance under the plan may differ materially and adversely from our expectations expressed in any forward-looking statements. We undertake no obligation to revise or publicly update our forward-looking statements or this plan for any reason. Although our expectations and beliefs are based on reasonable assumptions, actual results may differ materially due to a variety of factors, some of which are listed in certain of our press releases and disclosed in our public filings with the SEC.

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I. Overview

The Distribution System Infrastructure Project (DSIP) is a long term initiative by NorthWestern Energy (NWE) to assure that its electric and natural gas distribution systems are aligned to optimally meet its customers’ needs and expectations for safe, reliable and cost effective service. Virtually all elements of America’s infrastructure are aging too fast relative to modernization and replacement efforts, and the nation’s utility systems are no exception. Our current systems are safe, reliable and competitively priced, and we are committed to keep them that way. This requires a proactive approach to get in front of the aging infrastructure issue, as opposed to being forced into a more difficult and costly reactive approach later.

NWE is fortunate in that it has the time to deal with aging infrastructure in the right way. At the same time, new technologies are emerging that promise to offer many benefits in the future. A modern, adaptable infrastructure will be a prerequisite for seizing those opportunities, and we have the obligation to assure that our system is ready to accept new proven and cost-effective technologies, as they become available to help support our customer needs and Montana’s economic foundation.

A. Background

NWE serves 337,600 electric customers and 181,300 natural gas customers in Montana. An elaborate infrastructure, including 17,200 miles of electric distribution circuits and 4,900 miles of natural gas mains, is required to carry the electric or natural gas commodity to these customers in a safe, reliable and cost effective way. The utility’s obligation to serve is not open to discussion; NWE is required to build and maintain the infrastructure necessary to meet its customers’ needs. In return, the company has the opportunity to earn a fair return on appropriate investments it makes to meet that obligation.

Utilities are challenged to determine the optimum investment required to meet their obligations. Too little investment will lead to unacceptable service levels. Too much investment means unnecessarily high costs. Utility managers, under the oversight of regulators, must find the right balance to maintain both reasonable rates and service levels.

Adding to this challenge is the reality that the factors influencing the balance are often in flux. The various infrastructure strategies of the past are often no longer appropriate due to natural variations such as changing public or regulatory expectations, aging facilities, resistance to rate increases, evolving technical issues or priorities, or a wide variety of other changing circumstances. Good management carefully monitors such trends and adjusts plans accordingly, preferably by annual fine tuning, but at times by more aggressive, quantum changes in strategy. NWE is now precisely at such a crossroads, where decisive action is appropriate.

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This Technical Plan describes a thoughtful, measured approach that accelerates our distribution infrastructure management program over the next seven years. It is designed specifically to result in electric and natural gas distribution facilities that will meet the long term customer needs, while maintaining stable and competitive utility rates. Arriving at this balance involves both science and art – there are no easy formulas that can produce universally accepted solutions. In all cases, however, the application of science and art has been governed by sound engineering judgment and industry practices. The purpose of this document is to clearly explain that process and why we believe that the technical plan for the maintenance and improvement of our electric and natural gas distribution facilities is the right thing to do, and now is the right time to do it.

B. Why DSIP? Why Now?

Much like the aging infrastructure trends across the United States in other areas, whether it is bridges, roads, airports or others, electric and natural gas utilities are faced with addressing their aging wires and pipes distribution systems.

The result is similar to other types of U.S. infrastructure, that maintenance and new investment have not kept pace as equipment and facilities age. With each year of decline, the difficulty and cost continues to grow to the point where costs can become prohibitive, further restraining new investment.

The generic factors now converging to magnify this aging infrastructure challenge include:

x Aging of key assets – the building boom of the late 60s and early 70s has resulted in a variation of the “baby boom,” in which many facilities are reaching the end of their design life (typically 40 years) at the same time.

x The cost of modernizing systems continues to rise – although inflation has been benign in recent years, this has not been the case in electric construction, as recent studies have shown above average cost increases for labor and material. Further, the cost to replace the aging components is many times their original cost.

x Absorption of what was once “excess” capacity in systems – the industry has been “working off” for decades the excess that resulted from the high growth years, with the result that in many cases the excess has turned to a deficit.

x Nationally, focus on cost containment has impacted modernization and maintenance efforts – the industry was especially aggressive in cost cutting in the 90s as it faced the potential for competition.

x Customer expectations continue to increase – the role of electricity in our society continues to grow, with the inevitable result that demands and expectations will also grow.

x The expectations gap between urban and rural customers has narrowed – rural reliability will never equal that of urban customers, but rural customers rightfully expect a reasonable service level.

x Technology offers mushrooming opportunities – the enormous investment now taking place in distribution technology (the Smart Grid) has the potential to lead to significant benefits in the future.

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In terms of urgency and timing, electric and natural gas utilities across the country find themselves in different positions. Virtually all face infrastructure challenges and most view the issue with great concern. However, some are positioned well to deal with it, and others are not. The worst positioned have simply fallen too far behind, and are in the spiral caused by prohibitive costs – the challenge of “catching up” will be difficult. Others are borderline, and should be very aggressive while there is still time. Others still, although challenged, have the time to do it right. However, the half-life of that asset is short, and such firms would be prudent to not allow it to waste away.

The nature of the company’s schedule, featuring a two-year phase-in followed by five years of high production, is ample evidence that this is not a panicked reaction. On the other hand, the high production levels envisioned in 2013 through 2017, which far exceed what the company has done in the past, are clear evidence that this is indeed a very aggressive program. Such a thoughtful, structured, efficient approach is possible only because NWE has the time to do it right.

In Chapter II, A Call to Action, The Liberty Consulting Group will discuss in detail the U.S. trends in infrastructure in general and electric and natural gas distribution in particular. Their analysis shows there are good reasons why America’s infrastructure has been in decline, and it will take strong leadership to overcome those reasons.

C. Development of the Plan

The company retained The Liberty Consulting Group to conduct a formal audit of the company’s transmission and distribution infrastructure management in 2004, the results of which included numerous recommendations for improvement. Perhaps the most significant of these relate to the overall management and engineering approach to infrastructure management, and these were the recommendations that were most effectively implemented.

As a result, NWE restructured its engineering organization to provide increased focus and enhanced capabilities. In addition, the company recognized the need for better data on the existing infrastructure, and for more sophisticated analytical capabilities to exploit that data. The current ability to knowledgably and efficiently attack the infrastructure challenge is a direct result of the improvement initiatives undertaken by NWE in the wake of the 2004 audit.

In 2009, management believed that the time was right for the next logical step and that an aggressive approach to confronting the aging infrastructure challenge was appropriate. The audit actions set the stage and established a strong foundation. The organization had the capability to now attack the bigger distribution infrastructure issues. As a natural bridge to their participation in the 2004 Audit, NWE once again retained The Liberty Consulting Group to provide independent third party views, input and analysis into the planning process. The effort was kicked off with four rather simple objectives applicable to the electric system:

x Arrest or reverse the trend in aging infrastructure

x Build margin (capacity) back into the system

x Maintain reliability over time, and improve it for our rural customers

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While simple, these objectives nevertheless proved powerful, and they are still the foundation for the DSIP. There is a direct tie for every element in the plan to one or more of these founding objectives.

A slightly different but equally powerful approach was applied to natural gas. The overriding importance of safety tends to relegate other objectives to the background. So, in natural gas, the secondary objectives are perhaps less important as a foundation element than are the principles that will guide the organization in achieving the safety objective. A commitment to safety and doing things right is less of an objective than it is a way of life or culture. Accordingly, organizational attributes seemed more appropriate as the founding principles for the natural gas program. Those attributes were defined as follows:

x Improve, or at minimum, maintain leak rate performance

x Enthusiastically embrace the industry’s new safety model (DIMP)

x Employ state-of-the-art analytical skills to proactively manage safety

The reader will notice that these four electric objectives and three natural gas attributes are repeated throughout this – this is no accident. In fact, as the foundation of the DSIP, they were repeated continuously throughout the development of the plan. They appeared at the front of every presentation, regardless of audience and regardless of how many times that audience heard them before. Also, they appeared in every technical discussion, as every decision and every consideration was tested for compliance with them.

After project kick-off, the general flow of the planning effort is illustrated below:

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customers and stakeholders, further challenged the utility mindset of both NWE and The Liberty Consulting Group resulting in a plan that is rooted in customer expectation.

We noted above that infrastructure development has faced very real restraints, and those restraints are not easy to overcome. The strength of those restraints is what has caused the national infrastructure issues we have addressed. Management recognized that a traditional approach, although it served the industry well for decades, is no longer effective, and a new approach is required. We will discuss the criteria for that new approach in Chapter III, Principles and Benefits of the Plan, but will emphasize here the participative aspects, which directly contributed to several instrumental course corrections.

D. Summary of the Plan

1. Scope

The plan consists of eight elements or projects, each for electric and natural gas. These were identified as the critical parts of the infrastructure, or critical work activities, necessitated by the objectives of the plan and the visions established for the future electric and natural gas systems. The 16 elements are shown to the right.

Each of the 16 elements will be managed as a project, with all being integrated into an overall project management scheme. This notion of an integrated DSIP is important because the sequencing of work will be a critical consideration in achieving an optimized, cost-effective implementation. To the extent each element goes its own way, efficiencies will be lost. On the other hand, to the extent work can be packaged, including across project lines, substantial cost and schedule benefits are expected.

2. Costs

The estimated costs of the DSIP are summarized on the next page. The electric and natural gas plans will be explained in detail in Chapters IV and V, respectively. The supporting activities, which are shown below the line in the summary, are described as follows:

x Supervision & Engineering Project Support. Acquire additional staffing necessary for several aspects of the project, including engineering, supervision and project management. The funding listed in this activity is to address the expense portion of the additional staffing.

x Geographical Information System (GIS) Expansion. Conduct a field inventory of visible electrical components to verify and augment electric distribution facility data in NWE’s GIS. Field data collected will include information such as component locations,

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component phasing, and customer service connectivity to protective devices to support plans to implement an integrated Outage Management / Mobile Workforce Management / Computer Aided Dispatch (OMS/MWM/CAD) solution.

x Electric Lighting Inventory. Conduct a full inventory of NWE-owned lights. The inventory will include information to assist NWE’s Asset Management team to develop a future lighting business plan.

Electric Utility Plan Primary Activities

Incremental CAPEX Incremental O&M Incremental CAPEX Incremental O&M Incremental CAPEX Incremental O&M

Pole Inspection Inventory & Ranking 0.45 1.30 6.25

Pole Replacement 7.00 8.00 78.86

Overhead Line Equipment Patrol & Repair 0.40 5.51

Line Clearance Tree Trimming 2.00 2.00 20.67

Underground Equipment Repair 1.38 3.39

Underground Cable Replacement 1.00 1.50 46.64

Capacity Margins Improvement 21.94

Line Clearance Correction 3.92

Worst Circuit - Rural Reliability Improvement 0.50 0.20 0.50 0.60 3.29 7.84 Substation Upgrade and Improvement 0.60 1.70 14.63 4.13 System Automation & Smart Grid Technology

Installation 0.50 0.40 42.40 1.06

Electric Utility Total $ 9.10 $ 2.65 $ 12.20 $ 4.70 $ 213.06 $ 48.87

Natural Gas Utility Plan

Business District Inside Meter Set and

Vintage Construction Improvements 5.00 5.00 26.50 Non-Business District Inside Meter Set and

Vintage Construction Improvements 0.85 0.21

Establish a Distribution Integrity

Management Program 0.35 0.70 0.75 0.64

Gas Line Damage Prevention 8.06

Farm Taps Rebuild 0.53 0.11

Gas Line Stub Removal 4.98 0.53

Gas Lines Under Structures Removal or

Relocation 4.13 1.06

Zone Valve Installation Plan 1.00 0.50 1.00 0.50 3.18 3.71

Natural Gas Utility Total $ 6.35 $ 1.20 $ 6.00 $ 1.25 $ 40.17 $ 14.31

Other Related Activities

Supervision & Engineering Project Support 0.65 0.95 5.62 Geographical Information System Expansion 2.50 2.53 3.18

Electric Lighting Inventory 0.25 0.25

Other Total $ 3.40 $ 3.73 $ 8.80

Project Total $ 15.45 $ 7.25 $ 18.20 $ 9.68 $ 253.23 $ 71.97 CAPEX = Capital Expenditures

O&M = Operations and Maintenance Expenses

Phase-in to Recommended Plan Estimated Cost 2013-17

2011 2012 Recommended Plan

Phase-in to Recommended Plan

Estimated Cost 2013-17 w/inflation

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3. Schedule

The main production window for the DSIP is the five-year period beginning in 2013. The levels of production in this period are well beyond the size of any prior NWE distribution construction efforts. In addition to a major management challenge, the size of the DSIP is an opportunity to develop additional efficiencies. We are committed to taking advantage of these opportunities, but it will take time to build the capabilities and management systems required. Simply stated, it would be neither prudent nor practical to make such a quantum leap overnight.

For this reason, NWE is implementing a two-year phase-in or ramp-up period. On a simplified basis, 2011 can be viewed as a head start on the especially important priorities as well as the engineering and planning actions necessary to support the later years. In 2012, the focus will be on ramping up to a higher level of production while implementing and perfecting the new DSIP organization and management systems. By the end of 2012, we expect to be ready to move to the very high demands of the production years.

E. Benefits

The benefits of the DSIP come at many levels. The technical benefits will be reviewed in detail in the discussions of the electric and natural gas plans. However, the most valuable benefits will flow simply from the achievement of the visions for the future electric and natural gas systems. The attributes described in those visions have a tangible value to our customers and regional stakeholders. Safety, reliability, the ability to grow with the region and the efficient use of our energy resources, all rolled into a cost effective, competitive package, is a benefit that is hard to quantify, but is nonetheless important.

The genesis of the DSIP was the concern for aging infrastructure; the DSIP is well suited to that challenge. It arrests and reverses the aging trend; it restores margins that have eroded through the years; it maintains a high level of reliability; and it positions the distribution system to take advantage of new technologies, including automation in the near term and yet to be defined advances in the longer term. Meanwhile, on the natural gas side, a significant contribution to system safety will result, brought about through targeted leak reductions, supported by a more aggressive program of threat analysis and mitigation.

The timing of the DSIP project in itself produces real benefits. The program recognizes the importance of “seizing the moment” while we still have the time to do it right. There is no question that a failure to act now simply postpones the inevitable. It will be a lot harder and a lot more expensive to face these very same questions five years from now.

In addition to the direct electric and gas system benefits of the program, there are other societal benefits from this initiative. The capital spending plan for the next seven years is nearly $300 million, and that is over and above NWE’s base level of spending. That represents many jobs for a sustained period, with obvious benefits to the region. Like many utilities, we expect a significant amount of our experienced employees to retire in the next few years. The DSIP provides the added benefit of enabling knowledge transfer to occur so that the next generation is

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well prepared to carry on the strong traditions that have been instilled in the utility over the past century.

It is important that we focus on the utility of the future – now – to be able to fully support the future economic well-being of the communities that we serve. Modernizing the systems today in preparation for tomorrow’s standards can be reasonably accomplished now at a reasonable cost and in a logical, controlled manner. It is the right thing to do, and the right time to do it.

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II. Principles and Benefits of the Plan

In 2009, NWE responded to “the call to action” and started the process culminating in this plan. Respecting the restraints that have limited infrastructure investment, and which continue to be strong negative forces, it was obvious that a traditional approach would not overcome those restraints. We looked for (a) a new, holistic process that would take the time and effort to act along many fronts to build a credible case for action; (b) a workable, cost-effective plan; (c) a financial strategy that could support the program; (d) developing an approach for timely cost recovery; and (e) a stakeholder strategy to build stakeholder preferences and opinions into the plan.

This effort spanned two years so far, with encouraging results. It is not likely that the restraints to infrastructure programs would have been overcome to the same extent had a shorter, narrower planning approach been employed. In this chapter, the process to develop the plan will be explained. The more detailed planning aspects of the electrical and natural gas efforts will be discussed under those chapters.

A. Planning Principles

The single most important planning principle that guided the project was the necessity to establish a strong foundation in the form of a vision and objectives, and continuously test all subsequent planning activities against that foundation. This principle always recognized that changing that original foundation would, if necessary, be acceptable; but as long as the foundation was in place, no exceptions could be made. Whenever results conflicted with the foundation, the team returned to the original vision and objectives, tested the results against them, and then took remedial action to get back on course. As a result, this plan is fully compliant with the founding concepts.

A second equally compelling principle stems from the notion that the plan could only succeed if the restraining factors discussed in Chapter II could be overcome. Otherwise, the effort would succumb to the same factors depressing infrastructure investment around the country. This led to a set of criteria that the planning effort would have to achieve:

x The plan must demonstrate a credible net benefit to customers and the region.

x The resulting infrastructure must be demonstrably cost-effective in its scope, design and construction efficiency.

x There cannot be an unreasonable rate impact.

x There must be a meaningful voice for stakeholders that are respected in the process.

x The plan cannot compromise NWE’s financial position or its future ability to serve. These principles were not taken lightly. A commitment to them is in fact one of the reasons why the process spanned two years. The company felt the added effort was worth it. In reality, the added effort was, and continues to be, mandatory. Chapter II should have made clear the certain results from a traditional approach to infrastructure planning. The traditional approach served us, and all other public works, well for decades. But it is now, unfortunately, just a recipe for frustration and deteriorating infrastructure. New approaches, as difficult and time-consuming as they may be, are needed.

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B. Objectives

The company is in better shape than many other utilities. Rates are competitive and reliability is high. Infrastructure is aging faster than the company’s modernization efforts, but this has not manifested itself in the form of large declines in reliability, large increases in cost or the urgent need for super-expensive programs, at least not yet. Compared to utilities that are clearly in a high cost “catch up” mode, and perhaps to some for whom it is already too late, we have the time to do things right.

But the warning signs are indeed there, and the primary root cause is the challenge of making suitable investment to keep pace with the aging of facilities and equipment. We are not immune from the forces impacting essentially every utility. With this in mind, we started the process with a set of four objectives for the electric distribution system, and this DSIP covering both electric and natural gas distribution is the result. Similar objectives were defined for natural gas. And a vision established for the future electric and natural gas systems. These defining factors form the foundation for the DSIP, as defined below.

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C. The Planning Process

1. Economic Analysis / Justification

The electric and natural gas approaches are substantially different due to the role of cost and economic justification. Simply stated, the safety priority took precedence in the analysis of the natural gas system, whereas the balancing of cost and benefits was the focus in electric. This is not to say that cost was ignored in natural gas, but it was not involved in the initial prioritization of high impact items. That process was governed entirely by safety considerations, including the probability and consequences of leaks. Once the initial highest priorities were established, the more discretionary items were judged on a balance of cost and degree of threat.

In planning for the electric scope, a wide range of programs was considered, from relatively minor efforts to the very aggressive. Initial technical preferences were made, but then the options were subjected to economic considerations. A life cycle cost analysis1 was conducted on each case such that the relative costs and impact on rates for the more and less aggressive cases could be examined.

It would certainly be fortuitous if every preferred option could be justified on the basis of life cycle costs. This would mean that for whatever is invested up front on the infrastructure, direct cost savings of a greater amount will be achieved. In fact, in many industrial applications, no

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A “life cycle” analysis considers not only the first (capital) cost but all subsequent costs associated with the change. This includes operating costs as well as the savings from any direct benefits, such as reduced outage costs.

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investment would be made without such justification. The accompanying chart illustrates this line of thinking, and it represents an appropriate analysis.

But such an approach does not necessarily work in evaluating all electric (and many other public service) infrastructure needs. Specifically, utilities have obligations to provide an appropriate level of service. What if the optimum point, the least cost option, is to simply wait for the component or facility to fail and then replace it? In fact, from a strictly economic perspective, this is indeed the least cost in many cases, but it is often not an acceptable practice. One cannot simply wait for poles to fall over, or large expensive transformers to fail, or overhead equipment to fall off the pole.

In other words, the optimum economic point in the above graphic often falls in the “Unacceptable Operations” regime. To complicate matters further, the dimensions of that regime are subjective – it may be as shown above for one utility and twice that width for another. The result is that, in many cases, the otherwise elegant analysis deteriorates to a subjective judgment of where to draw the line in selecting a frequency of asset replacement.

But this is not really unusual, nor should it be troubling. Engineers are trained and paid to make these judgments based on sound technical principles and a reasonable balancing of the competing priorities. And this is indeed the basis for many of the decisions underlying this plan. The life cycle cost of each infrastructure option, expressed as a rate impact2, was estimated and balanced against the benefits and consequences resulting from that option. That thought process is further explained in each of the technical elements described in this plan.

It is important to note that “engineering judgment” is not some vague excuse to do what one pleases. On the contrary, the costs associated with options are real as are the resulting technical benefits or consequences. The estimation and logic surrounding any decision must be logical, consistent with good engineering practice and subject to validation, both internally in the organization and externally through regulators and others.

Despite many decisions being made on such a subjective basis, a rigorous cost analysis is still appropriate, because it both frames the basis for an engineering judgment and suggests alternates for optimization.

2. Participative Process

We were committed to a participative process from the start. The key feature, but not the only, was the creation of an ISG. This organization was involved as the plan evolved. Their feedback provided many valuable insights and led to some major shifts in thinking on the part of the company. The material discussed with the ISG, as well as minutes of their meetings, is cataloged on the web.3

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Rate impacts are estimated by calculating the “revenue requirement” associated with an option. The revenue requirement, which is the amount that must be recovered from the customer, equals the operating costs plus the

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We also shared information during the process with others as frequently as practical. Regulators, community leaders, employees, and consumer representatives were kept informed as the process moved forward.

3. Technical Approach

As a result of The Liberty Consulting Group 2004 audit of NWE’s infrastructure management processes, the company launched an effort to significantly upgrade the capabilities of its organization. In fact, it is a direct result of those added capabilities that permitted the creation of this plan. NWE’s response was to reorganize its engineering function to provide for an infrastructure management group. That group immediately recognized that infrastructure data necessary for sophisticated analysis was lacking, and set upon developing the data sources and structure necessary. That effort has taken great strides and continues today.

In addition, the group enhanced its own capabilities for sophisticated analysis. This has enabled NWE to both better understand the appropriateness of acting now on infrastructure improvement as well as develop a credible plan for that purpose.

D. Benefits

Each specific element of the plan is justified on the basis of the benefits it contributes. The expected benefits, and their appropriateness versus added costs, are explained under each of the technical descriptions in Chapters IV and V. In addition, there are significant global benefits that flow from the plan as a whole, not the least of which is the achievement of the vision for the future electric and natural gas distribution systems. These other global benefits are described below.

1. Reliability

In evaluating the benefits of the DSIP, we have frequently discussed increased reliability. We have attached a tangible dollar savings to reliability only to reflect reduced company costs for responding to outages and restoring service. But this is only a small fraction of the savings to the economy resulting from reliability gains. This is a little understood concept, because our added costs as residential customers do not change one way or another as a result of an outage. In fact, customers respond in surveys that they place little dollar value on reduction of outage minutes. The real “value of reliability” is seen by business and industry, where the cost impacts of electric outages are enormous.

A 2004 study by the Lawrence Berkeley National Laboratories estimated a cost of $80 billion per year as a result of electric interruptions. These costs result from lost business, idled workers, idled manufacturing processes and lost raw materials and products. Commercial customers bear the brunt of this, amounting to 72 percent of the estimate.

In a more recent study, the Electric Power Research Institute (EPRI) put the loss at $104-164 billion per year. They included power quality problems in addition to outages and attributed $15-24 billion to that cause.

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As an example, the cost to a medium or large commercial or industrial customer for four hours on a summer weekday afternoon is estimated at nearly $60,000. The corresponding cost for a small business is $2,700, much less but still very impactful for a small businessman.

We would expect therefore that the benefits to the regional economy from increased reliability are both real and substantial. But NWE does not use these benefits to justify investments, nor do most utilities. It is felt that the beneficiaries of such increased reliability are hard to define, as are the actual amounts of the savings. Therefore we leave them out of the analysis, but that does not change the reality that real and tangible benefits will result for the regional economy.

2. Safety

The DSIP places its highest priority on natural gas safety, and specifically leak mitigation. The industry does recognize the importance of leak prevention and responding to leaks; however, in rare cases, the consequences of a natural gas leak can be catastrophic. While we can and do estimate the cost to prevent a leak, there is no credible way to estimate the value of that avoided leak. But with each natural gas incident experienced around the country, we are reminded that the value is considerable.

Perhaps some of our discussion here will be interpreted as downplaying the role of safety in electric versus natural gas. No one in the industry would make that mistake – the danger of the business, especially among electrical workers, is universally respected. There continues to be too many fatalities by electrical contact or other accidents. So there should be no mistaking NWE’s, or any other utility’s commitment to safety in all of its businesses. Our point vis-à-vis natural gas is that safety is the overriding decision parameter when evaluating natural gas infrastructure. But as will be seen in the plan discussion, safety is an important element of the plan as a whole, and enhanced safety for the public and employees is a real benefit arising from the DSIP.

3. Regional Economy

Economic benefits can be visualized in two categories. First, the large capital expenditures spread over many years mean many jobs for a long time. Second, a region cannot be economically strong without a sound utility infrastructure, reliable electric service and reasonable utility rates. In many ways, the DSIP is an investment by Montana in its own future. 4. Costs

We have stressed the phrase “the time to do it right” which means the time to do it cost-effectively. The investments recommended herein could, in many cases, be deferred for a few years. In fact, that option, recognizing the state of the economy in the last few years, seemed quite logical during the evaluation of the plan. There is a downside to any deferral, but could not rule out that option. This issue is far less significant today because of the program’s “phase in” in 2011-12, effectively deferring the main part of the program by two years.

Despite these changes, deferral was examined in the consideration of individual elements. A relaxed schedule was an option, and was a key part of the decision-making process.

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We believe that, under any circumstances, the DSIP investments are necessary. Timing is undeniably an option – completing the investments at some time in the future is not. With that said, there are compelling arguments to move ahead promptly, while the work can be scheduled in a reasonable and structured pace. In addition, costs are sure to be less now than later. And finally, it can eventually become too late to catch up – the scope becomes prohibitive.

In summary, moving ahead expeditiously is the most beneficial option. 5. Technology

Distribution technology is one of the electric elements of the plan. As with virtually every other business, technology is playing a driving role in distribution. A large portion of new spending, and virtually all government funding, is dedicated to Smart Grid initiatives in general and smart meters in particular. The extent to which such technologies may eventually benefit our customers is a question that will not be answered for some time. Suffice it to say that the company is committed to major investments only as they prove economically justified.

NWE is participating in a regional pilot program that will inform future decisions about cost-effective and appropriate timing of large scale deployments of new technology. However, we believe that now is the time to make the system ready for these advancements.

The communication backbone necessary to support most new applications is lacking, and the creation of the backbone is a DSIP priority. The subsequent ability to employ new technologies as they come along is a benefit with substantial potential in the future.

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III. The Electric Plan

The electric distribution system of NWE-Montana serves 337,600 customers via 17,200 miles of overhead and underground distribution lines. These customers are spread over more than 100,000 square miles, giving NWE one of the lowest customer densities in the U.S. This rural, or more appropriately frontier, characteristic of the system raises many challenges. Some might say the deck is stacked against the company

because of low customer density, which usually is a cause of low reliability and high cost. However, these challenges have been largely overcome, and the nature of the service territory has not resulted in the reliability and cost penalties one would expect. The difficult aspects of managing such a widely spread infrastructure is nevertheless a major consideration in the DSIP and should not be underestimated.

A. Objectives

The “foundation” for the electric plan, consisting of the program objectives and vision, was discussed above. The objectives were set from the very start, and all other DSIP activities flowed from them. Those objectives were, and continue to be:

x Arrest or reverse the trend in aging infrastructure

x Restore margin (capacity) back into the system

x Maintain reliability over time, and increase it for our rural customers

x Position NWE to adopt new technologies

All of the objectives are tied directly to one or more specific implementing elements of the DSIP, as illustrated below. There are also indirect and overlapping ties (not shown).

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The vision, which was initially defined by management and later modified slightly with the help of the ISG, similarly directly ties to every element of the plan. The vision as finally approved is for a distribution system that is:

x Safe for our employees and the public

x Reliable – consistent with the needs of a society that is increasingly dependent on electricity

x Able to grow – to accommodate the needs of new customers and potential quantum growth from new electric applications

x Optimized – an optimum mix of investment in new plant and maintenance of existing facilities

x Responsive to all customers – minimizes the service gap between urban and rural customers

x Energy efficient – a system that provides the platform to achieve the efficient use of energy resources

x Cost effective – a system designed, built and operated for least, long-term cost while achieving the above objectives

x State-of-the-art – a system that employs effective technologies to further the above objectives

The vision represents a view of the system that is very beneficial to the region and NWE’s customers. It represents a safe, reliable, efficient, flexible and cost-effective system that will meet the future demands of businesses, industry and consumers. It will be highly supportive of

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economic development and the benefits that it will bring to Montana’s communities. This is a vision that hopefully can gain a wide degree of support among stakeholders.

B. Building the Plan

Management’s initial direction to the planning team was to develop an aggressive program for dealing with the aging infrastructure issue, specifically aimed at the four objectives discussed above. A first challenge was to fully understand just how “aggressive” the program should be, recognizing that the question entailed both economic and technical factors. The first action of the team was therefore to frame the possibilities, from less investment to a high level of investment. Five “scenarios” were defined as a starting point, with the stipulation that each would be examined for its economic and technical impacts on the distribution system.

These scenarios were intended to frame the early discussions and not to produce a precise selection of one box or another. This allowed the full spectrum to be considered, even clearly unacceptable options. As a result, the team developed a healthy and full understanding of the possibilities and the cost to move forward.

This same framework was then applied to each proposed element of the plan. A scope was defined for each element that sought to meet the criteria of each scenario. The resulting matrix allowed a quick cut of many options.

Once the obvious non-contenders were removed, a more detailed technical analysis could be conducted. For each plan element, the specific problems to be addressed were identified and the various solutions examined in more detail. The combination of an awareness of the current situation with the guiding principles of the objectives, allowed a narrowing of options.

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As preferred solutions began to emerge, a more detailed cost analysis was conducted. The intent was to determine the relative costs and values of the options and to seek optimum, or least cost, solutions. The final decisions on each element evaluated were based on an engineering assessment balancing costs and benefits.

C. Program Summary

The full production elements of the DSIP electric plan are being planned for 2013-17. A phase-in period will span 2011-12, in which initial inspections, high priority work and capability building will take place.

The workload envisioned for 2013-17 represents production levels not previously seen by NWE. As such, they are considered to be a major management challenge. A new organizational approach to management, additional resources and expanded management systems are necessary. These will all be put in place and built to their full capability during the 2011-12 phase-in period. The table below sets forth the estimated costs of the eight elements comprising the electric plan.

Electric Plan

Electric Utility Plan Primary Activities Incremental _CAPEX Incremental _O&M Incremental _CAPEX Incremental _O&M Incremental _CAPEX Incremental _O&M

Pole Inspection Inventory & Ranking 0.45 1.30 6.25

Pole Replacement 7.00 8.00 78.86

Line Clearance Correction 3.92

Underground Equipment Repair 1.38 3.39

Underground Cable Replacement 1.00 1.50 46.64

3 Overhead Line Equipment Patrol & Repair 0.40 5.51

4 Line Clearance Tree Trimming 2.00 2.00 20.67

5 Worst Circuit - Rural Reliability Improvement 0.50 0.20 0.50 0.60 3.29 7.84

6 Substation Upgrade and Improvement 0.60 1.70 14.63 4.13

7 Capacity Margins Improvement 21.94

8 System Automation & Smart Grid Technology _Installation 0.50 0.40 42.40 1.06

Electric Utility Total $9.10 $2.65 $12.20 $4.70 $213.06 $48.87 2

Phase-in to Recommended Plan Estimated Cost 2013-17 w/inflation

2011 2012 Recommended Plan

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D. Technical Details

1. Pole Inspections and Replacement a. Background

This program involves the management of the NWE wood distribution poles. It has been estimated that between 160 million and 180 million wood poles support the electric transmission and distribution systems in the United States.4 These lines represent up to 40 percent of the net value of some utilities.5 Wood poles have a long history of providing excellent service for supporting overhead electrical and telecommunication lines for nearly a century. They are still unsurpassed as the structural foundation of the overhead distribution system due to their combination of economy, sustainability, flexibility and strength.

NWE has over 289,000 wood distribution poles in Montana. These poles vary in terms of wood types, wood preservative treatments and suppliers. Once any wood pole is placed into the ground, it begins a slow process of aging and decay. The aging of these poles must be monitored until eventually the pole will require replacement. A treated distribution pole can easily have a life of over 40 years.6

The National Electrical Safety Code (NESC) requires that wood poles be replaced when they deteriorate to below ⅔ of their original design strength requirement. Decay of a pole is usually in the form of gradual deterioration in an area just below the groundline caused by fungi and other low forms of plant life. Also, insect attack (termites and ants) and excessive weathering and splitting at the pole top can contribute to pole failure or need for replacement. However, such failures are not considered as major as groundline decay, and happen much later in the pole's life. By far, the main cause of pole replacement is active decay in the groundline area of the pole to 18 inches below. Moisture and oxygen in this area greatly speed up the decay process.

The pole decay below the groundline may be on the exterior of the pole, but usually the decay area is in the soft center wood of the pole. As the decay progresses the interior of the pole becomes hollow. In order to check for decay properly, each pole must be excavated to about two feet below the surface. After the exterior is checked for decay, the pole must be bored and measured for interior rot. If the pole still has sufficient strength to remain in service, it is then prudent and cost effective to apply preservative to the excavated pole area and the pole interior. This preservative treatment stabilizes and reduces the future decay rate of the pole. With this regular inspection and maintenance, it is possible to extend the life of wood poles to over 75 years.7

4

Forest Products Journal, 2002 Utility Survey, Nov 2002

5

Ibid.

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b. Status of NWE Poles

i. Summary of Present Conditions and Trends

The overall condition of the NWE distribution pole inspection and replacement program can be summarized as follows:

x A large population of aging lodge pole pine dominates. This vulnerable population will require close monitoring and maintenance to avoid becoming a major safety concern in the near future.

x As a result of natural aging of the less durable lodge pole pine population, the defective pole rate is undergoing rapid growth. The present rate of pole replacement is not keeping pace with the acceleration in failures. A growing backlog of decayed poles is the inevitable result.

ii. NWE’s Pole Inventory

There are two main pole species on the NWE system. Of the 289,000 poles, it is estimated that 61 percent are lodge pole pine and 39 percent are Western red cedar. These two pole types have very different characteristics.

The lodge pole pine is one of the least durable pole species used in the United States.8 Its use has been mainly restricted to western states due to their relatively favorable environmental conditions. This species became dominant in the NWE inventory due to its lower costs and suitability for Montana’s conditions, but changing economics caused NWE to cease all purchases of this pole in 2000. The average age of the lodge pole pine poles now in-service at NWE is estimated to be 32 years. The average age at failure is estimated to be 38 years.

The Western red cedar pole is one of the most durable pole species available.9 Although more expensive, this pole is the economic choice and is the current type being purchased by NWE. The average age is estimated to be 19 years. The average age at failure is estimated to be 48 years.

iii. Failure Rates

The current demographics of NWE’s pole inventory accurately reflect the reality of the pole inspection results. With the relatively high average age of the lodge pole pine population, one would expect that an increasing number of poles fail to pass inspection. 8

US Department of Agriculture Rural Utilities Service, Bulletin 1730B-121, Pole Inspection and Maintenance

9

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This is indeed the case, with 10 percent of lodge pole pine failing inspection compared to about three percent for the Western red cedar. Further, as the poles continue to age, that high 10 percent failure rate is sure to increase every year, further expanding the backlog of decayed poles in service.

The accompanying chart shows the clear trend of accelerated failures. The relatively high and growing failure rate is an unmistakable signal that the inspection and replacement process must be accelerated. The key to success is a program that:

x Inspects and replaces poles faster than the annual failure rate in order to reduce and stabilize the number of decayed poles in service.

x Once the backlog is minimized and stabilized, maintains an inspection / replacement cycle synchronized to expected failure rates for the long term.

iv. Current Inspection Cycle

The optimum inspection frequency is a function of failure rates, but is also tied to many other factors. Economics is an important consideration in that it is costly to inspect, treat or replace poles. Too frequent inspections mean higher costs – too infrequent inspections mean a growing backlog of defective poles.

A defective pole can be located anywhere in a circuit due to large variances in local moisture conditions and exposure. In Montana, elevation also plays a large part in the weathering conditions of a pole. It is, therefore, best practice to implement a structured, methodical program in which every pole in a circuit portion is inspected on a reasonable cycle.

Based on a 2002 pole survey of 261 utilities, the average distribution pole inspection cycle was 8.1 years.10 It is important to note that this cycle could range from a cursory visual inspection to a complete excavation, sounding, and boring.

The inspection rate employed by NWE in the past has varied. Inspection rates were determined annually by considering a number of factors, including available funding, relative priority of the work, failure rates (as evidence of defective pole backlog) and local workload conditions. On balance, the rate has been in the five percent range, which equates to a 20-year cycle.

v. Consequences of the Backlog

The number of defective poles is a public safety issue. Normally, it will not show up in the regular reliability reports. However, it will become increasingly apparent in storm situations. The poles will experience their maximum stresses during the icing and high wind storm events. A good example is the Florida Power & Light (FP&L) company experience during Hurricane Wilma in 2005.11 Prior to the hurricane, only eight percent of FP&L poles were inspected from 1999 to 2004, which suggests that the backlog of deteriorated poles was growing. However, during more typical weather conditions, the backlog remained invisible and FP&L experienced virtually no interruptions from pole failures.

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This all changed when most areas experienced winds ranging only from 75 to 95 mph, which was within the design capability of healthy poles. The hurricane damaged or toppled stands of 40 to 50 distribution poles at a time, and 98 percent of FP&L’s customers lost power. The company reported that pole failure was a key factor in the outages. As a result of the experience, the state utilities commission instituted a mandatory pole inspection program for all utilities in Florida. c. NWE’s Plan for Poles

i. Plan Features

After careful analysis and planning, as well as study of existing conditions, it has been concluded that a structured program, featuring accelerated inspection of existing poles and mitigation of the defective pole backlog, is appropriate. The sequencing of the program is planned as follows:

x 2011-12: Accelerated inspections and replacements as funding and resources permit, building the capabilities and processes for later high production rates.

x 2013-17: Ramp up accelerated inspections and replacement to complete 100% of the system in the remaining five years.

x 2018 and thereafter: A structured program with a 10-year inspection cycle and replacement rates adjusted as conditions warrant.

The expected impact of this sequence on pole replacement rates is illustrated on the accompanying chart. Note the two-year phase-in that leads to the capability for high production levels starting in 2013, when pole replacements should equal about 5,000 to 6,000 per year.12 This will result in a drastic cut in the inventory of defective poles, after which reduced inspection and replacement rates should be suitable to maintain stable levels.

The backlog reduction and replacement effort represents the lynch pin of the program, including the majority of the costs. However, such an effort is far from sufficient, with several other program features essential to the long term health of pole-related infrastructure. Additional features include:

x Replace all lodge pole pine poles that are found to be 55 years old or greater.

x Complete groundline treatment for every pole excavated for inspection.

ii. Scope and Rationale

aa. Pole inspection and replacement

The key to the NWE distribution pole challenge is reducing the inspection and replacement cycle. The length of this inspection cycle drives the following items:

x The number of poles to be replaced is driven by the number of poles inspected.

x The rate of reduction of the defective pole backlog, which is driven by the number of poles being replaced annually.

12

Note that this is the estimate for program poles, and excludes poles that will be installed for other reasons, such as new construction, accidents, etc.

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x The rate of getting groundline treatment in place to reduce future decay rates, which is driven by the number of poles inspected.

bb. Inspection Cycles

It is clear that a five percent inspection rate is no longer sufficient to stabilize the backlog. Utility planners are therefore faced with two key questions:

x What cycle is required to reduce the backlog of defective poles to reasonable levels?

x What cycle is required to maintain the backlog at those reasonable levels on a sustained basis?

NWE’s analysis produced answers of five and 10 years, respectively.

The five-year cycle with a two-year phase-in was chosen after considering many factors. First, the majority of the NWE poles (90 percent) are not defective, but the immediate need is to inspect and protect poles that indicate decay has set in at the groundline with fresh internal preservatives and a protective wrap (see Section iii below). This groundline treatment may extend the service life of the poles 25 to 30 years. Second, the backlog of defective poles will be eliminated quicker by this short initial inspection and treatment cycle.

The five-year cycle represents a quantum leap to a work level that is unprecedented for NWE. This represents a physical challenge in managing and executing the work efficiently as well as financial risk. In response, the plan includes a two-year phase-in, in which the organization’s performance and production capability can be built to meet the challenge and during which any regulatory and financial uncertainty can be resolved. The inspection cycle will be accelerated nonetheless in this period, allowing identification, planning and contracting for the much higher level of replacements starting January 1, 2013.

The subsequent 10-year cycle was also chosen after considering a number of factors, the most important being the mixture of pole species in service and the predominate decay conditions in the area. The objective is simply to maximize the economic benefits of the inspection cycle. A shorter inspection cycle will cost more per year. Will the additional benefits of life extension provide a payback? A longer inspection cycle will cost less each year. Will the savings be offset by a larger failure rate in the inspection cycle? Due to the long time frames involved, a utility will rarely have the data to answer these questions. The 10-year cycle is the most common cycle in the industry. If the failure rates for the first years of the 10-year cycle are low, the cycle can easily be extended.

At the beginning of the 10-year cycle each pole being inspected would have received groundline treatment if required. At that point the reject rates of the 10-year cycle are expected to be considerably lower than the present rates, especially for the Western red cedar poles. However, the number of extremely old lodge pole pine will keep the replacement rate at a high level for the next 10 years. Their average age at that time is estimated to be around 50 years old. This is well past their anticipated average service life.

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Overall, the total estimated number of lodge pole pines that would have been replaced by the pole inspection program in 15 years is 67,000, or 38 percent of the population. The purpose of a planned inspection program is to reveal and remove defective poles and to identify poles which are in the early stages of decay so that corrective action can be taken. The end result of the inspection program is the establishment of a continuing maintenance program for extending the average service life of all poles on the system.

cc. Proactive Replacement of Aged Poles

One new component of the pole replacement program is the active retirement of lodge pole pine poles that are found to be 55 years old or greater. Replacing the pole after a maximum age has been reached is a common feature of many utility pole replacement programs. The pole inspection program can only check the groundline of the pole. Once the groundline area of the pole becomes stabilized and the pole is able to become a senior member of the pole community, the decay conditions at the top of the pole will start to dominate.

Unfortunately, the top of the pole cannot be economically treated or readily inspected. Because the energized equipment is located in this area, it is a hazardous area to work in while the line is in service. Work in this area on an energized line can only be done from an insulated bucket platform with protective gloving and line sleeves. This is both hazardous and expensive.

The top of the pole has the end wood grain exposed. Over the years, this end grain will gradually wick moisture into the upper pole area and set up decay conditions. The bolt holes which mount the equipment to the pole top are also a source of moisture intrusion. Because these decay conditions cannot be prevented or readily observed, it is prudent to replace the pole once it has managed to exceed its anticipated life. A 55-year-old lodge pole pine would be 65 years old in the next inspection cycle. Therefore, 55 years was chosen as its replacement age. For the Western red cedar poles, it is anticipated that this pole species can last much longer once they have been groundline treated. At this time, no maximum age has been set for this pole type.

dd. Groundline Treatment

While poles can be inspected without excavating and retreating, this step adds considerable life to the pole. The average cost to inspect and, if necessary, groundline treat a pole averages $28. Poles less than 15 years old are visually inspected for decay. Poles greater than 15 years old are excavated and treated when required. This process involves excavating around the pole to a depth of 18 inches. After complete inspection and application of preservative treatment, a protective wrap is applied and the area around the pole is backfilled. The cost of the full excavation, groundline treatment and protective wrap is $51 to $64, depending on the internal decay treatments.

With proper application of groundline treatment and pole wrap performed on a regular schedule, the pole decay in this area can be virtually eliminated as the failure cause for wood poles. The weathering, splitting and decay of the pole top then become the limiting factor on the life of the pole. This pole top decay occurs at a much slower rate than the groundline decay.

A most important consideration in groundline treatment is once again the length of inspection / treatment cycles. The first cycle length of seven years (the two-year phase-in and the first

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complete five-year cycle) which was selected is particularly important. Obviously longer cycles will postpone pole replacement dollars at the safety risk of leaving defective poles in service for a longer period. The safety risk is that a pole will fall and/or lean severely without causing the line to become de-energized. A person or animal can then accidentally contact the line. This occurrence is the primary reason behind the National Electrical Safety Code requirement to replace the structures when they are below ⅔ of their original design strength. This safety risk has extremely high consequences, but it also has an extremely low possibility of occurrence. There is also an economic benefit in the consideration of the initial inspection cycle length. Because the poles have been untreated during their life, it is important to get as many treated as soon as possible to slow the decay rate. This will allow the pole to remain in service until the next inspection cycle rather than being replaced.

The length of the second inspection cycle is another important plan variable. For the decay zone that includes Montana, some recommended re-inspection cycles are up to 12 years. As the data of the second cycle inspections on poles becomes available, it will be possible to optimize this cycle length. The future reject rates after the initial treatment cycle will determine whether this cycle length can be increased.

iii. Production Estimates

The key production measures are contained in the following table. To the extent shortfalls occur in 2011-12, quantities in subsequent years will be adjusted, particularly in 2017.

iv. Alternate Strategies

The planning process that resulted in the pole replacement strategy discussed here was developed over an extended process that included consideration of a wide variety of options, from minimal and cheap to extensive and expensive. As in all planning work, the challenge was to begin with a clear set of objectives, identify options and then balance the good and bad features that inevitably materialize.

The priorities for the pole program should be rather clear from the four basic infrastructure program objectives, one of which is “reverse the trend in aging infrastructure,” and NWE’s vision for the future distribution system, which clearly cannot tolerate an increasing backlog of defective poles in service. In terms of aggressiveness, these demands seem to immediately put us in the top half of the response spectrum. To do less would simply slow, not reverse, aging, and would lessen the growth of bad poles, but not eliminate the backlog. An extensive effort would clearly be required – there would be no cheap way out. The challenge then shifted to optimizing

2011 2012 2013 2014 2015 2016 2017

Annual inspections 29,000 52,513 52,828 53,145 53,464 53,785 30,060

Defective poles identified 3,480 6,302 6,339 6,377 6,416 6,454 2,555

Defective poles replaced 3,180 3,480 6,302 6,339 6,377 6,416 6,454

Pole Inspection and Replacement

Excludes Proactive Quantities for Aged LPPs

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The optimization process focused on several key variables:

x The length of the initial inspection / replacement cycle, which can alternately be viewed as the time required to reduce the backlog of defective poles to stable levels

x The length of the steady state (long term) cycle

x The number of “good” (but really old) poles to replace each year

The easiest parameter to estimate is the steady state cycle length. It is also a “no consequences” estimate, because we will have a great deal of history before finally having to finalize that number. The thinking behind this strategy was explained earlier, but can be summarized here. Suffice it to say that a consideration of likely failure rates, applied to the forecasted pole population, suggested that a 10-year cycle would result in a backlog of bad poles that was both minimum and stable. This is not out of line with today’s typical industry cycle, which is 8.1 years. This replacement rate also reduces the average age of the inventory for a period.

The next choice to be made is the time to work off the existing backlog, and the logical starting point is the same 10 years. However, this is troubling, not because 10 years is a long time, but because the backlog is growing every year, in some ways creating a “chasing your tail” situation. While this is not necessarily a fatal flaw, the notion of a large backlog of bad poles in service, growing each year and sustaining for 10 years is not a pretty picture and may not be consistent with the vision of the future to which NWE is committed. A more aggressive option of five years emerged and garnered considerable engineering and planning support.

The final parameter, “good but very old” poles, perhaps contains the most flexibility in that there is little science to support a firm age target for a whole universe of poles. In the case of lodge pole pine, we have already concluded that the population is both vulnerable and aged. Getting them off the system would be a good thing, but at what price? We concluded that it was simply not economically appropriate to launch a full scale replacement, but a reasonable number that could be added to the defective pole replacement program without distorting the program made sense. An additional 1,000 poles per year meets this criterion, and an age of 55 or greater will translate to about 1,000 poles per year.

This brings us to a situation where a number of viable options are on the table and a more detailed economic analysis becomes both possible and appropriate. Eventually, the key decision-making event centered on two strategies:

1. An initial five-year cycle with subsequent 10-year cycles

2. A permanent 10-year cycle, both options including the proactive replacements of the “oldies but goodies”

The economic analysis considered the higher capital costs and lower maintenance costs associated with the five-year program and concluded that the more aggressive program would result in additional costs with a present worth of $18 million spread out over the next 15 years. In light of the technical concerns with the 10-year program, the relatively small customer impact spread over a long period and the consistency of the five-year program with NWE’s vision, it was concluded that the prudent choice from technical and economic perspectives was the five-year cycle followed by subsequent 10-five-year cycles.