wyoming office of consumer advocate 2012 …psc.state.wy.us/oca/assets/2011 oca annual...

WYOMING OFFICE OF CONSUMER ADVOCATE

2012 ANNUAL REPORT

REPORTING ITS MAJOR ACTIVITIES OF 2011

Governor Matt Mead

Bryce Freeman, Administrator

State of Wyoming

Office of Consumer Advocate

2515 Warren Avenue, Suite 304

Cheyenne, Wyoming 82002

Phone: (307) 777-7427

FAX: (307) 777-5748

Website: http://psc.state.wy.us/oca.htm

http://psc.state.wy.us/oca.htm

TABLE OF CONTENTS

REFLECTIONS OF A CONSUMER ADVOCATE .................................................................. 1

WHO WE ARE…MEET THE STAFF .................................................................................. 3

WHAT DOES THE OFFICE OF CONSUMER ADVOCATE DO? ............................................ 6

MAJOR ACTIVITIES INVOLVING ROCKY MOUNTAIN POWER ......................................... 8

Rocky Mountain Power -- 2010 – 2011 Rate Case ...................................................... 8

Rocky Mountain Power -- Class Cost of Service Collaborative .................................. 11

Rocky Mountain Power -- 2011-2012 Rate Case ...................................................... 12

Rocky Mountain Power -- Power Cost Adjustment Mechanism ............................... 13

Rocky Mountain Power -- Demand Side Management Program .............................. 15

Rocky Mountain Power -- Establishing the Avoided Cost Rate ................................. 16

Rocky Mountain Power -- Naughton Power Plant Environmental Investments ........ 17

Rocky Mountain Power Major Rate Proceedings since Inception of the OCA ........... 18

MAJOR ACTIVITIES INVOLVING CHEYENNE LIGHT, FUEL AND POWER ......................... 19

Cheyenne Light, Fuel & Power -- Approval to Construct a New Power Plant ........... 19

Cheyenne Light, Fuel & Power -- Natural Gas Rate Case .......................................... 21

Cheyenne Light, Fuel and Power -- Electric Rate Case .............................................. 22

MAJOR ACTIVITIES INVOLVING BLACK HILLS POWER AND LIGHT ................................ 25

Black Hills Power -- Approval to Construct a New Power Plant ............................... 25

MAJOR ACTIVITIES INVOLVING MGTC, INC. ................................................................ 27

MGTC, Inc. -- Natural Gas Rate Case ........................................................................ 27

MAJOR ACTIVITITIES INVOLVING QUESTAR GAS COMPANY ....................................... 29

Questar Gas Company -- Natural Gas Rate Case ...................................................... 29

MAJOR ACTIVITITIES INVOLVING TELECOMMUNICATIONS ......................................... 31

Wyoming Universal Service Fund Technical Conference and Follow-up Inquiries ..... 31

Wyoming Universal Service Fund Annual Proceeding .............................................. 33

Wyoming Universal Service Fund Appeal to the Courts ........................................... 34

TRANSMISSION PLANNING ........................................................................................ 36

The Western System ............................................................................................... 36

Regional Transmission Expansion Plan System ........................................................ 37

Energy Imbalance Market ....................................................................................... 40

Federal Energy Regulatory Commission (FERC) ........................................................ 41

INTERACTIONS WITH CUSTOMERS AND OTHER STAKEHOLDERS ................................ 43

Speeches, Presentations, and Discussions with Customer Groups ........................... 43

Responses to Inquiries and Customers Concerns ..................................................... 44

WORKING WITH OTHERS IN THE REGULATORY COMMUNITY ..................................... 45

ADDITIONAL RESOURCES ........................................................................................... 47

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SPLIT ROCK, WYOMING

REFLECTIONS OF A CONSUMER ADVOCATE

It has been nearly ten years since the OCA was created, so in this year’s annual report I’m going to take the opportunity to reflect not only on the activities of the OCA over the last year, but also generally on the work that we’ve done since 2003 to advance consumer interests in utility regulatory matters. It’s been a heck of ride and I am proud of the expertise and commitment that OCA has been able to provide to the utility rate setting process on behalf of Wyoming consumers.

During the ten years that the OCA has been in existence we’ve seen many changes, both in markets and in federal and state rules and regulations. When the OCA was created in 2003 the west was just coming out of the western power crisis that wracked electricity markets in 2000 and 2001. Gas prices were high and prices for wholesale electricity were relatively high as well. In 2004 and 2005, energy prices moved lower, only to rise dramatically again 2007 and 2008 as a result of storms and production losses in the Gulf of Mexico. Today, as a result primarily of the shale gas revolution, gas and electricity prices have stabilized at historically low levels. Yet, the challenges to maintaining affordable and reliable utility services to Wyoming customers are as urgent as ever.

Since its inception, the OCA has actively participated in hundreds of proceedings before the Wyoming Public Service Commission. We have also actively participated in matters before other state and federal regulatory agencies and industry associations. Our focus is always on ensuring that Wyoming utility consumers have access to safe and reliable service at affordable rates.

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We have been successful in meeting our commitment to Wyoming ratepayers. On average, our participation in Wyoming utility cases has resulted in utilities being granted approximately half of the revenue increase that they originally sought. Often we are successful in getting the utilities to accept a lower revenue increase than requested, which avoids the necessity of a protracted hearing and minimizes the cost of regulation. At the same time, we have closely monitored the service quality provided to Wyoming consumers and suggested strategies for maintaining and improving service quality. While we understand that utilities need to recover the cost of providing service to customers, we just want to make sure that what they are spending customer money on is necessary for providing safe and reliable service.

The year that has passed since I last had the privilege of providing this message has been an especially busy one for the OCA. During that time we have been involved in several important proceedings before the Commission. One of these cases, in particular, highlights the type of results that the OCA has achieved over its existence. Many of the other cases are described more fully in the body of this report.

In late 2010 Rocky Mountain Power filed a request to increase its rates by $97.9 million or about 17.3%. The OCA filed testimony recommending an increase of about $50 million. The OCA, the Company and other parties were ultimately able to reach an agreement that allowed Rocky Mountain Power to collect additional revenues of approximately $44 million, or less than half the amount originally requested by the Company. Instead of an increase of 17.3%, the stipulation among the parties resulted in an average increase of slightly less than 8% annually.

This is just one example of the public interest outcomes that I and my dedicated staff have been able to achieve on behalf of Wyoming utility rate payers since the OCA was created in 2003. Over that period the issues raised in utility filings have become increasingly complex and the filings more frequent. I expect that trend will continue in the future with new federal rules on emission limitations and other issues that will challenge the traditional model of providing utility services to customers. The OCA will continue to be at ground zero of these policy debates and we will continue to look for ways to ease the burden of an evolving regulatory policy environment on Wyoming utility consumers.

A final note is worthy of mention. We at the OCA have dedicated ourselves to our mission of advocating the best interests of utility consumers since 2003. I am proud of our record and what we have been able to achieve on their behalf over the intervening years, and I am anxious to undertake the hard work that will be required to meet the challenges that lie ahead. However, the legislation that created the OCA in 2003 will sunset in July of 2013. Without action by the legislature to either extend or repeal the sunset provision the OCA will cease to exist. I have every confidence -- based on recent developments -- the legislature will act to retain this important function on behalf of utility ratepayers and all citizens of the state. After all, an independent consumer voice in utility ratemaking matters has not been more important at any time in Wyoming’s history.

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BRYCE FREEMAN, Administrator

(307) 777-5742 [email protected]

Mr. Freeman has been the Administrator of the OCA since

its formation in 2003. He is trained in the areas of business administration,

mathematics, and statistics. He has more than twenty years of experience in his fields

of expertise which include utility regulation, property tax appraisal, utility valuation,

and capital costs. Mr. Freeman is a member of the Executive Committee of the

National Association of Utility Consumer Advocates (NASUCA) and is a member of the

NASUCA Electricity Committee. He is Treasurer of the Wyoming Infrastructure

Authority (WIA) and has been a continual member of the WIA Board of Directors since

his appointment in 2004. Additionally, he serves as a consumer representative on the

Scenario Planning Steering Group, an entity created to facilitate the development of a

Regional Transmission Expansion Plan.

DENISE PARRISH, Deputy Administrator


Ms. Parrish has more than 35 years experience in the area

of utility regulation. She has worked for the Michigan, Colorado, Arizona and Wyoming

utility regulatory commissions and the Arizona and Wyoming consumer advocate

offices. She has testified in more than 190 regulatory proceedings on a wide variety of

topics. She is a member of the National Association of State Utility Consumer

Advocates (NASUCA) Committee on Tax and Accounting and has had previously been

chair of the National Association of Regulatory Utility Commissioners (NARUC) Staff

Subcommittees on Accounting and Finance, International Relations, and Research and

Education. She is active in the regional, national and international regulatory

communities through virtual working groups and participation in meetings and

conferences. Her formal educational training is in accounting.

WHO WE ARE…MEET THE STAFF

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BELINDA KOLB, Ph.D., Rate Analyst


Dr. Kolb joined the OCA in mid 2011 bringing with her

two decades of training and experience in the fields of engineering, business, and

education. From 2000 to 2009, she taught college courses in business and finance.

Prior to 2000, Dr. Kolb gained industry experience as an engineer, insurance agent

and bond insurance financial analyst. She is a three time graduate of the University

of Wyoming – earning a Bachelor of Science degree in Civil Engineering, a Master

of Science in Business Administration, and a Doctor of Philosophy in Adult

Education. She is a member of the National Association of State Utility Consumer

Advocates (NASUCA) Committee on Gas. She has also been an active participant in

the Northern Tier Transmission Group Cost Allocation Committee.

The Senior Rate Analyst Postion held by Ms. Kimber Wichmann from October

2011 to October 2012 is currently vacant.

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CHRISTOPHER LEGER, Counsel


Mr. Leger joined the OCA in October 2012 as legal counsel

after having spent a number of years in private legal practice. During the course of his

legal career, he has participated in a wide variety of legal matters including criminal

cases, pharmaceutical litigation, employment law, estate planning, business formation,

and trademark and copyright protection. He also has legal experience with land rights

and title transfers related to the oil and natural gas industry. He is a graduate of the

Univesity of Wyoming College of Law and has a Bachelor of Science degree in Business

Management from the Univesity of Wyoming.

IVAN WILLIAMS, Senior Counsel


Mr. Williams has been involved in utility regulation in

Wyoming for more than twenty years. In 1990, he began as an intern rate analyst while

still completing his studies at the university. While still completing his studies, he was

offered a permanent position as a rate analyst, since he had already received a degree

in Accounting from the University of Wyoming. In 1995, after he completed his legal

training from the University of Wyoming, he took a position as an attorney on the Public

Service Commission’s legal staff having already gained practical experience as a

regulatory analyst. Mr. Williams has a wealth of knowledge regarding Wyoming utility

regulation based upon professional experience both as an analyst and as legal counsel.

He is frequently consulted about institutional history of cases before the Public Service

Commission. He is a regular participant in meetings and conferences of the National

Association of State Utility Consumer Advocates (NASUCA).

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WHAT DOES THE OFFICE OF CONSUMER ADVOCATE DO?

Statutory Authority

The Office of Consumer Advocate was created by the Wyoming Legislature in 2003 as an

independent division of the Public Service Commission. The Administrator is appointed by

and reports directly to the Governor. The OCA’s five other employees, each of whom has a

unique technical expertise, are hired by and report to the OCA Administrator.

Pursuant to W.S. § 37-2-401, the OCA is charged with “representing the interests of

Wyoming citizens and all classes of utility customers in matters involving public utilities.” In

many cases, the OCA is the only formal party who represents all of the impacted customers.

This role is often quite challenging and requires finding a balance of the interests of the

different types and sizes of customers.

In representing customer interests, the OCA is to consider all relevant factors. These factors

may change from case-to-case but according to W.S.§ 37-2-401, the OCA is always to keep

in mind “the provision of safe, efficient, and reliable utility services at just and reasonable

prices.”

Specifically, the OCA has been authorized to:

◦ Act as a party in any proceeding before the Public Service Commission, with the

same rights and subject to the same obligations and requirements as other parties

to the proceeding;

◦ Appeal actions of the Public Service Commission in accordance with other Wyoming

law and the Wyoming Administrative Procedures Act;

◦ Seek permission to appear as amicus curiae in any court proceeding in order to

accomplish the mandate of the OCA as specified in Wyoming statutes;

◦ Provide information and assistance to individual consumers regarding proceedings

within the jurisdiction of the Public Service Commission – while not permitted to

advocate for or on behalf of any individual, organization or entity; and

◦ Enter into stipulations with other parties to balance the interests of Wyoming

citizens and utility customers with the interests of the public utilities as a means of

minimizing the weaknesses of the adversarial process, improving the quality of

decisions in a highly technical environment, and minimizing the cost of regulation.

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Budget

The funding for the OCA is included as a separate portion of the budget of the Public Service

Commission. It is collected through a revenue-based assessment paid by public utilities,

and ultimately, the customers of the utilities. The total 2012-2014 biennium budget is

$1,927,320. For an example of how this assessment impacts consumers, recent

computations have determined that, on average, the cost associated with the existence of

the OCA increases a Rocky Mountain Power residential electric customer’s bill by about

$0.05 per month.

Seventy-one percent (71%) of the OCA’s budget is associated with the salaries and benefits

associated with six-full time employees. The cost of equipment, supplies, travel, and office

rent comprise about thirteen percent (13%) of the biennium budget with the remaining

sixteen percent (16%) available to supplement the existing employees’ expertise with

outside consulting services, as needed.

There has been no increase in the number of employees since the creation of the OCA in

2003. The number of full-time employees, including the OCA Administrator, remains at six.

Sunset Provisions

The current authorization of the OCA expires on July 1, 2013 without further legislative

action.

$1,367,781

$156,585

$101,104

$301,850

OCA 2012 - 2014 Biennium Budget

Salaries and Benefits Equipment, Supplies and Travel

Space Rental and Cost Allocations Outside Consulting Services

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MAJOR ACTIVITIES INVOLVING ROCKY MOUNTAIN POWER

ROCKY MOUNTAIN POWER -- 2010 – 2011 RATE CASE

Docket No. 20000-384-ER-10, Record No. 12702

On November 22, 2010, Rocky Mountain Power submitted an application to raise its

Wyoming retail rates in an amount that would result in an aggregate annual revenue

increase of approximately $97.9 million. The Rocky Mountain Power request was premised

on forecast or expected expenses, revenues, and investments for the 12-month period

ending December 31, 2011. If the full amount of the request had been authorized, rates

would have increased by an average of 17.3%. Ultimately, as a result of a settlement that

contained many terms and conditions, the resolution of the case resulted in an average net

customer rate increase of about 7.87%.

The issues in the case caught the interest of many different entities and individuals,

resulting in many more interveners than usually participate in cases before the Wyoming

Public Service Commission. The following were listed as interveners in the case: the Office

of Consumer Advocate (OCA), the Wyoming Industrial Energy Consumers (WIEC), QEP Field

Services Company (QEP), Granite Peak Development LLC, Interwest Energy Alliance, Cimarex

Energy Company, Kinder Morgan Interstate Gas Transmission LLC (Kinder Morgan), AARP,

the City of Casper, the Town of Bar Nunn, Natrona County, the Town of Mills, the Powder

River Basin Resource Council, the Town of Midwest, the United States Department of

Energy (DOE), the Utilities Workers Union of America, and Senator Cale Case.

The number of witnesses providing written direct and rebuttal testimony in this case was

unprecedented and spoke to the complexity of the issues in the proceeding. The OCA

provided evidence from four witnesses with the testimony touching on most of the topics

raised in the case. The topics discussed by the OCA included: the reasonableness of the

operating expenses, the prudence of the new capital investments, a recommended return

on equity, treatment of revenues from sales of renewable energy credits, system reliability,

allocating costs to the various customer classes, alternative rate designs, and appropriate

line extension policies.

Rocky Mountain Power offered the testimony of twenty-one witnesses to present its direct

and rebuttal cases. WIEC offered the testimony of seven witnesses. Cimarex, Kinder

Morgan and QEP together offered the testimony of one witness and AARP had a witness to

provide support for its positions. DOE offered yet another witness to support its position.

The Powder River Basin Resource Council offered two witnesses and the Utilities Workers

Union had its own witness in the case. Five witnesses provided support for the interests of

the City of Casper. One of the witnesses for the City of Casper also provided testimony on

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behalf of Granite Peak. Furthermore, concerns were provided by more than a dozen

members of the public at the public comment hearing.

The issues in the case were varied and wide ranging. As a response to the overall level of

increase sought by Rocky Mountain Power, the recommendations of the parties ranged

from an overall decrease of more than $500,000 to a net increase of approximately $50

million, considering all inputs to the overall required revenue. Specific items with which

parties took issue included: the treatment of revenue from the sales of renewable energy

credits; the level of wages, incentives and employee bonuses; the cost and use of the new

transmission investment; net power costs; the accuracy of the wind generation forecasts;

the appropriate return on equity; the cost of environmental retrofits to certain coal plants;

and on-going operating and maintenance levels.

The parties also had significant disagreement about the

amount of the increase to be paid by each of the

different customer rate classes. The OCA offered,

through its outside consultant, some alternative views

about how the costs should be spread among the

various customer classes. Many of these views

differed from the more common class cost allocations

that have been used in prior rate proceedings. Several

parties also offered their alternate views on the

optimum design of the rates themselves. Some of the

disagreements centered on the appropriate level of the

fixed monthly customer charge while others related to

the number of different rates that should be in place

for different usage levels. The appropriateness of the

line extension policy was also challenged.

Finally, there was quite a lot of concern expressed

about the reliability of service, particularly by the cities

and towns and Natrona County. While the City of

Casper provided the witnesses on the issue, reliability

was a common concern expressed by the various

municipal entities as part of their intervention in the

proceeding.

Given the level of controversy and contentiousness, it is astounding that a settlement was

achieved in this proceeding. The settlement that was approved by the Commission

contains the following key provisions:

I have never been involved in a case with so many

parties with such divergent views… Yet, here we are with a settlement

agreement pending approval before the

Commission…

I can personally vouch for the fact that all parties to

the Agreement made tough, gut wrenching decisions to get to this

point. But, I also believe that none of the parties

forsook their principles in signing on to the

Agreement …

Testimony of Bryce Freeman

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◦ Rocky Mountain Power was allowed retail rate increases totaling $44.6 million in

annual revenue. This net amount was derived through an increase in base rates of

$61.3 million offset by a credit of $16.7 million associated with projected revenue

from the sales of renewable energy credits and SO2 emission allowances.

◦ The investments associated with the new transmission line (known as the Populus to

Terminal line) and the environmental projects on the PacifiCorp power plants were

deemed to be prudent and used and useful and were included in the calculation of

the overall rate increase.

◦ Prior to beginning construction on any portion of three specifically identified pieces

of the Energy Gateway Transmission project, and for each specifically identified

environmental project located in Wyoming that is anticipated to have a total project

cost of $25 million or more, Rocky Mountain Power will file an application with the

Commission asking for a ruling on whether the proposed construction is reasonable

and in the public interest. If the Commission provides a positive response to the

application, the Parties agree not to challenge the prudence or cost recovery unless

there is evidence of mismanagement or the actual costs exceed the estimated costs

– at which point the excess costs are subject to prudence arguments. This provision

allows an earlier review of certain planned

investments than would normally be required.

◦ The Residential monthly customer charge

remained at $20 per month. Furthermore, the

two block residential energy charge was

designed to minimize the impact of the rate

increase on small users while giving larger

users stronger price signals about increasing

costs.

◦ The average rate increase to each rate group

differs based on the cost of serving that class

of customers. The key class increases are:

10.10% for residential, 9.54% for small

commercial, 3.71% for large commercial, and

6% to 10% for large industrial customers.

◦ Interested entities agreed to participate in a collaborative discussion about how to

allocate the costs of providing utility service to the various customer classes. An

attempt was to be made to agree upon a recommended methodology that provides

the most accurate and fair representation of the actual cost of service to the various

customer rate classes.

Based upon our extensive review of the record in this case, including the prefiled testimony, and the evidence presented at the hearing, the Commission finds, independent of the Stipulation itself, that the Stipulation results in just and reasonable rates.

Memorandum Opinion, Findings and Order Approving Stipulation

September 22, 2011

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The Collaborative also agreed that potential rate shock to one or more customer classes

that would result from most of the other alternatives considered weighed in favor of

retaining the current methodology.

◦ A capital improvement plan for the Natrona County, Wyoming area and its

communities was developed. Rocky Mountain Power also agreed to prepare a

written semi-annual service quality report for the Natrona County area.

Furthermore, a series of quarterly meetings were agreed to in order to address the

reliability and system improvements in Natrona County and its environs.

ROCKY MOUNTAIN POWER -- CLASS COST OF SERVICE COLLABORATIVE

Docket No. 20000-384-10, Record No. 12702 -- Follow-up

In 2011, OCA was an active participant in the collaborative discussions about how to

allocate the costs of providing utility service to the various customer classes. The

discussions looked at alternative methods and formulas relative to allocating generation,

transmission, and distribution costs. In order to bring in fresh ideas and to assure that the

appropriate expertise was brought to the issues being studied, the OCA hired an expert

consultant to assist in the examination of these cost-of-service issues.

Participants in the discussions were AARP, Cimarex Energy, City of Casper, Kinder Morgan

Interstate Gas Transmission, QEP Field Services, Rocky Mountain Power, Town of Bar Nunn,

United States Department of Energy, Wyoming Industrial Energy Consumers, and the

Wyoming Office of Consumer Advocate. The OCA was one of the key participants in the

collaborative because we had

recommended a number of changes to

the class allocations in the rate case –

recommendations that caused the

parties to want to further study the

allocation issues.

After months of study and four

meetings to discuss the issues and the

results of the various analyses, the parties reached an agreement as to the best way of

allocating different categories of costs to the different rate classes. The outcome of the

discussions is best stated in the October 31, 2011 Cost Allocation Collaborative Report to the

Public Service Commission:

After reviewing the results from the studies examined in the Collaborative process, the Collaborative determined that it is appropriate to continue to employ the methodology used currently for RMP [Rocky Mountain Power] for cost allocation in Wyoming…

The Collaborative could not reach a consensus that any individual or group of modifications to the current methodology is superior from an economic

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or policy perspective to the current methodology. However, the Collaborative did reach a consensus that the current methodology produces reasonable results that are in the public interest. While some of the other methodologies benefit smaller customers and others benefit larger customers, the Collaborative observed that the current methodology appears generally to produce a reasonable middle-ground result among the various alternatives considered. The Collaborative also agreed that potential rate shock to one or more customer classes that would result from most of the other alternatives considered weighed in favor of retaining the current methodology…

The OCA found the collaborative discussions to be very useful. The outcome was

verification that the process of class allocations that had been being used for several years

was the most acceptable outcome for the parties as a whole – even if an individual entity

may have recommended something different if left to their own devices and balance were

not important. However, a balance of all customer classes’ interests is important, and the

current allocation method was found to be the best means of attaining the desired middle

ground.

ROCKY MOUNTAIN POWER -- 2011-2012 RATE CASE


On December 9, 2011, Rocky Mountain Power submitted an application to increase its retail

electric service rates in order to increase its annual retail revenues by $62.8 million per

year. In support of its request, Rocky Mountain Power filed the direct testimony of

eighteen witnesses. Approval of the request would have resulted in an average increase of

10.4%.

The Rocky Mountain Power rate case was the fourth major rate case to be filed within a

three week period late in 2011. This was also the seventh Rocky Mountain Power general

rate case to be filed within a nine year period. The filing of this general rate case was no

surprise but did not change the rate case weariness that was beginning to occur for

Wyoming customers, the Commission, and the OCA.

This case involved fewer intervening parties and a narrower range of issues than the broad list of issues from the prior year’s rate case filing. However, there were still a number of complex issues that had to be addressed including:

◦ The appropriateness of Rocky Mountain Power’s gas hedging policies, ◦ The rate of return on equity to be included in the rate calculation, ◦ Forecast net power costs, ◦ The prudency of expenditures spent to meet environmental compliance standards,

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◦ Whether the wind generators are providing adequate and expected levels of production,

◦ The appropriateness of including certain capital costs related to future coal mine facilities,

◦ Cost issues related to the uncertain future of certain hydro generating facilities, ◦ The reasonableness of labor costs including employee incentives and benefits, ◦ An acceptable monthly customer service charge, and ◦ The appropriate rate level to apply to different usage levels. Nearly all of the activity related to this case occurred in 2012 and therefore will be more

fully described in next year’s activity report. However, the matter was satisfactorily and

creatively resolved with a settlement agreement that involves Rocky Mountain Power not

filing a general rate case in 2013. Instead, the 2011-2012 rate case resulted in a pre-set two

step increase with retail revenues increasing overall by $32 million beginning in October 22,

2012 and another $18 million effective October 1, 2013 as a result of the general rate case

itself. However, other provisions of the stipulation mitigate some of the impact of this

increase, especially in the first year, resulting in an average first year impact on customers’

bills of about 1.78%. The second year average impact of the general rate case agreement is

computed to be about 2.82%.

ROCKY MOUNTAIN POWER -- POWER COST ADJUSTMENT MECHANISM

Docket No. 20000-389-EP-11, Record No. 12777

Since March 2006, Rocky Mountain Power has had a rate mechanism in place that allows it

to recover changes in the cost of its power supply costs without the necessity of filing a full-

blown general rate case. For the first several years, it was referred to as the Power Cost

Adjustment Mechanism (PCAM). During the 2010-2011 timeframe, this rate mechanism

was reviewed and a different power supply cost rate mechanism was authorized in February

2011. The new mechanism is referred to as the Energy Cost Adjustment Mechanism

(ECAM) and has a different formula than the PCAM for computing the amount of the cost

change to be paid annually by retail customers – including a different incentive

arrangement for encouraging the utility to keep costs at as reasonable a level as possible.

However, there was the need for a transition from the PCAM to the ECAM in order to allow

for recovery of the last of the allowable costs that had been accumulated pursuant to the

PCAM arrangement. This transitional filing -- the last of the PCAM filings -- was submitted

on February 1, 2011. It sought to recover $15.9 million in net power costs that had been

expended by Rocky Mountain Power but for which it had not yet been compensated by

customers.

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As is its usual practice, the OCA intervened in this proceeding. The Wyoming Industrial

Energy Consumers (WIEC) also became a party to this matter. The Commission authorized

interim approval of the requested rate increase while the parties investigated the

appropriateness of the costs for which rate recovery was sought. The practice of interim

approval has been commonly used in conjunction with the PCAM to allow the Parties

adequate time to explore the issues with Rocky Mountain

Power while allowing timely recovery of these costs by

the utility. However, interim rates are still subject to all

of the usual procedural protections such as the

opportunity for Parties to protest the amount of the

increase and offer alterative recommendations in a

hearing, and the interim rates are subject to refund if

they are later found to be unjust or unreasonable by the

Commission.

Rocky Mountain Power filed testimony indicating that the

cost increases described in the application were driven by

a number of factors including less total hydroelectric

generation, less thermal generation availability, coal cost

increases, and impacts related to the cost sharing

mechanism among Rocky Mountain Power’s six states

related to the joint use of generation facilities. The OCA

filed testimony raising concerns about certain fines and

citations at the Rocky Mountain Power coal mine,

treatment of costs from prior periods, and recovery of

costs incurred relative to services for entities other than

the utilities’ own retail customers. WIEC raised concerns about several of the same issues

as the OCA and additional issues including matters related to the amount of wind

generation being produced at the wind generating facilities.

The Parties reached an agreement relative to the final amount of customer increases that

should result from the settlement of the case. This agreement was approved by the

Commission in a written decision issued in November, 2011. It authorized an annual

increase of about $13.6 million instead of the requested $15.9 million after taking into

account a number of the different recommendations offered by the OCA and WIEC. The

discussions in the case also raised a number of items that needed to be clarified in the

ECAM tariff that would take effect, and the Parties agreed to work together to resolve some

of these additional identified matters to try to eliminate confusion and interpretation

differences in future proceedings. The ultimately approved rates also incorporated the

overpayment that customers had made between April and November due to the difference

Until the Company’s application [regarding

specific wind integration costs] is resolved by FERC or

the courts, I see no choice other than to have

customers pay these costs from which they do not

benefit, have shareholders absorb the cost when the

Company has no choice but to provide system balancing

or to share these costs between customers and

shareholders. I recommend erring on the side of

customers.

Testimony of Denise Parrish

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between the interim and the final authorized increase, so that only the total of $13.6 million

would be paid over the entire one year rate period.

ROCKY MOUNTAIN POWER -- DEMAND SIDE MANAGEMENT PROGRAM

Docket No. 20000-383-EA-10, Record No. 12686

This matter provided an opportunity to review and investigate the current status of Rocky

Mountain Power’s energy efficiency and demand side management program. The OCA

became involved for that very purpose, and in the process recommended several measures

to improve the program. In its application, Rocky Mountain Power proposed a number of

changes to its initial program, primarily focused on increasing customer outreach and

communications, in order to improve participation in the energy efficiency and demand side

management activities. The Wyoming Industrial Energy Consumers (WIEC) and the

Southwest Energy Efficiency Project (SWEEP) also participated as interveners in the

proceeding.

Additionally, the application included a request to suspend the surcharge applied to

customers’ bills. This surcharge funds the energy efficiency and demand side management

programs, including customer incentives and administrative costs. Since the surcharge had

brought in more money than had been necessary to fund the program to date, due to less-

than-anticipated participation, there was no need to continue to collect the surcharge until

program participation increased. However, Rocky Mountain Power testified that customers

were continuing to benefit from the existence of the program, in spite of its slow start.

The OCA’s position was that it was too early to make a judgment about whether the

entirety of the program was and continued to be effective. In making that recommendation,

the OCA agreed with Rocky Mountain Power that the evidence showed the savings that had

been achieved to date were cost effective and provided benefits to both the Company and

its customers.

In its August 29, 2011 Order, the Commission determined that the surcharges should be

suspended and reinstatement would occur only after an application was filed and formally

approved. The Commission also approved the Rocky Mountain Power proposed program

changes. Finally, the Commission directed the filing of quarterly reports showing specified

information including monthly participation levels, energy savings, and cost data.

16 | P a g e

ROCKY MOUNTAIN POWER -- ESTABLISHING THE AVOIDED COST RATE


This matter involved an application of Rocky Mountain Power for approval to implement a

permanent method of computing its avoided cost rate for larger qualifying facilities. There

is a separate tariff and rate schedule for smaller non-utility power producers that wish to

sell power to PacifiCorp or Rocky Mountain Power (found at Rocky Mountain Power Tariff

37) that was not at issue in this proceeding. Instead, this proceeding addressed the amount

that larger independent power producers, such as industrial customers who produce more

power than needed for their own purposes, are to be paid for selling power to PacifiCorp.

The rate might also apply to independent companies who build wind generators and then

wish to sell the power to the utility. Pursuant to federal law, the rate is to be based on

avoided costs but the method of computing avoided costs is a state matter and differs from

state to state.

In an earlier proceeding, an agreed upon calculation method had been put into place as a

pilot program. Rocky Mountain Power was now seeking to implement the same calculation

method, with minor modifications, on a permanent basis. The suggested method

attempted to encourage the development of cost-effective qualifying facilities (or

independent power production) without creating subsidies for either existing or new retail

customers. Key elements of the methodology include looking at what would be paid to a

third party wind generator based on computed costs and assumed timing of PacifiCorp

building its own wind generators (which is the cost that would be avoided if someone else

were to build the plants instead) and payments to other (non-wind) power producers based

on the proxy calculation using PacifiCorp‘s costs and timing of building a combined cycle

combustion turbine generator using natural gas.

Along with the OCA and Rocky Mountain Power, other participants in this proceeding

included Wyoming Industrial Energy Consumers (WIEC), QEP Field Services Company, and

Interwest Energy Alliance. Interveners raised concerns about: specific elements of the

calculations, the need for some contract pricing terms flexibility, the number of years

contained within the purchase contract and the rate calculation, and the need for updated

sample calculations on a regular basis in order to maintain a fair and transparent process.

The OCA supported adoption of the Rocky Mountain Power proposed calculation, based on

its belief that the proposal accomplished the public interest objectives of assuring fair

avoided cost prices while leaving utility customers indifferent as to whether the generating

resource is provided by the utility or a third party.

On November 4, 2011, the Commission issued a written decision authorizing Rocky

Mountain Power’s avoided cost proposal to become permanent, with some changes

relative to clarification of the tariff language.

17 | P a g e

ROCKY MOUNTAIN POWER -- NAUGHTON POWER PLANT ENVIRONMENTAL INVESTMENTS


On September 16, 2011, Rocky Mountain Power submitted an application for a certificate of

public convenience and necessity (CPCN) to install certain environmental equipment on

Unit 3 of its Naughton power plant near Kemmerer, Wyoming. Specifically, authority was

sought to install a Selective Catalytic Reduction System and a Pulse Jet Fabric Filter System

in order to allow the plant to operate beyond December 31, 2014 in accordance with

federal law, standards set by the Environmental Protection Agency, and associated

requirements established by the State of Wyoming. In support of its application, the utility

indicated that it had performed numerous economic evaluations and studies and found that

the least cost / least risk option to comply with the environmental mandates was to install

the specified pollution control equipment.

Interveners to the proceeding included the OCA, the Wyoming Industrial Energy Consumers

(WIEC), Interwest Energy Alliance, and the Powder River Basin Resource Council. The initial

recommendations of the parties ran the gamut from

denying the requested authority (due to lack of

proper analysis) to not taking a position due to

concerns about errors and lack of supporting

evidence, to granting the certificate but placing

some additional risk of cost recovery on the utility.

In response to the positions of the interveners as

well as the precipitous drop in natural gas prices,

Rocky Mountain Power did some further analysis of

the cost effectiveness of the investment that it was

proposing to make to maintain Naughton Unit 3 as a

continuing coal generator. This additional analysis

showed that the planned environmental upgrades

were no longer viewed as being cost-effective.

Thus, the new proposal was to convert the unit to a natural gas generating facility that

would be used to help meet customer’s energy needs at peak periods. On May 11, 2012,

Rocky Mountain Power submitted a request to withdraw its original application for

authority to install the environmental controls related to on-going coal generation. This

withdrawal request was granted by the Commission in an order dated July 19, 2012.

…the Company’s modeling and

analysis in this case are just that, modeling and analysis.

While it can inform our judgment on these issues,

ultimately it is no substitute for reasoned consideration and interpretation of the

results.

Testimony of Bryce Freeman

18 | P a g e

Rocky Mountain Power Major Rate Proceedings since Inception of the OCA

Date of

Application

Revenue Increase (Decrease) Requested by Rocky Mountain Power --

Per Annum

Approved Rate Increases (Decreases) -- Per Annum

Effective Date

of Rate Change

General Rate Case 05/27/2003 $41,800,000 $23,000,000 03/02/2004

Net Power Cost Recovery

07/08/2004

$11,830,973

$9,250,000

09/15/2004

General Rate Case & Net Power Cost Recovery

10/14/2005

12/19/2005

$40,200,000

$16,094,510

$15,000,000 Plus an additional

$10,000,000

03/01/2006

07/01/2006


02/01/2007

$2,837,251

$2,857,252 (interim) Changed on

permanent basis to $2,500,000

04/01/2007

07/01/2007



02/01/2008

$31,020,000

$31,020,000 (interim) Changed on a

permanent basis to $28,864,416

04/01/2008

10/15/2008



01/30/2009

$23,900,000 Later corrected to a

request of $18,600,000

$7,070,000

04/01/2009

General Rate Case

10/02/2009

$70,918,825


$10,000,000

07/01/2010

02/01/2011


01/28/2010

($16,318,000)

($19,818,000)

04/01/2010



02/01/2011 $15,900,000 $15,900,000 (interim) $13,627,366 (final)

04/01/2011 11/01/2011

General Rate Case

12/9/11

$62,800,000


$18,000,000

10/22/2012

10/1/2013

19 | P a g e

MAJOR ACTIVITIES INVOLVING CHEYENNE LIGHT, FUEL AND POWER

CHEYENNE LIGHT, FUEL & POWER -- APPROVAL TO CONSTRUCT A NEW POWER PLANT

Docket Nos. 20003-112-EA-11 and 20003-113-EA-11, Record Nos. 12895 and 13007

In August 2011, Cheyenne Light, Fuel & Power

filed for approval to construct three natural

gas fired combustion turbine generators on

the southeast side of Cheyenne. The

estimated cost to construct these plants that

would have provided a total of 114 megawatts

(MW) was $158 million with a planned in-

service date of June 2014. The need for these

facilities was explained as being the growing

electric power needs of Cheyenne Light, Fuel

& Power customers and the upcoming

expiration of purchase power contracts. The

facilities to be constructed were also to

include a substation, a transmission line, a fuel

gas supply system, and ancillary equipment.

The OCA intervened in this matter but was

soon informed that the application was to be

replaced with a different application that

would seek approval of new generating

facilities for both Cheyenne Light, Fuel &

Power and Black Hills Power.

On November 1, 2011, a motion to withdraw the original application for construction of the

Cheyenne Light, Fuel & Power generating plants was filed simultaneously with the promised

updated application. This new application looked to use the same location to build some

generation for Cheyenne Light, Fuel & Power and some generation for Black Hills Power.

So, instead of three small generators totaling 114 MW at a cost of $158 million solely

owned by Cheyenne Light, Fuel & Power, the new application sought approval for one 37

MW combustion turbine owned by Cheyenne Light, Fuel & Power and one 95 MW

combined cycle generator jointly owned by Cheyenne Light, Fuel & Power and Black Hills

Power. As in the initial application, additional facilities would also need to be constructed

including a gas pipeline, a transmission line and certain common ancillary equipment.

Under this revised arrangement involving the two affiliated but distinct utilities, the net

estimated construction costs for Cheyenne Light, Fuel & Power was now estimated to be

about $135.7 million of the total project cost of about $237 million. So, the new

The Company has elected to construct the Facility to serve

its customers in lieu of purchasing power. Reasons for

this decision include price stability, regulated rate of

return approved by the Wyoming Public Service Commission, operational

benefits and security realized by utility owned generation, and because of the risks that

may be associated with purchased power.

From Cheyenne Light, Fuel & Power Application

20 | P a g e

construction arrangements were seen to be not only more cost beneficial for Cheyenne

Light, Fuel & Power but were also seen as providing more operational flexibility with better

fuel economy. However, the two generating unit plan does require Cheyenne Light, Fuel &

Power to provide part of is growing needs with some power purchases from the wholesale

generation market, rather than providing all of its growing needs from its own generating

plants.

As the only intervening party in the matter, the OCA thoroughly reviewed the application

for a certificate to construct the plants as well as the underlying planning documents that

purported to support the need for the shared generating facilities. Yet, the OCA continued

to have a concern about whether adequate supporting data had been provided for these

particular generating facilities. Of particular concern was the fact that the two utilities had

not conducted any joint planning of customers’ future power needs or the best way to meet

those needs. As discussions between the utilities and the OCA continued, the OCA

ultimately became convinced that the joint facilities did offer a reasonable least cost / least

risk opportunity to meet the future generation needs of both Cheyenne Light, Fuel & Power

and Black Hills Power, if certain protections were enacted. These additional protections are

detailed in the settlement agreement that has been approved by the Commission.

There are four primary provisions of the agreement among the OCA, Cheyenne Light, Fuel &

Power and Black Hills Power. These provisions address both planning and cost matters

related to the new generating units.

◦ The Parties agreed to engage in a study to evaluate the creation of a generation pool

for Cheyenne Light, Fuel & Power and Black Hills Power. They currently share

certain generating assets and have contractual agreements regarding the buying,

selling and dispatching of power from other individually owned facilities. A study

will be conducted to see if pooling existing and/or future assets would be more cost

effective for the customers of both utilities.

◦ A price cap of $222 million was established for the Cheyenne Prairie Generating

Station. This price excludes the normal financing carrying costs (often called

Allowance for Funds Used during Construction or AFUDC) since those costs will not

be capitalized as part of the overall agreement. The cap established a construction

cost that will be deemed to be prudent at the time that the utilities seek rate

recovery of the plant costs. Construction costs exceeding this amount are subject to

dispute at the time of the next general rate proceeding.

◦ The in-service date was pushed out in time a few months to October 1, 2014, in

order to lessen the cost impact to customers in 2014. This provision is subject to

verification that requiring purchases of market power during this few months delay

21 | P a g e

is not likely to actually cost customers more than if the plant were to enter service

earlier.

◦ The impact on customers’ rates of building these new facilities will phase-in prior to

the October 2014 in-service date. This will be done by allowing the cost associated

with financing the construction to be included in rates during the construction

period rather than being capitalized as part of the overall plant cost. This avoids the

usual situation of having ratepayers pay a return for the next several decades on

these initial financing costs. This provision required the filing of a separate

application which was reviewed separately from the construction certificate and was

ultimately approved by the Commission.

CHEYENNE LIGHT, FUEL & POWER -- NATURAL GAS RATE CASE

Docket No. 30005-157-GR-11, Record No. 13029

On December 1, 2012,

Cheyenne Light, Fuel &

Power filed a request to

increase its base retail

rates by an amount that

would have increased its

annual retail revenues

by about $2.6 million, or

about 6.7%. The OCA

participated as an active

intervener. Holly Frontier Refining was also a party to the case. There were a number of

items of disagreement that arose during the Parties’ investigation and review of the

application, although the issues in this natural gas rate case were far less complicated than

the issues in the concurrently filed Cheyenne Light, Fuel & Power electric rate case. These

matters of controversy included: the appropriate rate of return to be utilized in establishing

rates, the appropriate level of expense to be paid by ratepayers – particularly the expense

of filing the rate case itself, the appropriateness of allocating the costs to each of the

customer classes, and proper mix of flat customer charges and volumetric based usage

charges.

One of the most controversial matters in the case focused on the appropriate return on

equity. When an analyst makes a recommendation regarding an appropriate return on

equity, it is generally based on investor expectations – something that is derived through a

mix of analysis and judgment. The recommendations in this case were widely varied, with

AUDIT OF CHEYENNE LIGHT, FUEL & POWER RATE CASE IN RAPID CITY

22 | P a g e

more than fifteen sets of analytical results offered by the three expert witnesses providing

testimony on the matter of the appropriate return. The reasonable ranges of the three

experts included a low of 6.18% and a high of 11.5%, with several recommendations in-

between. The OCA’s reasonable range was 6.18% to 9.85% with an initially recommended

return on equity of 9.25%. Ultimately, as part of the overall settlement of this rate case, the

Parties agreed to the use of a return on equity of 9.6%. This was a significant decrease from

the original request of Cheyenne Light, Fuel & Power of 10.9% and the lower authorized

return on equity had a large impact on the overall amount of revenue increase granted.

Cheyenne Light, Fuel & Power originally requested an increase in revenues of about $2.6

million while the OCA originally recommended about $1.7 million. In the end, the Parties

agreed to an increase in natural gas base revenues of about $1.64 million based on updated

and corrected information related to growth, expenses, and investment.

Another major issue in the proceeding involved the determining of how the authorized

revenues should be billed to customers. There were multiple views on how much of the

revenues should come from the flat monthly service charge and how much should come

from the rate associated with each dekatherm used. The final agreement made only small

changes to the monthly customer charges. Further discussions are to be held before

Cheyenne Light, Fuel & Power’s next general rate proceeding to allow for a better analysis

of the costs to be assigned to each class and the costs to be recovered from each rate

element of the rates.

CHEYENNE LIGHT, FUEL AND POWER -- ELECTRIC RATE CASE


Concurrent with the filing of its natural gas rate case, Cheyenne Light, Fuel & Power filed a

request to increase its retail electric rates by an amount that would have resulted in an

additional $5.9 million of annual retail revenues. If the original request had been

authorized, it would have increased annual

base revenues approximately 5.9%. The

Cheyenne Light, Fuel & Power natural gas

rate case, described above, and the

Cheyenne Light, Fuel & Power electric rate

case were worked together, as many of the

issues – such as the allocation of common

costs – needed to be coordinated and

resolved in a consistent manner. However,

there were more contested issues in the

WORKING ON THE CHEYENNE LIGHT, FUEL & POWER RATE CASE

23 | P a g e

electric case as well as issues that were more complex and more difficult to understand

than the relatively straightforward issues of the natural gas case. The OCA, Holly Frontier

Refining and Dyno Nobel were all active Parties in the proceeding with each filing testimony

raising numerous concerns. The disputed issues included, but were not limited to: the

anticipated new and expanding load of Cheyenne Light, Fuel & Power customers, the

recommended return on equity, the appropriate level of generation-related costs and

revenues, the necessary level of costs related to filing the rate case, the fuel and purchased

power costs sought to be recovered through the base rates (rather than rate surcharges),

the appropriate costs to be assigned to each customer rate class, which industrial

customers should be classified into a unique rate group, and how future rate surcharges

associated with the costs of fuel and purchased power should be calculated.

The initial positions of the Parties again covered a wide spectrum. Cheyenne Light, Fuel &

Power initially sought an increase for its electric operations of about $5.9 million, reducing

its request to $4.6 million by the time it filed its rebuttal testimony. Dyno Nobel and Holly

Frontier jointly recommended a rate decrease of $2.9 million. The OCA recommended a

rate increase of about $1.65 million. Additional discussions among the Parties greatly

helped clear up many misunderstandings that had originally existed, allowing a greater

meeting of the minds with an agreement ultimately being presented to the Commission. In

approving the agreement of the Parties, the Commission granted a per annum increase in

Cheyenne Light, Fuel and Power’s

base electric revenues of

approximately $2.7 million, or less

than 50% of Cheyenne Light’s original

request.

The resolution of this case also

resulted in several other notable

changes. The two largest customers,

Dyno Nobel and Holly Frontier, were

moved into their own rate class. Yet,

for purposes of resolving this case,

these two customers will continue to

pay more than the cost of providing

them service, even though the

combined revenues paid by these two

large customers will be less than in

the past.

Additionally, the Parties agreed that

further study would be useful relative

Overall, the Commission finds the Stipulations, with supporting

stipulation testimony of Parrish, Kirkpatrick, White, and Iverson, to be well-documented explanations

of how the parties proposed to resolve the numerous issues in this case… The Commission notes that

stipulation testimony of good quality is, as here, useful for

understanding the details and methodology that went into

reaching an agreement.

Memorandum Opinion, Findings and Order Approving Stipulations

September 28, 2012

24 | P a g e

to assigning costs to the various rate classes to determine the amount of revenue that

should come from each group of customers (e.g., residential, commercial, industrial, and

lighting). Therefore, agreement was reached to have a collaborative process where

technical allocation methodologies will be discussed (similar to what was done for Rocky

Mountain Power) in an attempt to reach an agreement to be incorporated into upcoming

rate cases. These discussions will also include any information available from the new

advanced meters and data management system.

Lastly, there was a change to the method of computing the Power Cost Adjustment. This

provision relates to a surcharge or credit that appears on customers’ bills to address

significant cost increases or decreases in the costs of generating or purchasing electricity.

The computation method at the time of the case included a $1 million deadband (meaning

that if costs changed by $1 million or less, there would be no rate change) and a sharing of

the cost changes with 95% assigned to customers and 5% assigned to shareholders. This

was changed in an attempt to provide additional incentives to keep costs as low as

reasonably possible, and to bring shareholder interests into the picture to a greater extent.

The new formula eliminates the deadband and changes the sharing arrangement to 85%

customers and 15% shareholders.

FROM THE DRIVE BETWEEN RAPID CITY AND CHEYENNE – RETURNING HOME FROM AUDIT OF CHEYENNE LIGHT RATE CASES

25 | P a g e

MAJOR ACTIVITIES INVOLVING BLACK HILLS POWER AND LIGHT

BLACK HILLS POWER -- APPROVAL TO CONSTRUCT A NEW POWER PLANT


As part of a joint application with Cheyenne Light, Fuel and Power, which is described in the

an earlier section of this report, Black Hills Power filed a request for a certificate of public

convenience and necessity to build new generating facilities to be known as the Cheyenne

Prairie Generating Station. This request was based on Black Hills Power’s integrated

resource planning process that showed it will be replacing some of its existing generating

resources in order to comply with regulations of the Environmental Protection Agency.

Black Hills found that it would not be cost effective to upgrade some of its existing

generators and therefore is proposing to replace them with new generation shared with

Cheyenne Light.

Black Hills sought approval of a 58% share of a 95 megawatt combined cycle gas fuel

generator. Its share of the combined facilities is estimated to be $101.3 million with an

estimated in-service date of mid-2014. The application explained that the benefits of

sharing facilities with Cheyenne Light, Fuel & Power outweighed any detriments of not

locating the new plant closer to the Black Hills Power load in South Dakota and northeast

Wyoming.

BLACK HILLS POWER CORPORATE OFFICE SIGN IN RAPID CITY, SOUTH DAKOTA

26 | P a g e

As noted earlier in this report, the OCA had a number of concerns about the proposed

generating facilities. In particular, the OCA’s concerns related to the fact that Cheyenne

Light, Fuel & Power and Black Hills Power had individually studied their customers’ future

resource needs and the best options for meeting those needs, without having a combined

study to see if some additional efficiencies might be obtained through a combined

generating resource. Additionally, the proposed plant assets were to be individually

assigned to one of the utilities or the other, even though both stated that they would

benefit from sharing the common facilities. There appeared to be a series of mismatches

among the different pieces of the planning process, with the result being uncertainty as to

whether the proposed construction plan was actually supported by the planning process.

The OCA’s concerns were mitigated by the provisions of a stipulation and agreement

entered into by the Parties. Specifically, significant effort will be put into a study to see if

pooling the generation assets of Cheyenne Light, Fuel & Power and Black Hills Power might

be beneficial to the customers of both utilities. Additional protections were also agreed to

including a construction price cap for purposes of determining the prudent cost of the

construction. Finally, some non-traditional rate methods were offered in order to try to

smooth the construction cost impacts on customers’ bills.

SUNSET IN NORTHEAST WYOMING

27 | P a g e

MAJOR ACTIVITIES INVOLVING MGTC, INC.

MGTC, INC. -- NATURAL GAS RATE CASE

Docket No. 30003-52-GR-11; Record No. 12840

In May 2011, MGTC, Inc. filed an application requesting an increase in annual retail gas

revenues of $486,936, equating to a 28.5% increase. It had been 22 years since MGTC’s last

general rate case. MGTC explained in its application that it was sorely in need of a rate

increase given that its current earnings were far below its last authorized earnings level and

that if significant new investments were to be put into the system – and there was a dire

need for new investment – its needed rate increase would be quite significant.

Furthermore, MGTC explained that it needed to restructure its rates in order to eliminate

incentives for industrial customers to migrate to lower priced services whose prices had

become outdated and

unreasonable with the

passage of time. However,

given the small size of its

system, with approximately

500 customers, it hoped to

keep the support for its case,

as well as the resulting rates,

relatively simple.

Three entities intervened in this proceeding: the

OCA, SourceGas Distribution LLC, and GARCO

Energy. All three entities provided witnesses in

the proceeding raising a myriad of issues and

concerns. The OCA initially recommended an

overall revenue increase of about $46,000 and

offered a different rate design proposal than the

one suggested by MGTC. Furthermore, the OCA

recommended that a master pipeline

replacement plan be provided since MGTC

continued to have about 60 miles of pipe above

ground. The OCA also opined about the various

capital improvement projects that MGTC was

proposing and recommended that each of the

PORTION OF ABOVE GROUND PIPELINE -- SOUTH ROZET TO ROCKY POINT

Again, in the interest of safety for all stakeholders, I

recommend that MGTC immediately heighten their

accountability to their previously stated long term objective of replacing above ground pipeline by adopting

and implementing the provisions of a well crafted

five year master plan.

Testimony of Dr. Belinda Kolb

28 | P a g e

projects were reasonable for inclusion in the development of customers’ rates. SourceGas

proposed an overall revenue increase of about $155,000 and provided yet an additional

rate design proposal. GARCO raised concerns about the impact of the rate proposals on its

costs. In its rebuttal, MGTC modified its requested increase to about $285,000.

As is the OCA’s normal practice, discussions continued about the issues in the case even

after direct testimony and rebuttal had been filed. The discussions allow the Parties, at

best, the opportunity to continue to work toward a jointly agreed to resolution of the

identified issues and at least the opportunity to better understand the positions of the

other Parties. In due course, the Parties were able to reach a mutually agreeable

settlement of the issues in the case. The Commission approved the settlement but not

without some additional provisions being added to address some of its own concerns that

were different than those identified by the Parties.

Pursuant to the terms of the settlement, MGTC was granted an annual increase of

$254,660, or 14.9%. Based on a mix of technical cost allocation studies and rate mitigation

principles, the rate increases were distributed in such a way that no increase was assigned

to the general service (residential and commercial) customers. The entire increase was put

on the firm transport customers (customers who purchase their own commodity and use

the MGTC system simply to deliver that natural gas to their locations). A new class of large

firm customers was created to address the fact that SourceGas is a huge customer

compared to the other transport customers. MGTC also agreed to provide a future

construction plan on or before March 30, 2012.

As to the additional issue not addressed in the Parties’ agreement, the Commission found

that MGTC should have obtained certificates of public convenience and necessity for two of

the system improvement projects prior to beginning construction. Specifically, the

Commission directed that certificate authority be sought and obtained for (1) the

replacement of 11 miles of four-inch above ground pipe with 11 miles of six-inch pipe since

the new line will operate at over 500 psig and (2) the Hannum line that involves the

installation of a new line to loop the northern part of MGTC’s system into SourceGas’

system in the Gillette area since the Commission found this to be a transmission line, rather

than a distribution line. The Commission approved the rate settlement on an interim basis

pending the certificate filings for these two capital projects.

29 | P a g e

MAJOR ACTIVITITIES INVOLVING QUESTAR GAS COMPANY

QUESTAR GAS COMPANY -- NATURAL GAS RATE CASE

Docket No. 30010-113-GR-11, Record No. 13023

On November 21, 2011 Questar Gas

Company filed an application

requesting approval to increase its

non-gas revenues by an annual amount

of $1,002,832, or approximately 8.67%

of base, non-commodity revenues. The

rate request was driven primarily by

the amount of new capital investment

that had been made in system assets,

particularly in the Kemmerer and

Diamondville service area. This new

investment meant that Questar was no

longer able to earn what it believed to

be a fair and reasonable return on its

utility investment.

Additionally, the rate request was filed to address the end of a three year pilot program

regarding a Conservation Enabling Tariff. The Commission had directed that a rate case be

filed at the end of the pilot period so that it could evaluate the program’s performance

before authorizing it on a permanent basis. This controversial rate provision allows an

adjustment to customers’ bills between rate cases to recognize the difference between

authorized and billed revenue levels. Its stated purpose was to eliminate any disincentive

to encourage conservation that existed by breaking the tie between sales volumes and

revenues.

The OCA was the only intervener in this rate case. During the audit and review of the

matter, the OCA asked a number of questions that resulted in corrections and minor

modifications to the original application and rate request. These included matters related

to depreciation reserves, forecast plant retirements, cost allocations, contributions-in-aid of

construction, and construction work in progress balances. The OCA spelled out these

changes in its testimony, and in its rebuttal Questar accepted these changes without much

controversy. These changes, when combined with the OCA’s recommended return on rate

base, resulted in an OCA recommended rate increase of $372,167, or 3.41%.

OCA AUDIT OF QUESTAR GAS RATE CASE IN SALT LAKE CITY

30 | P a g e

The more contested parts of the proceeding related to: (1) the return on equity that should

be authorized, (2) the rate structure that should be approved and how the data is used to

develop that rate structure, (3) the continuation of the Conservation Enabling Tariff and (4)

the proposed changes to the Questar facility extension policy. Each of these items was a

disputed matter before the Commission. A settlement was not reached and the disputed

items were resolved by the Commission following a hearing held on May 14, 2012. The

Commission’s decision is spelled out in its Memorandum Opinion, Findings and Order issued

September 20, 2012.

The most hotly contested issue in the case related to the return on equity that should be

utilized in the rate computation. Questar sought a return on equity of 10.25% after

presenting a wide series of analytical model results that ranged from 6.87% to 11.19%. The

OCA recommended a return on equity of 8.4%, after presenting a range of reasonableness

of 6.72% to 8.97%. Based on an extensive analysis of the evidence regarding Questar’s

business risk, the potential for inflation, the utility’s credit rating, growth rates, and other

relevant factors, the Commission found that the appropriate return on equity should be

9.16%. This decision led to an authorized increase in annual revenues of about $796,000.

There was also a dispute between Questar and the OCA about the rate structure that

should be put into place. Both parties began with Questar’s cost of service study but the

OCA identified some minor improvements. There was also some dispute as to what the

basic monthly service charge should be, although the basic structure of establishing service

rates based on meter size was not part of the disagreement. The primary dispute was in

regard to whether the usage based charge should decrease with increased usage (a

declining block rate) or whether there should be a single usage rate, as proposed by the

OCA. The Commission determined that declining block proposal better matched the costs

of providing service over a wider range of usage.

As to the Conservation Enabling Tariff, the OCA argued that Questar had not provided

adequate support to justify continuance of the program. The Commission disagreed with

the OCA finding that the approval was consistent with the Commission’s policy of approving

reasonable decoupling mechanisms proposed by natural gas distribution companies.

The final major dispute in the case related to Questar’s proposed changes to its facility

extension policy. The OCA raised a number of concerns, primarily about the lack of clarity

of the language and subsidies from existing customers to new customers. With the changes

adopted in the rebuttal testimony and the lack of on-going OCA objection, the proposal was

approved. However, the Commission agreed that further improvements may be warranted,

and directed that this provision be reviewed in Questar’s next rate case.

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MAJOR ACTIVITITIES INVOLVING TELECOMMUNICATIONS

WYOMING UNIVERSAL SERVICE FUND TECHNICAL CONFERENCE AND FOLLOW-UP INQUIRIES

On December 7, 2010, the Wyoming Public Service Commission held a technical conference

regarding the Wyoming Universal Service Fund. At this meeting, the Commission

specifically identified five policy issues and invited anyone interested the opportunity to file

written comments. The five topics identified are:

◦ What constitutes an essential service line? Does a service line only meet the

definition of being an essential service if it has no other add-on services and is

essentially dial tone only? Does the fact that the entire cost of the switch was

included in the cost determination, including costs and features for extra services,

change what is considered to be an essential service line?

◦ How should bundled services be taken into account when computing the amount of

support to be provided from the Wyoming Universal Service Fund?

◦ Should there be one consistent method utilized by each of the telecommunications

companies for reflecting on customers’ bills the federal universal service funds

received?

SIGN IN MOUNTAIN VIEW, WYOMING

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◦ Should there be a more consistent treatment, relative to the calculation of the

Wyoming Universal Service Fund support, of wireless versus landline services, how

should voice over the internet services be incorporated into the calculation, and

how does broadband fit into the Wyoming Universal Service Fund calculations?

◦ Is the current method of distributing Wyoming Universal Service Funds

competitively neutral, or does it either inhibit or promote competition? Also, is

affordability still a goal of the Wyoming Universal Service Fund given the state of

competition?

On January 4, 2011, the OCA filed a comprehensive set of comments in response to the

issues identified at the technical conference. In preparing our comments, we took a step

back from our traditional thinking to reexamine the issues from different vantage points.

Some of the questions raised by the Commission had not previously occurred to us, while

the answers to others appeared obvious to us but not to others. Therefore, we took this

opportunity to fully examine the issues from different vantage points and based on

different interpretations of the existing statutes.

While we were unable to offer a definitive position on each and every question that the

Commission had raised, we did try to provide as much information as possible that spoke to

the issues. Some of the conclusions we offered included:

◦ If a strict interpretation of what constitutes an essential service line is used in the

Wyoming Universal Service Fund calculations, it could have a deleterious effect on

customers, particularly those customers in high cost / high priced service areas. This

could cause these customers to have to choose between affordable plain old

telephone service and the convenience of certain add-on services, but not allow

some customers to have both.

◦ It is difficult to reconcile a price-based support fund with barely regulated prices in a

market that is quite competitive in many, although not all, locations in Wyoming.

◦ The calculations of the support from the Wyoming Universal Service Fund are based

on the prices for essential telephone service, but most customers take service that

includes more than just dial tone. There is no obvious answer to the issue of how to

disaggregate the individual piece-parts of services contained within a bundle.

◦ Moving all telecommunications providers to the same method of incorporating

federal universal service funds into the customers’ bills is not necessary but if a

change is desired, the method used by CenturyLink and Qwest (now also part of

CenturyLink) is more transparent in showing the federal support as part of the final

bill to customers.

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◦ The OCA is satisfied that the current practice of excluding wireless lines should

continue to be the practice relative to calculating the distribution of Wyoming

Universal Service Funds.

◦ The Wyoming Universal Service Fund is generally administered in a competitively

neutral manner.

A number of other entities also provided comments in response to the technical conference

including Qwest, AT&T, Tri-County Telephone and TCT West, the Range family of

telecommunications companies, and CenturyLink.

The issues identified by the Commission and the responses provided offer a foundation for

future discussions about changes to telecommunications laws that may need to be

implemented to recognize the changes to the telecommunications industry that have

occurred since the enactment of the existing telecommunications statutes.

WYOMING UNIVERSAL SERVICE FUND ANNUAL PROCEEDING

Docket No. 90072-36-XO-11, Record No. 12814

On April 1, 2011, pursuant to Section 500(k) of the Procedural Rules and Special Regulations

of the Wyoming Public Service Commission, the Wyoming Universal Service Fund manager

filed a report with the Commission containing his calculations of the assessment and

funding benchmark for the upcoming fiscal year. Per its normal practice, the Commission

opened a docket regarding the matter and set a “hearing” to determine: (1) the assessment

factor to be applied to customer bills to fund the support to be provided in high rate areas,

(2) the associated 130% support benchmark for the 2010-2011 fiscal year, and (3) the total

level of support which will be provided to qualifying telecommunications companies. The

manager filed an amended report on April 21, 2011, which contained revised calculations

but did not change the recommended assessment level.

The OCA filed its Notice of Intervention, in this matter, on April 29, 2011. Consistent with its

prior actions in previous Wyoming Universal Service Fund proceedings, the Commission

“denied” this Notice of Intervention based upon its conclusion that the proceeding was not

a contested case, but rather a “legislative” proceeding which does not require the

observance of certain procedural due process rights. On April 7, 2011, the Commission

denied the OCA access to the confidential version of the manager’s initial and amended

reports as well as the underlying confidential source data.

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On April 29, 2011, the OCA filed comments which cited continuing concerns regarding 1) the

accuracy and appropriateness of the reported line counts associated with essential services;

2) the price associated with the essential service portion of packaged services; and 3) the

treatment of incremental Federal Universal Service Funds within the Wyoming Universal

Service Fund calculations. These comments were limited in nature given the OCA’s lack of

access to the confidential data associated with the calculations.

On May 4, 2011, the matter was heard by the Commission. In addition to presentations by

the OCA and Qwest, comments were also provided by representatives of Union Telephone

and the Range Companies. The Fund Manager also presented a summary of his amended

report which contained a calculated statewide average rate of $25.76, an associated

support benchmark of $33.49, and a recommended assessment level of 1.2%. The manager

also offered an alternative recommended assessment level of 1% based upon a

recommendation that Quest be required to draw its monthly WUSF support for the

upcoming fiscal year from its alleged Federal Universal Service Fund reserve.

On May 6, 2011, the OCA filed supplemental comments which addressed the alternative

recommendations which were made by the manager at the May 4, 2011 “hearing.” In these

supplemental comments, the OCA opposed the alternative recommendation of not paying

Qwest (now CenturyLink) its calculated monthly draw from the Wyoming Universal Service

Fund due to its alleged Federal Universal Service Fund reserve.

On May 9, 2011, the Commission approved the manager’s amended report. An order

implementing the recommendations contained within it was issued on May 13, 2011.

Given the pending consolidated appeals of the Commission’s prior two years’ Wyoming

Universal Service Fund orders, no “party” to the proceeding pursued an additional appeal.

WYOMING UNIVERSAL SERVICE FUND APPEAL TO THE COURTS

As referenced in previous annual reports, the OCA appealed the Commission’s decision

regarding the 2009 Wyoming Universal Service Fund proceeding. Subsequently, Qwest

(now CenturyLink) appealed the Commission’s decision regarding the 2010 Wyoming

Universal Service Fund proceeding. These appeals were consolidated by the First Judicial

District Court.

On October 31, 2011, oral arguments were held, with regard to the consolidated appeals of

the Commission’s 2009 and 2010 Wyoming Universal Service Fund Orders (First Judicial

District Docket No. 176-199). A decision was issued by the Court on March 28, 2012. While

35 | P a g e

the Court scrutinized the statutory construction issues identified by the OCA, it ultimately

disposed of the case based upon other grounds. Specifically, the Court determined that

Qwest (now CenturyLink) had adequately demonstrated a protected property interest

which entitled it to a contested case proceeding. Accordingly, the Court remanded the case

to the Commission for further proceedings consistent with its order. The Commission filed

an appeal of the decision with the Wyoming Supreme Court.

While in complete agreement with the result, the decision placed the OCA in a somewhat

perilous position. Specifically, under the terms of the analysis conducted by the Court, the

OCA may not be able to demonstrate a similarly protected property interest even though it

is statutorily charged to represent customers who pay into and receive support from the

fund. This ultimately renders the OCA’s right to intervene and request a contested case type

of hearing uncertain. The OCA has, through briefs, placed the statutory construction issue

before the Wyoming Supreme Court. The briefing schedule has concluded and the matter is

scheduled for oral argument on November 28, 2012.

At the District Court Level, the PSC argued that the OCA lacked statutory standing to

challenge its decisions with regard to the Wyoming Universal Service Fund. The Court

specifically found that the OCA, by virtue of the express provisions of W.S. § 37-2-402, has

such standing.

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TRANSMISSION PLANNING

THE WESTERN SYSTEM

As described in previous editions of this report, the OCA continues to be an active

participant in regional and national forums regarding electric generation and transmission

planning. The western electric transmission system is a vast array of substations and

transmission lines interconnecting virtually all local electric distribution areas and

generation resources. Transmission lines interconnected to the interstate transmission

system range in size from the largest 500 kilovolt direct current lines down to 115 kilovolt

alternating current lines. These transmission lines connect sources of generation such as

coal, gas, wind and others that are frequently located in areas remote from the load centers

where the power is used. In Wyoming, for example, several large coal fired power plants,

such as Rocky Mountain Power’s Jim Bridger power plant located near Rock Springs and

Basin Electric’s Laramie River Station located near Wheatland, are located in remote areas

and large transmission lines are required to move the generation to population centers

where the power is needed.

Fortunately, since the transmission grid functions as one large synchronous machine with

thousands of interconnections, it is easier to share resources to keep the system in balance.

This is important since investments in generation and transmission infrastructure are

typically large so sharing those investments and optimizing their use helps keep costs down

for all customers.

The western transmission system

has evolved over a period of

decades with the majority of the

lines being put into service 30 to

40 years ago. This system was

designed to carry power from

large base load generating plants,

primarily coal, to distant load

centers and it has performed

admirably for that task. However,

over the intervening years loads

have continued to grow and the

type and location of electric

generation resources has

continued to evolve. Under these

circumstances it is imperative to

not only continuously plan for

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necessary new generation and transmission infrastructure but to also determine how best

to adapt the existing transmission system to new uses.

To some extent the existing transmission system is burdened by its legacy design and

operation. For instance, even though it is a synchronous system it is divided into multiple

balancing authorities, each charged with balancing the loads and resources within its

boundaries. This makes it difficult for an individual balancing area to call on available

generation in other balancing authorities for balancing purposes. Additionally, lack of

available physical transmission capacity in some areas of the west may make it difficult if

not impossible to share power across balancing areas. Area control operators must balance

the system within their control area at the lowest possible cost while maintaining absolute

system reliability. In practice this would be a far simpler exercise with fewer and larger

balancing areas wherein generation resources could be more readily shared.

In addition to these operational constraints, the advent of new and different generation

resources to serve the changing demographics of the west also demands planning and

forethought to optimize required investment in new generation and transmission. System

planners are critically interested in where existing loads will grow and where new loads will

develop. Planners are also interested in determining what resources might be developed to

serve those loads given various state and national policies and again with a top priority on

reliability and cost.

For example, pursuant to state and national policy, over the last several years a relatively

large amount of renewable generation, such as wind and solar power, has been developed

and interconnected to the western grid. These intermittent generation resources are

typically more difficult to accommodate in the context of the interconnected grid than

traditional generating resources, such as coal and hydro electric generation, because they

cannot be counted on to provide generation capacity when consumers demand it. Looking

to the future it is critical to thoughtfully plan for additional generation and transmission

resources so that reliability is maintained and customers are not burdened with excessive

costs.

REGIONAL TRANSMISSION EXPANSION PLAN SYSTEM

For the reasons cited above the OCA has taken an active role in generation and transmission

planning forums around the west. One such forum is the Regional Transmission Expansion

Planning process being undertaken by the Western Electricity Coordinating Council (WECC)

which is the designated regional Electric Reliability Organization in the western United

States. WECC’s function is to ensure the reliability of the bulk electric system in eleven

western states, two Canadian provinces and parts of two Mexican states (the western

38 | P a g e

interconnection). In meeting its reliability obligations WECC sets standards and operating

criteria that all transmission owners and operators must observe. WECC’s reliability

authority is derived from the North American Electric Reliability Corporation (NERC) which is

the Congressionally chartered electric reliability corporation for North America.

Under its by-laws and the

terms of a Department of

Energy grant pursuant to the

American Recovery and

Reinvestment Act, WECC,

through the Regional

Transmission Expansion

Planning forum, is currently

engaged in planning. This

planning will look at both

future generation resources

and electric transmission

capacity expansions required

to meet expected electrical loads by 2020 (the ten year plan) and 2030 (the twenty year

plan) under a variety of plausible future scenarios.

Assumptions regarding what type of future generation resources will be needed and where

they will be located, together with projected transmission capacity additions needed to

accommodate the new generation, have the potential to profoundly impact the cost of

electricity throughout the western interconnection, including to Wyoming electric utility

ratepayers.

In 2010, Bryce Freeman was appointed by the WECC Board of Directors, with the consent of

other consumer advocate organizations from around the west, to serve on the Scenario

Planning Steering Group. The role of the Scenario Planning Steering Group is to develop

future (twenty year horizon) generation and transmission scenarios to be incorporated into

WECC’s twenty year transmission plan study process. This group also works closely with

other WECC committees and stakeholder groups such as the Transmission Expansion

Planning Policy Committee to provide input to and feedback on the WECC ten and twenty

year transmission plans. Bryce Freeman is also a voting member of the Transmission

Expansion Planning Policy Committee.

The Scenario Planning Steering Group and Transmission Expansion Planning Policy

Committee are populated with stakeholders representing a wide variety of interests ranging

from those committed to advancing the interests of certain renewable technologies to

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those advocating policies to fight climate change. While it is useful to have a dialog with

stakeholders representing many different perspectives, many of these interests are

parochial and not motivated by the public interest. The OCA’s objective in these forums, on

the other hand, is to represent the viewpoint of customers which frequently does not align

directly with the viewpoints represented by other stakeholders. It is critically important for

Wyoming customers and customers elsewhere around the west to have a voice in this

dialog, after all it is customers that will be expected to pay the freight for any investments

that result, or not, from this planning process.

WECC issued its first ten year plan under the Regional Transmission Expansion Planning

forum in September of 2011. While the plan details the study of many different

transmission expansion cases, it reinforces the fact that customers in all parts of the

interconnection are best served by a transmission grid that is designed to be shared and

optimized widely across the interconnection. Even though environmental and policy

constraints restrict where and what types of new resources are developed, the ten year

plan makes a compelling case for developing the least cost new resources regardless of

where they are located. For example, the studies show that the quality of Wyoming wind

energy is so far superior to that of neighboring regions that it is the lowest cost renewable

resource available even after considering the transmission investments necessary to deliver

that generation to distant load centers.

Under the terms of the Regional Transmission Expansion Planning grant, WECC will issue its

first biennial twenty year transmission plan in September of 2013. This plan will consider, as

did the ten year plan, a wide variety of factors that impact transmission and generation

development such as environmental and cultural constraints, anticipated future generation

needs, expected future load growth, state renewable energy policy preferences, and more.

The objective is to develop the portfolio of transmission and generation resources that

results in the lowest cost of service to consumers, while, at the same time maintaining

system reliability. Consumers want reliable electric service that is consistent with existing

environmental rules and regulations. However, customers also need electric utility service

that is affordable. The OCA wants to make sure, by participating in the Regional

Transmission Expansion Planning process, none of the parties at the table forget that

electric consumers are the reason we are engaged in transmission planning in the first

place. Customers ultimately pay the bill for whatever generation and transmission

investment is made. Consequently, those investments should be the least cost options,

reasonably available, consistent with existing environmental and reliability requirements.

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ENERGY IMBALANCE MARKET

In many parts of the country, particularly in the northeast and mid-Atlantic states,

electricity markets have long been restructured. In these areas, regulated utilities are often

limited to purchasing wholesale generation in an open, competitive market and then

reselling that power to their retail distribution customers. In these areas, the transmission

system is typically operated by a Regional Transmission Operator (RTO) that also facilitates

the wholesale power market. In many, but not all of these states, retail consumers are

offered the right to choose the provider of their electricity commodity from a variety of

competitive providers, while the transmission and distribution functions are provided by the

regulated monopoly. RTOs are also authorized to maintain and expand the transmission

system within their boundaries and set the price that generation companies must pay to

use the system.

For a variety of reasons, organized power markets and RTOs have not developed in the

western United States. With the exception of California, retail electric service is still largely

provided by vertically integrated utility companies that are regulated by state public service

commissions. Recently, however, regulators and other policy makers throughout the west

have begun investigating whether or not trading of energy in a structured but limited way

might foster greater system reliability and lower costs for customers.

Currently, generators must let transmission system operators know an hour in advance the

amount of power expected to be delivered to their customers in the coming hour. At the

end of the hour, the transmission operator will determine if the generator actually

delivered more or less than the amount scheduled and, within certain parameters, charge

the generator for any excess or insufficient flows. These charges are often referred to as

imbalance penalties and are particularly problematic for intermittent generation such as

wind and solar. It is exceedingly difficult to know how much energy will be produced by a

wind or solar farm an hour in advance of delivery, and imbalance penalties for these

generators can be substantial.

In an Energy Imbalance Market, generators would be allowed to schedule their generators

on a sub-hourly basis, perhaps in fifteen, ten or even five minute intervals while buying and

selling power on a simultaneous schedule to support retail deliveries. Such a market, might

reduce the cost of imbalance energy borne by generators – and passed on to customers –

while also enhancing the reliability of the overall system.

While the creation of west-wide Energy Imbalance Market is still being studied, the OCA

believes that there is a potential for customer savings from this type of wholesale market

depending, of course, on how it is structured. The benefits of such a market may be even

41 | P a g e

more pronounced as increasingly larger amounts of intermittent renewable generation are

integrated into the system. Many different stakeholders from around the west, led by a

group of state public service commissioners, are currently studying the costs and benefits of

such a market. The OCA and a few other consumer advocates have been participating

regularly in public forums regarding the potential development of a western Energy

Imbalance Market. Participation in these forums offers an opportunity for the OCA to

provide input and become better informed about the merits of any Energy Imbalance

Market that may develop in our region.

FEDERAL ENERGY REGULATORY COMMISSION (FERC) TRANSMISSION MANDATES

FERC is the federal regulatory agency that has jurisdiction over interstate electric and

natural gas markets and infrastructure. In exercising its jurisdiction, FERC establishes rules

and sets prices for the movement of bulk electricity and natural gas over interstate electric

transmission and natural gas pipeline systems. FERC has been working for more than a

decade to open the electric transmission system to merchant generators who need access

to the interstate electric transmission system in order to deliver their generation to load

centers.

Over that period, FERC has initiated many rule makings designed to open the transmission

system, which is largely owned by regulated utilities, to third party generators. The 1992

Energy Policy Act (EPACT) required that competitive generators be given access to the

utilities’ transmission grid at rates and terms comparable to those that the utility would

charge itself. The dictates of “comparable access” has led to the growth of wholesale power

markets. In 1996, FERC issued Orders 888 and 889 requiring transmission owners to open

their transmission systems to third parties. These orders also required that transmission

owning utilities access their transmission systems on the same terms and conditions, and

pay the same rates for use, as any third party user of its system. FERC Orders 888, 889 and

Orders 2000 and 2003-A, published in 1999, were all issued to carry out the intended goals

of EPACT.

In 2007, FERC issued Order 890 which required coordinated, open and transparent regional

transmission planning processes to address undue discrimination. Order 890 was followed

in 2011 by Order 1000. Order 1000 requires transmission planning at the regional level to

consider and evaluate possible transmission alternatives and to produce a regional

transmission plan. The order also requires that the cost of transmission solutions chosen to

meet regional transmission be allocated fairly to beneficiaries.

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Northern Tier Transmission Group (NTTG) is the regional planning entity that includes

Wyoming transmission provider Rocky Mountain Power (PacifiCorp). Since September

2011, the OCA has been active in the multi-state NTTG Cost Allocation Work Group created

specifically to forge a regional cost allocation method to comply with FERC Order 1000.

FERC’s directives require both a regional and an interregional process for planning and cost

allocation. The Cost Allocation Work Group is comprised of transmission owners, state

regulatory commissions, and consumer advocates and is co-chaired by a regulator and a

transmission owner. The Cost Allocation Work Group members are engaged in a robust

process to develop a cost allocation methodology consistent with the principles set forth by

FERC. The group has held more than fifty meetings or conference calls. Initial cost

allocation filings have been submitted to FERC by the transmission owners, but regional

discussions on these issues continue.

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INTERACTIONS WITH CUSTOMERS AND OTHER STAKEHOLDERS

SPEECHES, PRESENTATIONS, AND DISCUSSIONS WITH CUSTOMER GROUPS

Not all interactions or involvement in cases result in the OCA filing a formal

intervention in docketed matters before the Commission. For example, in September

2010 the City of Torrington, a municipal electric service provider, filed a request with

the Public Service Commission to increase its revenues by approximately $227,000 per

year. Since the City of Torrington is a municipal utility it only needed approval to

increase the rates of its utility customers residing outside the incorporated limits of the

City. Rates for customers inside the City limits are set by the town council and are not

subject to review by the Commission.

Subsequent to the filing of its application, a group of Torrington customers approached

the OCA requesting assistance in intervening in the proceeding before the Commission.

These customers who are served by the City of Torrington, but reside outside the City

limits, objected to the requested increase and sought an opportunity to provide

evidence to the Commission in a formal proceeding showing that the increase was not

justified based on the information provided by the City.

Under its enabling statutes the OCA is prohibited from advocating on behalf of

individual customers or groups of customers but it is authorized to provide information

and assistance to customers regarding proceedings within the jurisdiction of the

Commission. In this proceeding the OCA assisted the Torrington customers in

understanding what is required to participate in a formal proceeding before the

Commission; deadlines that are required, the process of propounding discovery, the

filing of written testimony and briefs, and the rules of evidence used in formal

proceedings before the Commission.

With the assistance of the OCA these customers were able present evidence to the

Commission showing that the revenues currently being generated from electric

customers were sufficient to cover the costs of providing electric service and that a

revenue increase was not warranted. In the end the Commission ruled in favor of the

customers and denied the City approval to increase its rates to customers living outside

the City limits and directed the City to refund excess revenues that had been collected

from those customers while the rates were in effect on an interim basis. The City

subsequently reduced the rates charged to customers living inside the City limits t o

match those approved by the Commission; however, it did not refund excess revenues

to those customers.

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Additionally, the OCA welcomes the opportunity to speak to various customer groups

and organizations. Each year, we speak to groups such as Lions International, Zonta

International, Rotary International, etc. as well as industry groups such as the Wyoming

Telecommunications Association.

RESPONSES TO INQUIRIES AND CUSTOMERS CONCERNS

The OCA occasionally receives written or telephonic inquires requesting information or

assistance from a variety of stakeholders including utility customers, elected officials and

others. Frequently these requests relate to matters not within the statutory authority of

the OCA; for example, insurance, worker compensation, consumer product defects, etc.

When Wyoming citizens contact the OCA regarding non-utility matters the OCA makes

every effort to put that constituent in contact with the person or agency in state

government that is best equipped to address the matter on their behalf.

The OCA also receives requests for both general information as well as questions regarding

specific issues and cases in which the OCA is involved. We welcome the opportunity to

engage with interested stakeholders when they have questions about the regulatory

process, the positions taken by the OCA in specific proceedings or the concept of utility

ratemaking, generally. We enjoy these interactions with our stakeholders and typically find

that they simply want an explanation as to why the regulatory process works the way it

does. We also find that the citizens that contact our office are well informed and able to

understand ratemaking issues if we spend the time necessary to help them.

LOOKING FOR A SPEAKER?

The OCA welcomes the opportunity to interact with individual customers,

government entities or officials, fraternal organizations, civic groups, the

media, or others who which to discuss current utility or regulatory topics.

To arrange for a speaker or to simply inquire about current issues, please

contact any member of the OCA by calling (307) 777-7427

or

e-mail Bryce Freeman at Bryce.Freeman @wyo.gov

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WORKING WITH OTHERS IN THE REGULATORY COMMUNITY

Members of the Office of Consumer Advocate are active participants in the regulatory

community, working with regulators and consumer advocates regionally, nationally, and

internationally. Some of the many activities that we have participated in this past year

include:

◦ Mr. Freeman is a member of the Executive Committee of the National Association of State Utility Consumer Advocates and regularly interacts with the chairs of other consumer advocate offices through conference calls and meetings.

◦ Mr. Freeman, Ms. Parrish, and Dr. Kolb are each a member of a different committee of the National Association of State Utility Consumer Advocates.

http://www.camput.org/

http://www.icer-regulators.net/portal/page/portal/IERN_HOME/ICER_HOME

http://www.ipu.msu.edu/index.php

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◦ Each member of the OCA attends one or more meetings of the National Association of Regulatory Utility Commissioners each year and several OCA employees have been invited to be a speaker at events or participate on panels at these events.

◦ Mr. Freeman is on the Advisory Board for the Center for Public Utilities at New Mexico State University.

◦ Ms. Parrish is a member of the program faculty and teaches some basic regulatory

courses at the Institute of Public Utilities at Michigan State University.

◦ Ms. Parrish has been an active participant in the Virtual Working Group on

Competitiveness and Affordability in association with the International

Confederation of Energy Regulators. As part of her work and the call for papers, she

wrote a paper on investment incentives to promote additional energy supply and

transmission investment.

◦ Ms. Wichmann began exploring ways to become a Certified Rate of Return Analyst

through the Society of Utility and Regulatory Financial Analysts.

◦ Ms. Parrish actively engages with regulators from around the world through her

work with the Energy Regulators Regional Association, often volunteering her own

personal time to attend meetings with regulators from various parts of the world.

CONFERENCE ON TRANSPARENCY IN THE ELECTRICITY INDUSTRY, BISHKEK, KYRGYZSTAN

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ADDITIONAL RESOURCES

Wyoming Public Service Commission

http://psc.state.wy.us

[email protected]

General Number / Reception

(307) 777-7427

Complaints

(888) 570-9905 (Toll Free)

[email protected]

Customer Assistance Programs

Low Income Energy Assistance Program

(A program to help low income families pay

their utility bills during the winter months)

Administered by:

Wyoming Department of Family Services

(307) 777-5846

https://sites.google.com/a/wyo.gov/dfsweb/e

conomic-assistance/lieap ___________________________________________________________________________________________________________

Energy Share of Wyoming

(A private, non-profit organization established

to help people in hardship circumstances with

energy-related emergencies)

Administered by:

The Salvation Army

(877) 461-5719 __________________________________________________________________________________________________________

Telephone Assistance Programs for Income

Eligible Customers

(Programs that provide discounts to low-

income customers to help ensure the

opportunity for telephone service)

Wyoming Statutes §§ 37-2-301 through 306

Additional Information and Guidance:

http://www.fcc.gov/guides/lifeline-and-link-

affordable-telephone-service-income-eligible-

consumers

To apply:

https://sites.google.com/a/wyo.gov/dfsweb/e

conomic-assistance/tap

or

contact your local telecommunications

company __________________________________________________________________________________________________________

Do Not Call Registry

(888) 382-1222 (Toll Free)

https://www.donotcall.gov

Energy

Federal Energy Regulatory Commission

http://www.ferc.gov/

(866) 208-3372 (Toll Free)

e-mail: [email protected]

U.S. Department of Energy

http://energy.gov/

(202) 586-5000


Energy Information Administration

http://www.eia.gov/

(202) 586-8800 (24-hour FAQ line)


Telecommunications

Federal Communications Commission

http://www.fcc.gov/

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