questar gas company integrated resource...
TRANSCRIPT
QUESTAR GAS COMPANY
INTEGRATED RESOURCE PLAN
(For Plan Year: June 1, 2013 to May 31, 2014)
Submitted: May 31, 2013
TABLE OF CONTENTS
Page
1. EXECUTIVE SUMMARY ............................................................................................. 1-1 2. INTRODUCTION AND BACKGROUND .................................................................... 2-1 Wexpro II Agreement .......................................................................................... 2-6 Wyoming IRP Process ......................................................................................... 2-7 Utah IRP Process ................................................................................................. 2-9 Exhibit ................................................................................................................ 2-13 3. CUSTOMER AND GAS DEMAND FORECAST ......................................................... 3-1 System Total Temperature Adjusted Dth Sales and Throughput ........................ 3-1 Temperature Adjusted Dth Sales and Throughput Summary - 2013 IRP ........... 3-1 Residential Usage and Customer Additions ........................................................ 3-2 Small Commercial Usage and Customer Additions ............................................ 3-3 Large Commercial, Industrial and Electric Generation Gas Demand ................. 3-3 Firm Customer Design-Day Gas Demand ........................................................... 3-4 Periods of Interruption ......................................................................................... 3-4 Source Data .......................................................................................................... 3-4 Utah and Wyoming Economic Outlook ............................................................... 3-5 The U.S. Economic Outlook ................................................................................ 3-6 Alternatives to Natural Gas .................................................................................. 3-7 Lost and Unaccounted For Gas ............................................................................ 3-8 Exhibits .................................................................................................. 3-11 - 3-21 4. SYSTEM CAPABILITIES AND CONSTRAINTS ....................................................... 4-1 Questar Gas System Overview ............................................................................ 4-1 System Operations ............................................................................................... 4-2 Ongoing and Future System Analysis Projects .................................................... 4-3 System Modeling and Reinforcement .................................................................. 4-4 Model Verification ............................................................................................... 4-5 Gate Station Flows vs. Capacity .......................................................................... 4-7 Joint Operating Agreement .................................................................................. 4-7 System Pressures .................................................................................................. 4-7 System Capacity Conclusions ............................................................................ 4-15 DNG Action Plan ............................................................................................... 4-16 Integrity Management Plan Activities and Associated Costs ............................ 4-21 Transmission Integrity Management ................................................................. 4-22 Distribution Integrity Management .................................................................... 4-25 New Regulations that May Impact Future Costs Associated With Integrity ..... 4-25 Environmental Review....................................................................................... 4-33 Exhibits .................................................................................................. 4-36 - 4-41 5. PURCHASED GAS ......................................................................................................... 5-1
Local Market Environment .................................................................................. 5-1 Sendout Modeling Issues ..................................................................................... 5-2 Price Stabilization ................................................................................................ 5-4 6. COST-OF-SERVICE GAS .............................................................................................. 6-1 Cost of Service (COS) Modeling Factors ............................................................ 6-1 Producer Imbalances ............................................................................................ 6-3 Future Resources .................................................................................................. 6-4 Exhibit .................................................................................................................. 6-6 7. GATHERING, TRANSPORTATION AND STORAGE ............................................... 7-1 Gathering and Processing Issues .......................................................................... 7-1 Transportation Issues ........................................................................................... 7-2 Storage Issues....................................................................................................... 7-7 Exhibits ................................................................................................... 7-15 - 7-22 8. ENERGY-EFFICIENCY PROGRAMS .......................................................................... 8-1 Utah Energy-Efficiency Results 2012 ................................................................. 8-1 Wyoming Energy-Efficiency Results 2012 ......................................................... 8-4 Utah Energy-Efficiency Plan 2013 ...................................................................... 8-4 Wyoming Energy-Efficiency Plan 2013 .............................................................. 8-8 SENDOUT Model Results for 2013 .................................................................... 8-8 Avoided Costs Resulting from Energy Efficiency ............................................. 8-10 Exhibit ................................................................................................................ 8-11 9. FINAL MODELING RESULTS ..................................................................................... 9-1 Linear Programming Optimization Model ........................................................... 9-1 Costraints and Linear Programming .................................................................... 9-1 Monte Carlo Method ............................................................................................ 9-2 Natural Gas Price ................................................................................................. 9-3 Weather and Demand ........................................................................................... 9-3 Peak Day and Base Load Purchase Contracts ...................................................... 9-4 Base Case Identification ...................................................................................... 9-5 Purchased-Gas Resources .................................................................................... 9-5 Cost-of-Service Gas ............................................................................................. 9-6 First-Year and Total System Costs ...................................................................... 9-6 Gas Supply Plan ................................................................................................... 9-6 Normal Temperature Case ................................................................................... 9-6 Gas Supply/Demand Balance .............................................................................. 9-6 Exhibits ................................................................................................... 9-8 - 9-100 10. GENERAL IRP GUIDELINES/GOALS FOR GAS SUPPLY AND ENERGY
EFFICIENCY RESOURCES ........................................................................................ 10-1
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EXECUTIVE SUMMARY
Questar Gas Company (Questar Gas or Company) is a regulated natural gas utility company providing retail natural-gas-distribution service to more than 930,000 customers in Utah, southwestern Wyoming and two communities in southeastern Idaho. The Company is regulated by the Utah Public Service Commission (Utah Commission) and the Public Service Commission of Wyoming (Wyoming Commission).
During January of 2013, the service area of Questar Gas experienced unusually cold
temperatures. For 14 of the 31 days in January, the Salt Lake International Airport observed-high temperature was at or below the normal-low temperature. For the gas-day January 14th, Questar gas set a new record for distribution system deliveries of more than 1.2 million decatherms (Dth). Even though a design-day peak event did not occur, these unusually cold temperatures were a good test of the adequacy of the distribution system and the upstream transportation and storage facilities contracted for by Questar Gas.
For over two decades, Questar Gas has engaged in an annual integrated resource
planning (IRP) process. This process results in a planning document that is used as a guide in meeting the natural gas requirements of the Company’s customers for the ensuing year. As a fundamental part of the IRP process, Questar Gas conducts an assessment of available resources through the utilization of a cost-minimizing linear-programming computer model. An atmosphere of open dialogue with regulatory agencies and interested stakeholders is an overarching principal of the IRP process.
The IRP process this year has resulted in the following key findings:
1. A design-day firm sales demand of approximately 1.27 million Dth at
the city gates for the 2013/2014 heating season; 2. A cost-of-service natural gas production level of approximately 80
million Dth assuming the completion of new development drilling projects;
3. A balanced portfolio of natural gas purchases of approximately 35
million Dth; 4. Questar Gas should maintain flexibility in purchase decisions pursuant
to the planning guidelines listed herein, because actual weather and load conditions will vary from assumed conditions in the modeling simulation;
5. There is not a current need for any additional price stabilization, but
the Company should review this issue on an annual basis to determine whether such measures are appropriate in the future;
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6. Questar Gas should continue to monitor and manage producer
imbalances; and 7. In Utah and Wyoming, Questar Gas should continue to promote cost-
effective energy-efficiency measures.
Questar Gas’ High Pressure (HP) feeder line system is capable of meeting the current peak- day demands with adequate supplies and pressures in the system. This system capacity assessment is based on the fact that the gate stations have adequate capacity, the supply contracts are adequate, and system models show that pressures do not drop below the design minimum of 125 psig. The system will continue to grow along with the demand and Questar Gas will conduct an analysis annually to ensure that the system continues to meet the peak- day needs.
This report has been organized into the following sections: 1) executive summary; 2)
introduction and background; 3) Questar Gas’ customer and gas demand forecast; 4) the capabilities and constraints of Questar Gas’ distribution system; 5) the local market for natural gas, the purchased gas RFP, associated modeling issues, and price stabilization topics; 6) cost-of-service gas including modeling issues, producer imbalances and future development prospects; 7) gathering, transportation and storage; 8) energy-efficiency programs; 9) the final modeling results; and 10) the general planning guidelines to be used in the implementation of the IRP from June of 2013 through May of 2014.1
The preparation of this planning document is dependent on information from many
sources. Questar Gas acknowledges the contributions of all who have participated in the IRP process this year. In the event there are questions, comments or requests for additional information, please direct them to:
Christina M. Faust General Manager, Gas Supply Questar Gas Company 333 South State Street P.O. Box 45360 Salt Lake City, UT 84145-0360 Phone: (801) 324-2715 Email: [email protected]
1 Throughout this report, “Dth” refers to decatherms, “Mcfh” refers to thousand cubic feet per hour, “MDth” refers to thousands of decatherms, “MMDth” refers to millions of decatherms, “Dth/D” refers to decatherms per day, “MDth/D” refers to thousands of decatherms per day, “Btu” refers to British thermal units, “MMBtu” refers to millions of British thermal units, “cf” refers to cubic feet, “Mcf” refers to thousands of cubic feet, “MMcf” refers to millions of cubic feet, “Bcf” refers to billions of cubic feet, “Tcf” refers to trillions of cubic feet, “Mcf/D” refers to thousands of cubic feet per day, “MMcf/D” refers to millions of cubic feet per day, “psi” refers to pounds per square inch, “psig” refers to pounds per square inch gauge, and “lf” refers to linear feet. “FL” refers to feeder line.
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INTRODUCTION AND BACKGROUND
In recent months, an unusual number of personnel changes have been announced for
leadership positions in many of the governmental and regulatory agencies that shape the policies affecting the natural gas industry in America. Likewise, in the states where Questar Gas provides services to its customers, a number of key personnel changes in regulatory agencies have also taken place.
Early in 2013, President Obama nominated Sally Jewell to replace the outgoing
Secretary of the Interior, Ken Salazar. Also this year, the President nominated Ernest Moniz to be the new Secretary of the Department of Energy replacing Steven Chu and Anthony Foxx, Mayor of Charlotte, North Carolina, to be the new Secretary of the Department of Transportation, replacing Ray LaHood. In the Environmental Protection Agency, Gina McCarthy was nominated by the President to replace Lisa Jackson who resigned in February. And, during the summer of 2012, Tony Clark, a former member of the North Dakota Public Service Commission, was nominated and sworn in as a new member of the Federal Energy Regulatory Commission filling the vacancy created by Commissioner Marc Spitzer who resigned earlier.
At the state level, Governor Mead of Wyoming recently announced two new
appointments to the Wyoming Commission, Kara Brighton and Bill Russell, who have been confirmed to fill the vacancies created by the resignation of Kathleen Lewis and the retirement of Deputy Chairman Steve Oxley. The Wyoming Commission currently consists of Chairman Alan Minier, Deputy Chairman Bill Russell, and Commissioner Kara Brighton.
In Utah, where the majority of the customers of Questar Gas reside, Governor Herbert
recently appointed two new members to the Utah Commission, Thad LeVar and David Clark. David Clark has filled the position vacated by Commissioner Ric Campbell and Thad LeVar filled the vacancy created by the retirement of the former Chairman of the Utah Commission, Ted Boyer. Ron Allen, who was formerly serving as a Commissioner was appointed by Governor Herbert to be Chairman of the Utah Commission on January 1, 2013.
As supplies of this moderately priced and clean burning resource have become more
plentiful in recent years, Questar Gas is optimistic that the public policies of the future will allow natural gas to play a significant role in the growth of the U.S. economy.
During October of 2012, the American Gas Association (AGA) announced that
Ronald Jibson, Chairman, President and CEO of Questar Corporation, the parent company of Questar Gas, had been elected to serve as Chairman of the Board of Directors of AGA for 2013. In his words, as a representative of the natural gas industry:
For more than 177 million Americans, natural gas provides more than just warmth and a hot shower . . . it provides tangible value for our quality of life . . . The United States leads the world in not only producing this clean energy resource but also in capitalizing on the most robust and reliable pipeline system in the world. With this abundant domestic resource and our ability to
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deliver natural gas safely and reliably, we can boost our economy, improve our environment and enhance our energy security today.2 In recent years, technological improvements in drilling have led to remarkable
increases in natural gas reserves, particularly in shale gas plays.3 During April of 2013, the Potential Gas Committee released its biennial assessment of the total technically recoverable natural gas resource base in the U.S.4 This assessment does not include proved dry-gas reserves. Proved reserves are generally those reserves which are estimated with reasonable certainty to be economically producible from known reservoirs.5 For year-end 2012, the mean value for total potential natural gas resource was 2,384 trillion cubic feet (Tcf). This figure was 486 Tcf greater than the same assessment for year-end 2010 (26 percent greater). The 2010 assessment was the previous all-time high. The most recent formal assessment for proved dry-gas reserves in the U.S. is a 2010 figure of 304.6 Tcf. When the total technically recoverable resource base is combined with the proved dry-gas reserves, a total U.S. future gas supply figure of 2,689 Tcf is obtained.6
The Potential Gas Committee grouped geological provinces in the U.S. into seven
geographic assessment areas. Understandably, the Atlantic region now has the largest resource base with the development of northeastern shale plays such as the Marcellus. The Rockies region was assessed with the third largest resource base in the Country, behind the Atlantic and Gulf Coast regions. The Rockies region however, had the second largest increase in resource base over the previous two years behind the Atlantic region.7
It is instructive to put into context the size of the recent Potential Gas Committee
assessment of natural gas resource base. At current production rates, the total U.S. future gas supply represents in excess of 100 years of U.S. supply needs.
The increase in proved reserves, driven primarily by drilling in shale gas plays, has
implications for the pricing of natural gas. Current indications are that natural gas will be moderately priced for the foreseeable future. The Henry Hub natural gas futures forward curve in recent weeks has had prices through the summer and fall shoulder months of 2013 in the low four-dollar-per-decatherm range. During the winter of 2013/2014, Henry Hub futures’ prices rise to the mid four-dollar-per-decatherm range. The highest prices over the 36-month strip currently are under five dollars per decatherm.
Within the family of fossil fuels, natural gas is the cleanest burning with regard to air
emissions. Energy-related CO2 emissions in the U.S. during 2012 totaled 5.3 billion metric tons. The Energy Information Administration (EIA) reported that this was the lowest level in 2 “2013 Playbook, “American Gas Association, January 16, 2013, Pages 1-2, http://www.aga.org/our-issues/playbook/Pages/default.aspx. 3 For a more in depth discussion of directional drilling, hydraulic fracturing, and the growth in shale gas production, see the Introduction and Background section of the Questar Gas Company Integrated Resource Plan, For Plan Year: June 1, 2011 to May 31, 2012, Submitted: June 6, 2011. 4 The Potential Gas Committee is a widely respected, nonprofit organization consisting of volunteer members with technical knowledge of and experience in the natural gas industry. 5 For a more precise definition of proved reserves, see 17 CFR Section 210.4-10(a)(22). 6 “Potential Gas Committee Reports Significant Increase in Magnitude of U.S. Natural Gas Resource Base,” For Release April 9, 2013, 1100 EDT, Potential Gas Committee. 7 Ibid., Page 5.
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the U.S. since 1994. And, quite remarkably, since 2007, energy-related CO2 emissions have declined every year with the exception of 2010. The replacement of coal-fired power generation with generation from the less carbon-intensive and competitively priced fuel, natural gas has been fundamental to that decline in 2012. Other contributing factors to the 2012 decline are decreased demand for transportation fuels and mild winter temperatures across the U.S.8
During the fall of 2012, a new U.S. record was set for natural gas storage inventories. The EIA reported that working gas in storage for facilities in the Lower-48 states hit an all-time high of 3,929 billion cubic feet (Bcf) for the week ending November 2, 2012. The maximum storage build for the previous year’s injection season was 3,852 Bcf for the injection week ending November 18, 2011.9
The last week of March is considered by many to be the end of the traditional
withdrawal season for natural gas storage in the U.S. Given the recent abundance of natural gas supplies, one might expect a surplus in storage in excess of the five-year average at the end of March. For the week ending March 29, 2013, the EIA reported that working gas in storage for the Lower-48 states was at a level of 1,687 Bcf, substantially below the previous year’s level of 2,466 Bcf, and slightly below the five-year average of 1,724 Bcf.10 Analysts generally attributed that lower-than-expected end-of-withdrawal-season storage inventory level this year to an unusually cold March and modest increases in natural gas prices.
In earlier decades, natural gas storage capacity was largely obtained by regulated
utilities and used to meet winter-time base-load requirements, daily load fluctuations, and peak-day needs. Over the last decade, natural gas marketers have increasingly used storage as a means to capture value from short-term price arbitrage. While there appears to be ample storage capacity in the aggregate in North America, it is safe to assume that additional increments of capacity will be developed when and where they can be justified by regional economics. For a recap of recent natural gas storage projects in the vicinity of the demand areas of Questar Gas, and a discussion of the involvement of Questar Gas, see the “Gathering, Transportation and Storage” section of this report.
According to the EIA, 2012 had the fewest natural gas pipeline additions in the U.S.,
from both a capacity and a mileage standpoint since 1997. This statistic does not include gathering and distribution lines. Over one half of the transportation line projects in the Country were located in the Northeast and were designed to remove bottlenecks created by the rapid growth of production in the Marcellus shale. Nevertheless, occasional price run-ups occurred in the Northeast this past winter due to constrained transportation capacity. For example, during the fourth week of January 2013, daily deals were reported on “Transco Zone 6 NY” with prices in excess of $40.00 per Dth.
8 “Energy-Related Carbon Dioxide Emissions Declined in 2012,” Today in Energy, U.S. Energy Information Administration, April 5, 2013. 9Energy Information Administration, Weekly Natural Gas Storage Report History, April 5, 2013, http://ir.eia.gov/ngs/ngshistory.xls. 10 “Weekly Natural Gas Storage Report,” U .S. Energy Information Administration, For the Week Ending March 29, 2013, Released: April 4, 2013 at 10:30am.
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Across the country, 2013 is expected to be a better year for transportation capacity additions. During 2012, less than 5 Bcf per day of capacity was put in service. In excess of 15 Bcf per day of capacity has been announced for 2013, substantially more than 2012, but still a far cry from the approximately 44 Bcf per day of capacity put in service in 2008.11 For a discussion of the transportation issues affecting Questar Gas, see the “Gathering, Transportation and Storage” section of this report. Interest in the use of natural gas as a vehicle fuel has continued to intensify across the nation. During the past two years, over 200 compressed natural gas (CNG) stations have been added to the nation’s infrastructure, bringing the total to over 1,200 stations. A number of local distribution companies (LDCs) and exploration and production (E&P) companies around the country are fostering the growth of CNG as a retail transportation fuel by providing funding to expand CNG refueling infrastructure.
Original Equipment Manufacturers (OEMs) have both increased production of light and medium-duty CNG vehicle platforms as well as introduced a number of new vehicle models. Class 8, over-the-road CNG vehicle platforms are on the rise and refuse hauler manufacturers now produce more factory-built CNG models than diesel or gasoline models.
Congress reinstated the $0.50 per gasoline gallon equivalent (GGE) tax credit for fuel providers like Questar Gas, however, the tax credit is scheduled to sunset at the end of 2013. Through the regulatory process, the National Highway Traffic Safety Administration (NHTSA) which regulates the nation’s Corporate Average Fuel Economy (CAFE) standards recently gave additional fuel economy credits to vehicle manufacturers for the production of natural gas vehicles (NGVs).
Questar Gas is a national leader in the promotion of natural gas as a vehicle fuel. According to a recent NGV marketing study by TIAX, LLC published in February, 2013, the Questar Gas service territory accounts for approximately 11,000 CNG vehicles (9% of the total CNG vehicles on the road today in the U.S.). Exhibit 2.1 is a map of the CNG station locations in Utah.
Beginning in 2009, Questar Gas began installing new public access CNG infrastructure facilities and upgrading existing public access facilities. Partial funding for these new installations and upgrades was provided by a U.S. DOE grant.
New installations and upgrades were completed at Logan, Perry, Murray, Springville,
St. George, Vernal, Scipio, Heber City, Ogden, Hurricane, Sandy, Salt Lake, Woods Cross, Park City, Orem and West Jordan. In 2012 new stations were installed in Kaysville, Moab, Weber State, Rock Springs and the Price station was upgraded. There are currently 29 public access infrastructure facilities operated by Questar Gas.
In 2013 it is expected that upgrades will be completed at the Questar Gas station at
the Salt Lake International Airport and either Cedar City or Richfield, Utah.
11 “Over Half of U .S. Natural Gas Pipeline Projects in 2012 Were in the Northeast,” Today in Energy, U.S. Energy Information Administration, March 25, 2013.
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Public usage of Questar Gas’ CNG system has grown. Table 2.1 shows annualized Gasoline Gallon Equivalents for the past five years (based on 124,400 Btus per gallon).
Table 2.1
Year GGEs % Growth 2008 3,499,067 2009 3,862,037 10.4% 2010 4,145,802 7.3% 2011 4,714,135 13.7% 2012 5,592,512 18.6%
The Utah Legislature recently passed two bills promoting the use of NGVs. Utah
House Bill 96 extends tax credits for cleaner-burning-fuel vehicles. Senate Bill 275 establishes an interlocal entity to facilitate the use of more alternative-fuel vehicles, and directs the Utah Commission to initiate and conduct proceedings to explore funding mechanisms to provide capital for natural gas vehicle infrastructure.
In recent years, the increase in shale gas production has focused attention on the
environmental impacts of hydraulic fracturing. Hydraulic fracturing involves pumping fluid at high pressures into natural gas reservoirs to induce fractures in the formation. These fractures provide for better connectivity between the wellbore and the surrounding reservoir rock thereby enhancing natural gas production rates and total recoverable reserves. Fracture fluid contains approximately 90 percent water, 9.5 percent sand, and 0.5 percent additives. When the casing of an oil or gas well is properly cemented, formations containing ground water are isolated from those producing hydrocarbons. Studies by Federal agencies in the 1990’s and early 2000’s generally concluded that the risk of contamination of sources of drinking water by hydraulic fracturing fluids posed little or no threat.12,13 Contamination from hydraulic fracturing is more likely to occur from the improper handling of fluids above ground before the fracturing process, or, after the fracturing process when produced liquids are being disposed of. Both of these scenarios can be prevented by simply following accepted industry procedures.
The U.S. House of Representatives Appropriation Conference Committee, in its
Fiscal Year 2010 budget report, identified the need for another study of the environmental impacts of hydraulic fracturing. Congress tasked EPA scientists with carrying out the study. The EPA held public comment meetings in various locations around the country from July through September of 2010. The EPA released the first progress report in December of 2012. The progress report largely established the intent and methodological approach of the study, without articulating conclusions. A final draft report is expected to be released in 2014 for public comment and for peer review.
12 Correspondence, dated May 5, 1995, from Carol M. Browner, Administrator of the United States Environmental Protection Agency, to David A. Ludder, Esq., General Counsel, Legal Environmental Assistance Foundation, Inc. 13 “Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing,” U.S. Environmental Protection Agency, EPA 816-R-04-003, June 2004, Page ES-1.
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Companies in the oil and gas industry supported the EPA study by providing data for
review and analysis. Industry has voluntarily provided additional information from FracFocus, a fracturing chemical registry where well-specific chemical disclosures have been made for over 12,000 wells.14 Wexpro, the production affiliate of Questar Gas, is among the companies voluntarily providing data to FracFocus.
Many in the industry believe that states are in the best position to establish disclosure
rules for the chemical components used in hydraulic fracturing fluids rather than federal agencies. The Wyoming Oil and Gas Conservation Commission was the first in the nation to implement a fracturing disclosure rule in 2010. During October of 2012, the Oil, Gas and Mining Board of the State of Utah approved a rule requiring disclosure within 60-days of hydraulically fracturing a well.
Wexpro II Agreement For over 30 years, Questar Gas’ customers have benefited from supplies delivered at
cost-of-service to the Company pursuant to the Wexpro Agreement (Wexpro Agreement).15 Since the fall of 2011, Questar Gas and Wexpro Company (Wexpro) and regulatory agencies in Utah and Wyoming have been discussing the possibility of Wexpro acquiring oil and gas properties or undeveloped leases for the mutual benefit of Questar Gas’ customers and Wexpro, under an agreement similar to the Wexpro Agreement.16 This arrangement, referred to as the Wexpro II Agreement, was designed to incorporate essentially the same terms and conditions of the Wexpro Agreement.
On December 5, 2012, the Utah Commission held a technical conference to address
questions relating to the Wexpro II Agreement. On September 18, 2012, Questar Gas filed an application with the Utah Commission
seeking approval of the Wexpro II Agreement along with supporting testimony.17 On December 11, 2012, the Division of Public Utilities (Division) and the Office of Consumer Services (the Office) filed direct testimony.18 On January 10, 2013, Questar Gas, the Office and the Division filed rebuttal testimony. The same Parties filed surrebuttal testimony on January 24, 2013. On January 30 and 31 of 2012, the Utah Commission conducted hearings on the Wexpro II matter where witnesses from the Company, Utah regulatory agencies and the public appeared. On March 28, 2013, the Utah Commission issued its Report and Order approving the Company’s application for approval of the Wexpro II Agreement finding that 14 FracFocus is operated by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. 15 For more information on the Wexpro Agreement, see the Cost-of-Service Gas section of this report. 16 Meetings on the Wexpro II concept were held with Wyoming regulatory agencies in person or by telephone on November 9, 2011, January 26, 2012, February 14, 2012, March 28, 2012, and April 26, 2012. In Utah, meetings were held on October 25, 2011, January 18, 2012, March 26, 2012, and April 26, 2012. 17 Utah Public Service Commission, “In the Matter of the Application of Questar Gas Company for Approval of the Wexpro II Agreement,” Docket No. 12-057-13, September 18, 2012. See direct testimony of Barrie L. McKay and James R. Livsey in Docket No. 12-057-13 also filed September 18, 2012. 18 See direct testimony of Douglas D. Wheelwright on behalf of the Division and direct testimony of Michele Beck on behalf of the Office in Docket No. 12-057-13 filed December 11, 2012.
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“Questar [Gas] and the Division have adequately demonstrated Wexpro II to be in the public interest.”19 The Utah Commission held a technical conference on May 2, 2013 to discuss the information to be provided with an application for the approval of a property under the Wexpro II Agreement. The Utah Commission, Utah Commission Staff, the Office, the Division and the Wyoming Office of Consumer Advocate all participated in the technical conference.
On September 18, 2012, Questar Gas also filed an application with the Wyoming
Commission also seeking approval of the Wexpro II Agreement with the same supporting testimony.20 From September 2012 to March 2013 the Company and Wexpro responded to numerous data requests from the Wyoming Commission Staff. On March 11, 2013, direct testimony was filed on behalf of the Wyoming Office of Consumer Advocate in support of the Wexpro II Agreement.21 On April 11, 2013, the Wyoming Commission held a public hearing where witnesses from the Company and the Office of Consumer Advocate provided extensive testimony in support of the Wexpro II Agreement. At the conclusion of the hearing, the Wyoming Commission deliberated and approved the Wexpro II Agreement. Questar Gas anticipates that the Wyoming Commission will issue a written order approving the Wexpro II Agreement soon.
The Wexpro II Agreement provides a framework where the customers of Questar Gas
can continue to receive the long-term benefits of cost-of-service production. The approval of both the Utah Commission and the Wyoming Commission is required for a property to be eligible for treatment under the Wexpro II Agreement. Applications for Wexpro II treatment will include data and analysis on the impact of proposed properties on the Company’s gas supply and could include, as requested or appropriate, integrated resource planning analysis. Questar Gas is confident that the Wexpro II Agreement will prove to be valuable to its customers over the long term in Utah and Wyoming.
Wyoming IRP Process
Questar Gas has been involved in integrated resource planning for nearly two decades in the State of Wyoming. As directed in an order issued by the Wyoming Commission in 1992, the Company has been required to prepare and file integrated resource plans.22
More recently, on February 3, 2009, the Wyoming Commission issued an order initiating a rulemaking pertaining to integrated resource planning. The rule was proposed to “. . . give the Commission a more formalized process for requiring the filing of integrated resource plans, in some cases, and reviewing such plans.”23 19 Utah Public Service Commission, “In the Matter of the Application of Questar Gas Company for Approval of the Wexpro II Agreement,” Docket No. 12-057-13, Report and Order, Issued: March 28, 2013. 20 Public Service Commission of Wyoming, “In the Matter of the Application of Questar Gas Company for the Approval of the Wexpro II Agreement,” Docket No. 30010-123-GA-12, filed September 18, 2012. 21 See direct testimony of Bryce J. Freeman in Docket No. 30010-123-GA-12 filed on March 11, 2013. 22 “In the Matter of the Application of Mountain Fuel Supply Company to File its Integrated Resource Plan as Directed by the Commission in Docket No. 30010-GI-90-8,” Findings, Conclusions and Order, Docket No. 30010-GI-91-14, May 21, 1992. 23 Before the Public Service Commission of Wyoming, “In the Matter of the Proposed Adoption of Chapter 2, Section 253 of the Commission Procedural Rules and Special Regulations Regarding Integrated Resource Planning,” Order Initiating Rulemaking, Docket No. 90000-107-XO-09 (Record No. 12032, February 3, 2009).
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On May 12, 2009, the Wyoming Commission approved Rule 253. On June 7, 2010,
the Wyoming Commission sent out natural gas IRP guidelines to natural gas utilities with a request for comments.24 On January 24, 2011, the Wyoming Commission accepted the natural gas IRP guidelines.25
On June 12, 2012, Questar Gas filed its 2012 IRP with the Wyoming Commission.
On August 14, 2012, the Wyoming Commission noticed the filing in its Open Meeting Agenda and solicited written comments to be filed on or before October 12, 2012. The Wyoming Commission also set November 27, 2012 as the date for the matter to be considered in open meeting.26 On November 15, 2012, the Commission Technical Staff and the Commission Legal Staff sent a report to the Wyoming Commission addressing the content of the 2012 IRP and noting changes from the previous year’s IRP.27 Other than the report by Commission Staff, no comments were received on the 2012 IRP.
The Wyoming Commission addressed Questar Gas’ IRP in its Open Meeting on
November 27, 2012. At that meeting, representatives of Questar Gas (participating by telephone) summarized the IRP and answered questions from the Wyoming Commission. The Commission Staff recommended that a letter order be issued accepting the Company’s IRP for filing. Pursuant to action taken at the November 27th open meeting, the Wyoming Commission issued a letter order on January 11, 2013, accepting the 2012 IRP for filing. The Commission also indicated that no further action would be taken and closed the matter.28
On December 20, 2012, representatives of Questar Gas and Questar Pipeline met with
regulatory agencies in Wyoming to discuss natural gas interchangeability as part of a presentation titled, “Update on Gas Interchangeability Management.” Discussion topics included:
Brief definition of gas interchangeability. History of gas management on the system. Discussion of current operating ranges. Description of industry trends. Recommendations for moving forward.
24 Correspondence from the Public Service Commission of Wyoming; Alan B. Minier, Chairman; Steve Oxley, Deputy Chairman, and Kathleen “Cindy” Lewis, Commissioner; to Barrie McKay, Manager of State Regulatory Affairs, Questar Gas Company, dated June 7, 2010. 25 Correspondence from the Public Service Commission of Wyoming; Alan B. Minier, Chairman, Steve Oxley, Deputy Chairman, and Kathleen “Cindy” Lewis, Commissioner, To All Wyoming Natural Gas Utilities, dated January 24, 2011. 26 Wyoming Public Service Commission, Open Meeting Agenda, Tuesday, August 14, 2012, Page 2. 27 Memorandum From Don Biedermann and Steve Mink to Chairman Minier, Deputy Chairman Oxley and Commissioner Russell, Dated: November 15, 2012, Re: Docket No. 30010-117-GA-12 (Record No. 13213) In the matter of the application of Questar Gas Integrated Resource Plan (IRP) for June 1, 2012 to May 31, 2013. 28 Letter Order, To: Jenniffer R. Nelson, Senior Corporate Counsel, Questar Gas Company, From: Steve Mink, Assistant Secretary Wyoming Public Service Commission, Re: IN THE MATTER OF THE APPLICATION OF QUESTAR GAS’ INTEGRATED RESOURCE PLAN FOR PLAN YEAR JUNE 1, 2012 TO MAY 31, 2013 – Docket No. 30010-117-GA-12 (Record No. 13213), Issued: January 11, 2013.
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Utah IRP Process
In recent years, the Utah Commission has promulgated new IRP standards and guidelines. This implementation process has included numerous discussions between IRP stakeholders in public meetings and the submission of extensive comments.
On March 31, 2009, the Utah Commission issued its Report and Order on Standards
and Guidelines for Questar Gas Company (2009 IRP Standards) to be effective starting with the Company’s 2010 IRP.29
On March 22, 2010, the Utah Commission issued an order clarifying the requirements
of the 2009 IRP Standards (Clarification Order).30 On June 8, 2012, Questar Gas filed its IRP for the plan year, June 1, 2012 to May 31,
2013. On June 13, 2012, the Utah Commission issued an Action Request for the Division to conduct an investigation of the 2012 IRP.31 The Division responded with its report and recommendation on July 9, 2012.32 On August 6, 2012, the Utah Commission issued its Report and Order on the 2012 IRP.33 The Utah Commission commended the Company for its efforts in preparing the 2012 IRP, managing the IRP process, and addressing Commission guidance from previous Utah Commission orders. In particular, the Utah Commission acknowledged the Company for providing valuable, up-to-date information. The Utah Commission also acknowledged the Division’s analysis of and comments on the 2012 IRP. The Utah Commission agreed with the Division’s analysis and determination that the 2012 IRP satisfied the requirements of the 2009 IRP Standards.
In its August 6, 2012 Report and Order, the Utah Commission offered guidance for
the Company to address three areas: The first area involved the Company’s System-Wide Gathering Agreement (SWGA) with QEP Field Services Company. As discussed in more depth in the Gathering, Transportation and Storage section of this report, Questar Gas, after initiating an audit of the SWGA, filed a lawsuit on May 1, 2012 disputing certain gathering rates and charges invoiced under that agreement. The Utah Commission ordered the Company to provide a quarterly update of the dispute in future IRP quarterly variance reports.
Second, the Utah Commission observed significant cost increases in the Company’s
transmission and distribution integrity management programs (IMP) from those presented in
29 “In the Matter of the Revision of Questar Gas Company’s Integrated Resource Planning Standards and Guidelines,” Report and Order on Standards and Guidelines for Questar Gas Company, Docket No. 08-057-02, Issued: March 31, 2009. 30 “In the Matter of Questar Gas Company’s Integrated Resource Plan for Plan Year: May 1, 2009 to April 30, 2010,” Report and Order, Docket No. 09-057-07, Issued: March 22, 2010. 31 Action Request, From: Public Service Commission, Subject: Questar Gas Company’s Integrated Resource Plan (IRP) 12-057-07, Date: June 13, 2012. 32 Action Request Response, To: Utah Public Service Commission, From: Division of Public Utilities; Chris Parker, Director, Artie Powell, Manager, Energy Section, Marlin H. Barrow, Technical Consultant, Carolyn Roll, Utility Analyst, Subject: Action Request Docket No. 12-057-07, Questar Gas Company 2012-13 Integrated Resource Plan (IRP) Report, Division’s Recommendation – Acknowledgement, Date: July 9, 2012. 33 In the Matter of Questar Gas Company’s Integrated Resource Plan for Plan Year: June 1, 2012 to May 31, 2013, Report and Order, Docket No. 12-057-07, Issued: August 6, 2012.
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the 2011 IRP to those presented in the 2012 IRP. While acknowledging the importance of these programs and the fact that they are required by federal law, the Utah Commission ordered Questar Gas to explain the deviations in cost estimates in future IRPs or IRP-associated meetings.
And third, the Utah Commission encouraged the parties involved in the IRP process
to meet with the goal of enhancing understanding the SENDOUT model including its setup, logic and constraints.
Over the past year, Questar Gas has scheduled technical conferences and meetings to
respond to specific issues as ordered by the Utah Commission, to receive input for the IRP process, and to report on the progress of the Company’s planning effort. On March 13, 2013, the first public IRP technical conference was held in conjunction with the development of the 2013 IRP (a short portion of the meeting was closed due to the confidential nature of the information presented). The following topics were discussed including two that relate directly to the Utah Commission’s August 6, 2012 Order:
Purchased gas request for proposal (RFP) schedule and invitation to review
responses. Topics to be covered in future technical conferences. Review of the unusually cold January 2013. Performance of the high pressure distribution system. Performance of the intermediate high pressure (IHP) distribution system. Basis for the Company’s integrity management program (IMP). Report of recent distribution integrity management program (DIMP) activities. Report of recent transmission integrity management program (TIMP) activities. Basis for the increase in IMP costs from the 2011 to the 2012 IRP. Comparison of transportation alternatives. Transportation Contract No. 2945 expiration and basis for renewal. Update of Ryckman storage contract. Ryckman park and loan contract. Expiration of Clay Basin Contract No. 997. Need for storage and potential options. Update of the System-Wide Gathering Agreement lawsuit.
On March 14, 2013, Questar Gas received confidential responses to its annual RFP
for purchased gas. The RFP was sent out to potential suppliers on March 1, 2013. The Utah Commission held a public technical conference was held on March 27,
2013, with Utah regulatory agencies. The attendees discussed the following topics: Feeder line replacement program. IHP replacement program. Vintage Large Diameter (VLD) Main Replacement Program. 2012 Feeder Line Replacements - cost versus budget and basis for variance. 2013 Feeder Line Replacements – location, size, length and budgeted cost.
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On April 30, 2013, Utah regulatory agencies held a closed meeting to discuss the
following topics (which involved confidential market sensitive information): Schedule of future IRP meetings. Invitation for infrastructure replacement site tour on May 23, 2013. Responses to the Company’s purchased-gas request for proposals. Purchased-gas modeling results and recommendations. Invitation for review of purchased gas proposals. Wexpro capital expenditures by area. Lower 48 gas rig count, efficiencies and total production. Vermillion declining drill time. Pinedale drilling program update. Wexpro finding costs per Mcfe. Utah regulatory agencies held an additional IRP public technical conference on May
14, 2013. The meeting agenda included a presentation designed to bring about a greater understanding of the SENDOUT optimization model in direct response to guidance provided in the Utah Commission’s August 6, 2012 Order. The following topics were discussed:
SENDOUT optimization model; NARUC’s cybersecurity recommendations and the Company’s efforts relating to
cybersecurity; and Issues relating to firm customers changing to transportation service. A public meeting has been planned for June 18, 2013, to discuss the 2013 IRP with
Utah regulatory agencies and interested stakeholders. Over the previous year, the Company has participated in a number of Utah IRP
meetings to address specific issues as ordered by the Utah Commission. The Company welcomes discussion and open dialogue and will schedule additional technical conferences to answer questions and resolve any remaining issues.
During the course of the IRP process, Questar Gas has maintained four main goals
and objectives:
1. To project future customer requirements;
2. To analyze alternatives for meeting customer requirements from a distribution system standpoint, an upstream capacity standpoint, a gas-supply source standpoint and taking into consideration the inter-day load profile of each source;
3. To develop a plan using stochastic data, stochastic methods, and risk management programs that will provide customers with the most reasonable costs over the long term that are consistent with reliable service, stable prices,
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and are within the constraints of the physical system and available gas supply resources; and
4. To use the guidelines derived from the IRP process as a basis for creating a flexible framework for guiding day-to-day, as well as longer-term gas supply decisions, including decisions associated with cost-of-service gas, purchased gas, gathering, processing, upstream transportation, and storage.
The Company utilizes a number of models as part of its IRP processes. The
complexity of the systems being analyzed necessitates the use of computer-based tools. Modeling tools are an integral part of the forecasting, gas network analysis, energy-efficiency analysis, and resource selection processes. In each section of this report where the Company has referred to modeling tools, the IRP contains a description of the functions of each model and the version utilized. The IRP also contains discussion of any material changes (logic and data) from the previous year’s IRP including the reasons for those changes.
An annual IRP process dovetails well with the natural seasonal cycles of the gas industry. Some of the end-of-calendar-year data is not available and fully analyzed for IRP purposes until mid-April. The utilization of this information ensures that the Company is including the most current and relevant information in its IRP. The required data input assumptions utilized in IRP models are voluminous. Nevertheless, the intent of this IRP is to summarize, in a readable fashion, the Company’s planning processes.
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Customer and Gas Demand Forecast System Total Temperature-Adjusted Dth Sales and Throughput Comparison – 2012 IRP and Actual Results for 2012 On a weather normalized basis, Questar Gas’ actual natural gas sales during 2012 totaled 111.1 million Dth. This compares with the 111.0 million Dth projected in the 2012-2013 IRP. Average usage per system-wide General Service (GS) customer on an annual basis was 109.6 Dth, which is close to the projected average of 109.8 Dth. Temperature-adjusted system throughput (sales and transported volumes) was 173.1 million Dth in 2012 compared to last year’s IRP forecast of 170.0 million Dth for the same period.
This year the rate of customer growth is expected to accelerate as the housing recovery gains momentum. Average GS usage is expected to continue to decline, caused in part by the shifting of a number of commercial GS customers to transportation service. Non-GS commercial and industrial consumption will continue to grow modestly, but electric generation will increase substantially in 2014 and beyond with major power plant expansions fueled by natural gas. Temperature-Adjusted Dth Sales and Throughput Summary – 2013 IRP This year’s forecast of temperature-adjusted system sales projects 110.0 million Dth in 2013 and steady growth to 121.0 million Dth in 2023 (see Exhibit 3.11). The slight decrease in projected 2013 sales compared to 2012 sales results from the sales-to-transportation shift mentioned above.
This year’s forecast projects 1,173,742 system GS customers by the end of 2023, with annual Utah GS usage per customer at 95.6 Dth ( see Exhibits 3.1 and 3.2) and annual Wyoming GS usage per customer at 118.3 Dth (Exhibit 3.5). Note that the new Wyoming usage forecast reflects the temperature and elevation compensation in the computation of Dth that began in October of 2012 by order of the Wyoming Commission. The annual usage per Utah residential customer is projected to be 72.0 Dth (Exhibit 3.3) at the end of 2023, and average annual usage per Utah GS commercial customer is expected to be 423.9 Dth by the same time (Exhibit 3.4). The annual usage per Wyoming residential customer is projected to be at 77.7 Dth by the end of 2023 (Exhibit 3.6), and annual usage per Wyoming commercial customer is projected to be at 442.7 (Exhibit 3.7) Dth for the same period. System throughput in this year’s forecast is expected to increase from 173.0 million Dth in 2013 to 214.0 million Dth in 2023 (Exhibit 3.10). The current forecast includes the anticipated throughput for existing electric generation plants fueld by natural gas.
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Residential Usage and Customer Additions
Utah Utah residential GS customer additions in 2012 totaled 11,133, a notable increase over the 8,772 additions in 2011 and the highest number of residential additions since 2008. The rate of additions is expected to increase with the pace of housing recovery in the state beginning with 13,300 additions in 2013 and increasing to 15,200 in 2014. The rate of annual additions is expected to return to pre-recession levels of over 20,000 in 2016.
Actual temperature-adjusted residential usage per customer for the twelve months ending December 2012 was 82.31 Dth, a decrease of about 1.2 Dth from year-end 2011. An average of 81.2 Dth is projected for 2013 with the overall downward trend in average consumption continuing through 2023 as the pace of new dwelling construction increases and energy-efficiency programs continue to incentivize greater efficiency (see Exhibit 3.3).
The primary modeling tool for long-term residential usage is an end-use model
that estimates consumption for space heat, water heating, and other natural gas appliance use based on appliance efficiency and housing characteristics. The model incorporates estimates of housing characteristics, natural gas appliance saturation by efficiency rating throughout the residential customer base, customer growth projections, and projected changes in economic variables that affect use per customer such as the average residential gas bill and household income. Effects on use per customer from the company’s energy-efficiency programs based on past and projected participation have also been addressed in the model. No changes to the model beyond updated inputs have been applied. Along with the end-use model, statistical time series methods using SAS Enterprise Time Series 9.3 and Forecast Pro XE are also utilized in the forecasting process.
Wyoming
In Wyoming 57 residential GS customers joined Questar Gas’ system in 2012, 64% less than the prior year’s additions. However, improving economic conditions lead to a forecast of about 170 additions in 2013. The Company anticipates continued economic improvement will gradually increase customer additions to a pre-recession level of over 400 by 2015.
As noted, the Company has incorporated temperature and elevation compensation
into the computation of Dth. When all 2012 residential usage is adjusted for this compensation, the average annual usage per residential customer in Wyoming was 91.13 Dth, a decrease of just under a Dth from the year prior (also adjusted for temperature and elevation compensation). As in Utah, a general trend toward greater housing and appliance efficiency accelerated by participation in the energy-efficiency programs is expected to perpetuate the general long-term decline in usage per customer through the
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forecasted period. Average usage is projected at 90.3 in 2013 and is forecasted to continue to decline through 2023 (see Exhibit 3.6).
Small Commercial Usage and Customer Additions
Utah
Temperature-adjusted Utah GS commercial usage per customer for the twelve months ended December 2012 was 461.29 Dth. This year’s forecast reflects a continuation of a general downward trend that will be amplified in 2013 and 2014 with the departure of a substantial number of large GS customers shifting to transportation service. Average annual consumption is projected at 455.11 Dth at the end of 2013 and 449.85 Dth at the end of 2014 (see Exhibit 3.4). Utah GS commercial customer additions are expected to change in direct proportion to the changes in Utah GS residential customer additions. Historically, the relationship of commercial customers to residential customers has remained stable. The Company anticipates that approximately 470 customers will be added in 2013. The rate of annual additions will follow residential customer additions and gradually increase to 1,200 additions and above per year from 2016 on.
Wyoming
Usage for commercial GS customers in Wyoming for the twelve months ending
December 2012 was 486.25 Dth when all months of the year are adjusted for temperature and elevation. Average usage is projected to end 2013 at 481.31 Dth and continue its general decline through the forecast period.
The forecast projects about 20 additions in 2013 and a gradual increase to roughly
60 additions in 2016 as economic conditions improve. As with Utah, these projections are driven primarily by residential customer increases. Large Commercial, Industrial and Electric Generation Gas Demand As shown in Exhibit 3.8, annual gas demand among large commercial and industrial customers is steady with gradual increase. Demand is expected to grow from 46.0 million Dth in 2013 to 49.1 million Dth in 2023.
Annual demand among electric generation customers is projected to remain
steady through 2013 at around 26 million Dth and then increase substantially beginning in 2014 with the completion of significant power plant extensions. Demand is projected to double by 2015, reaching a level of around 51 million Dth annually.
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Firm Customer Design-Day Gas Demand As in prior years, the design-day demand projections are based on a one-in-twenty year (five occurrences in 100 years) weather event. More specifically, the design-day firm customer gas demand projection is based on a theoretical day where the mean temperature is –5 degrees Fahrenheit at the Salt Lake Airport weather station and corresponding design-day temperatures are seen coincidentally across the Company’s service territory. Wind speed, average December, January and February Utah GS sales, and prior days’ temperatures and sales are factors that have been statistically significant in predicting daily gas send-out during the winter heating season. The design-day demand projections distinguish between firm sales customers and firm transportation customers for gas supply and system capacity planning purposes. As shown in Exhibit 3.9, the firm sales and firm transportation for the years 2009-2013 reflect send out volumes where peak-day conditions did not occur. The firm sales customer design-day gas supply projection for the 2013-2014 heating season is 1.267 million Dth. The design-day projection grows to a level of 1.377 million Dth in the winter of 2022-2023. Periods of Interruption
It is estimated that under peak conditions 59,000 Dth could be curtailed across the system, 50,000 Dth of interruptible transportation and 9,000 Dth of interruptible sales.
The Utah Questar Gas Tariff states, “At times there may be a need for interruption
on an isolated portion of the Company’s system.” In 2009 the Company performed an analysis to determine if isolation of certain system segments could alleviate pressure concerns while limiting the impact on customers that are neither affected by nor can affect pressures on that segment.
Source Data Where available, the Company has obtained economic, demographic and other data from state and local sources such as the University of Utah (Bureau of Economic and Business Research) and the Utah Governor’s Office of Planning and Budget. When current local data were not available, the Company used nationally recognized sources such as the U.S. Energy Information Administration, the U.S. Census Bureau and IHS Global Insight.
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The Utah and Wyoming Economic Outlook In Tables 3.1 and 3.2 below, is a review of recent history and the current economic outlook:
Table 3.1 Summary of Utah Economy Annual Percentage Change
Description 2007 – 2012 2012 - 2013 2012 - 2017 2012 – 2020 Population 1.9% 1.6% 1.7% 1.8% Personal Income 2.9% 5.7% 6.3% 5.9% Construction Employment -7.8% 7.7% 11.4% 8.4% Manufacturing Employment -1.8% 3.4% 2.1% 1.5% Non-Manufacturing Employment 0.1% 3.4% 2.9% 2.5% Total Employment -0.1% 3.4% 2.8% 2.4% Average Housing Starts 11,727 13,605 20,147 22,367
Source: Based on Spring, 2013 long-term forecasts by IHS Global Insights.
Table 3.2 Summary of Wyoming Economy
Annual Percentage Change
Description 2007 – 2012 2012 - 2013 2012 - 2017 2012 – 2020 Population 1.5% 1.3% 0.8% 0.7% Personal Income 2.6% 5.0% 5.5% 5.1% Construction Employment -3.9% 4.9% 5.1% 3.3% Manufacturing Employment -1.6% 5.0% 1.5% 1.0% Non-Manufacturing Employment 0.1% 0.3% 1.2% 1.0% Total Employment 0.1% 0.5% 1.2% 1.0% Average Housing Starts 2460 1840 2231 2232
Source: Based on Spring, 2013 long-term forecasts by IHS Global Insights.
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The U.S. Economic Outlook
Tables 3.3 and 3.4 contain a review of recent history and the consensus economic outlook:
Table 3.3 U.S. MACROECONOMIC FORECAST
Source: IHS GLOBAL INSIGHT Review of the U.S. Economy – April, 2013
Forecast
2007 2008 2009 2010
2011 2012 2013
Real Gross Domestic Product 1/ 1.9 -0.3 -3.1 2.4 1.8 2.2 2.0 GDP Price Index - Chain Wt. 1/ 2.9 2.2 0.9 1.3 2.1 1.8 1.3 CPIU 1/ 2.9 3.8 -0.3 1.6 3.1 2.1 1.4 Real Disposable Income 1/ 2.4 2.4 -2.8 1.8 1.3 1.5 1.2 Pre-tax Profits 1/ -6.1 -17.4 7.5 26.8 7.3 6.8 1.0 Unemployment Rate 3/ 4.6 5.8 9.3 9.6 8.9 8.1 7.7 Housing Starts 4/ 1.3 0.9 0.6 0.6 0.6 0.8 1.0 3-month Treasury Bills 3/ 4.4 1.4 0.2 0.1 0.1 0.1 0.1 30-Year Fixed Mortgage Rate 3/ 6.3 6.0 5.0 4.7 4.5 3.7 3.5 Trade Balance 2/ -710 -677 -382 -442 -466 -475 -431 Vehicle Sales – Total 4/ 16.1 13.2 10.4 11.6 12.7 14.4 15.3 Real Non-Res Fixed Investment 1/ 6.5 -0.8 -18.1 0.7 8.6 8.0 4.7 Industrial Production 1/ 2.5 -3.4 -11.3 5.7 3.4 3.6 3.2
1/ Annual Rate of Change (Percent) 2/ Billions of 1996 chained dollars 3/ Percent 4/ Million Units
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Table 3.4
Long-term U.S. Economic Outlook Source: IHS GLOBAL INSIGHT Review of the U.S. Economy – April, 2013
2014 2015 2016 2017
2018 2019 2020
Real Gross Domestic Product 1/ 2.8 3.2 2.8 2.9 2.6 2.6 2.4 GDP Price Index - Chain Wt. 1/ 1.7 1.5 1.5 1.5 1.6 1.6 1.7 CPIU 1/ 1.6 1.6 1.7 1.8 1.9 1.9 2.0 Real Disposable Income 1/ 3.5 3.1 3.0 3.2 2.7 2.6 2.3 Pre-tax Profits 1/ 2.8 2.6 -0.2 -0.3 0.7 1.6 1.0 Unemployment Rate 3/ 7.3 6.7 6.3 6.0 5.8 5.6 5.5 Housing Starts 4/ 1.3 1.6 1.6 1.6 1.6 1.6 1.6 3-month Treasury Bills 3/ 0.1 0.2 1.7 3.4 3.7 3.7 3.7 30-Year Fixed Mortgage Rate 3/ 3.9 4.6 5.7 6.5 6.7 6.7 6.7 Trade Balance 2/ -415 -432 -433 -429 -422 -383 -342 Vehicle Sales - Total 4/ 15.7 16.2 16.6 16.6 16.4 16.4 16.3 Real Non-Res Fixed Investment 1/ 6.6 7.2 5.2 5.1 3.9 3.1 3.0 Industrial Production 1/ 3.0 3.3 2.7 3.0 2.8 2.9 2.4
1/ Annual Rate of Change (Percent) 2/ Billions of 1996 chained dollars 3/ Percent 4/ Million Units Alternatives to Natural Gas
Questar Gas customers have alternatives to using natural gas for virtually every application. Some energy applications are dominated by another fuel (cooking, clothes drying) while others are dominated by natural gas (space and water heat). A material shift in customer preference would affect future demand and load profiles.
Solar The Company does not anticipate that solar space or water heat will have a
significant impact in the Company’s service territory. The large investment required does not allow for an attractive payback, thereby limiting the potential.
Air-Source Heat Pumps Air-source heat pumps are becoming more competitive. There are significant
risks to the Company and its customers if these devices proliferate. The loads placed on
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the system will be substantially lower than a similar customer with conventional natural gas space and water heat, yet the investment to serve the customer will not be any lower. Most air-source heat pumps require a back-up heat source for those times when the outside air temperature is too low for the heat pump to meet the load. Since natural gas is the most economic heat source is likely that most customers will select natural gas for the back-up role.
The first risk arises because these customers will increase the peak demand on the system. This risk is especially troubling because it will be very difficult to estimate the additional peak requirement caused by these customers. There are only a handful of days each winter when temperatures are too low for the air-source heat pumps to operate efficiently. As a result the potential for peak load attributable to these units will not be evident in the load data used to predict peak requirements.
The second risk is more significant for other customers. The cost to serve
customers with air-source heat pumps is essentially identical to the cost to serve a similarly situated traditional customer. With the current rate design, the Company will only recover a portion of the cost to serve from air-source heat pump customers. The direct effect of this under-collection will be that other customers will be required to make up the difference. This may lead to a material cross subsidy between traditional customers and the air-source heat pump customers. The Company is monitoring the penetration of air-source heat pumps.
Ground-Source Heat Pumps While ground-source heat pumps may have similar risks to the air-source heat
pumps, the potential for significant penetration is very low. There is a large capital investment required for these installations. Commercial customers with adequate acreage have begun adopting this technology. Lost and Unaccounted For Gas The portion of gas that is lost or unaccounted for is calculated using a moving three-year average of annual proportions that are derived by dividing the total of system receipts for the twelve-month period ending June 30 into the sum of Company use gas (accounts 810 and 812), loss from tear-outs, and volumes that are unaccounted for during the same period. The most recent average of 0.494% reflects meter-level compensation for temperature and elevation in the Utah service territory that began in August of 2010 and in the Wyoming service territory in October of 2012.
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The current calculation for the most recent 3 years is included in Table 3.5.
Table 3.5
QGC QGC QGC QGC QGC Loss & Total Sales, Customer Customer Total Sales & QGC Use Loss Due Unaccounted Transport, Company
Year Sales Transport. Receipts Transportation Acct. 810&812 To Tearouts For Gas Usage and L&U2009-2010 116,891,696 57,431,097 174,322,793 173,831,634 241,077 23,346 226,736 174,322,7932010-2011 115,784,799 54,875,429 170,660,228 169,816,873 236,702 16,335 590,318 170,660,2282011-2012 107,765,322 57,613,566 165,378,888 164,193,992 188,196 23,351 973,349 165,378,888
Total 340,441,817 169,920,092 510,361,909 507,842,498 665,975 63,032 1,790,404 510,361,909
Lost-&-Unaccounted-For-Gas % 0.351% Company Use and Lost-&-Unaccounted-For-Gas % 0.494%
QGC Estimated Company Use and Lost-and-Unaccounted-For-Gas Calculation
Three Year Rolling Average
Questar Gas has implemented the following activities to minimize the volume of
lost or unaccounted for gas:
Temperature and Elevation Compensation. In August of 2010 the Company began compensating for meter-level temperature and elevation in the computation of Dth in its Utah service territory as ordered by the Utah Commission. This same compensation began in the Wyoming service territory in October of 2012. The effect has been a reduction in the volume of unaccounted for gas.
Maintenance work on high pressure feeder lines. When scheduled maintenance work requires the feeder line to be blown down, the line is allowed to feed down to the lowest possible pressure before being completely blown down. This minimizes the amount of gas that is blown down to the atmosphere. The pressure is recorded to allow the amount of gas that is blown down to be calculated.
Replacement project. Replacement projects replace aging infrastructure to ensure the safety and reliability of the distribution system.
Hot tapping. The Company utilizes hot taps when making branch connections on the feeder line system to eliminate the need to blow down sections of the feeder line. The hot tapping process allows this work to be completed while the line remains in service.
Excess flow valves. The Company installs an excess flow valve on any new or replaced service line delivering up to 1,000 cubic feet per hour. The excess flow valve is designed to limit the amount of gas lost in the event of the service line being severed (i.e. third party damage).
Leak survey and repair. The Company regularly conducts leak surveys and performs system maintenance as required. Additional leak surveys are conducted in high consequence areas or areas with aging infrastructure.
Response time to leak calls. The Company continues evaluating ways to reduce response time to gas leak calls through efficiencies in how employees are dispatched to these gas leaks. A GPS system to allow
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dispatchers the ability to dispatch personnel based on their geographic location with respect to the leak is currently being implemented.
Leak detection equipment. The Company utilizes advanced technologies for locating and identifying leaks. Examples include the RMLD (remote methane leak detection) and the Rover (gas detector).
Research and Development. The Company participated in a Gas Technology Institute study to identify factors for fugitive emissions from various types of facilities.
Forecast Exhibits The following charts summarize the 11-year customer and gas demand forecast. All charts contain temperature-adjusted data.
92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23
TRANS 52 53 51 60 49 51 55 52 55 55 46 38 32 31 36 54 62 58 59 53 62 63 80 89 90 90 90 91 91 92 92 93
NON-GS SALES 5 6 9 9 9 10 10 10 10 11 11 10 9 13 12 11 10 10 10 11 10 9 9 9 9 9 9 9 9 9 9 9
SYSTEM GS 72 74 77 79 84 87 84 86 87 85 86 90 91 91 94 93 98 97 97 101 101 101 102 102 103 104 105 107 108 109 111 112
0
50
100
150
200
250
DTH (MILLIONS)
TEMP ADJUSTED THROUGHPUT
Calendarized Tactical Plan Base Case Forecast
Exh
ibit 3.11
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SYSTEM CAPABILITIES AND CONSTRAINTS
Questar Gas System Overview
Historically, Questar Gas customers have been served by an integrated transmission and distribution system connecting natural gas fields in Utah, Wyoming and Colorado to the Company’s Utah, Wyoming, and Idaho markets. The operation of this integrated system remains intact as a result of Questar Gas’ relationship with Questar Pipeline Company (Questar Pipeline). Questar Gas’ ability to serve its customers is dependent primarily upon deliveries from Questar Pipeline and augmented by deliveries from Kern River Gas Transmission Company (KRGT). The Company also relies on deliveries from Northwest Pipeline Corporation to serve the towns of Moab, Monticello and Dutch John; Williams Field Services to serve the towns of La Barge and Big Piney in Wyoming; and Colorado Interstate Gas Company to serve the towns of Wamsutter and Rock Springs. These pipeline systems are part of the modeling process discussed in other IRP sections. This section will focus on Questar Gas’ local distribution system.
Figure 4.1: Daily Profile
Questar Gas builds steady-state and unsteady-state Gas Network Analysis (GNA) system models each year to account for changes in facilities and customer growth. The Company updates these models annually to include facilities and demands as of February of the current year. Questar Gas adjusts the models to match the predicted demand for the following year
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based on the growth projections. The modeling results provided in this report are based on the 2013-2014 models which were created in March 2013.
Questar Gas uses these GNA models to perform system analysis to meet future capacity
requirements while maintaining system reliability. Each time Questar Gas builds the models, the engineering department verifies their accuracy and then reviews the results to determine any required system improvements, supply changes, or contract revisions. The models can then be expanded to meet system analysis needs including planning and operational analysis, creating models at different temperatures and creating different types of models from the standard system model.
System Operations January 2013 was one of the coldest months experienced in Utah. For 14 of the 31 days in January, the Salt Lake International Airport observed-high temperature was at or below the normal-low temperature. Some interesting statistics from January 2013 are:
• 15 of Questar Gas’ top 25 total daily system demand days occurred in January 2013.
• January 14, 2013 was the highest total daily system demand in the history of Questar Gas at 1,225,730 Dth.
- This was 83% of the predicted peak day of 1,474,000 Dth. - The previous high was 1,194,133 Dth on February 1, 2011.
• Stretches of 6 and 13 consecutive days of total daily system demand of at least 1,000,000 Dth.
- Previously there had never been more than four consecutive days of total daily system sales of at least 1,000,000 Dth.
This period of high sendout provided a good test of the adequacy of the distribution
system and the upstream transportation and storage facilities contracted by Questar Gas. During this period, there were no major issues with upstream supplies and no pressure problems on the Questar Gas system.
Supply availability benefited from the improved access to Wexpro production and cost
efficient supply points associated with the extension of Contract No. 2945 (discussed further in Section 7 – Gathering, Transportation and Storage). These amendments provided increased access to some of the best priced supplies in the area and also provided additional capacity using Overthrust Pipeline.
The gate stations served by Questar Pipeline are mostly pressure set stations. This allows
them to be used to meet the hourly load swings of customers on the Questar Gas system. The use of the capacity on Overthrust Pipeline improved Questar Pipeline’s ability to meet these large load swings. Figure 1 shows the impact of these load swings on sendout to the northern system.
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Figure 4.2: Northern System Sendout During High Demand Period
During the highest sendout day, January 14, the highest sendout hour was almost 20% greater than the daily average and over 35% greater than the minimum hour of the day. The total swing from minimum to maximum sendout was 280,941 mcfh on this day. Questar Pipeline stations provided 250,488 mcfh of that swing on this day, which made up 89% of the total daily swing on the Questar Gas system. The ability to meet the hourly load swings is critical to the operation of the Questar Gas System.
Ongoing and Future System Analysis Projects
Master Planning Models Questar Gas has created master planning models and some potential methods to update
them. These models have been created using expected growth projections provided by the Regulatory Affairs department, as well as with input from region engineers on planned developments in their systems. The Company anticipates that, by using these models, the resulting pressures of the peak day analysis will be impacted by the specific growth centers and provide more realistic projections than flat growth models. These models are used in future projected analyses to determine the probable conditions.
System Supply Analysis The Questar Gas system supplies are analyzed each year to determine if the current
contracts, at each Meter Allocation Point (MAP), and available capacity will meet the coming year’s demands. This analysis carefully considers the upstream (transmission pipelines) constraints and capabilities as well as the ability to acquire gas to deliver to the Questar Gas
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system on a peak day. The purpose of this analysis is to determine the amount of gas required on a peak day and if the current contracts (sales and transportation) facilitate this required delivery.
Interruption Analysis
There are a number of non-GS customers on the Questar Gas system who have opted to purchase gas on an interruptible rate utilizing any available excess capacity. While the system is not designed for these customers, it is important to understand at which temperature(s) interruption is required. This analysis divides the system into interruption zones and determines the temperature at which interruption of a specific zone is necessary to maintain service to the surrounding firm customers.
Contingency Planning
Questar Gas uses the HP system models to develop contingency plans for potential
emergency scenarios. Questar Gas’ engineering and pipeline compliance groups coordinate to incorporate the various scenarios into its Emergency Plan. Questar Gas’ engineering department develops studies using the unsteady-state model to determine the system impact and time required to make changes to maintain system integrity or enact emergency procedures. While it may not be possible to model every possible scenario, it is beneficial to prepare general plans that can be tailored to specific events.
Construction Timeline Analysis During construction season, there are numerous projects that require feeder lines and high
pressure facilities to either be limited (pressure or flow) or shut down completely. Each month a construction timeline analysis is performed to determine whether or not the planned construction can take place without adversely impacting customers. This analysis considers the gate station settings, gas supply contracts, construction on the transmission pipelines upstream of the High Pressure (HP) system, probable temperatures and other specific conditions. This allows construction to proceed with confidence that the work planned will not have negative impacts.
Operational Models
Another way Questar Gas prepares to respond to unforeseen scenarios is by developing
and maintaining operational models of the system. Questar Gas maintains these models to represent current actual conditions that exist in the system at expected temperatures. Questar Gas’ engineers review these models on an ongoing basis with Questar Gas’ gas control, gas supply, marketing, operations, and measurement and control departments in order to inform them of expected system conditions.
System Modeling and Reinforcement Questar Gas’ engineering department utilizes steady-state IHP models to determine the
required improvements in order to maintain operational pressures. Questar Gas uses these
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models to identify the required location(s) and sizing of new mains and/or regulator stations. Questar Gas also uses the models to compare the required flow from the regulator stations to the maximum capacity of the existing stations. This analysis provides Questar Gas with the information necessary to determine which reinforcements should be constructed each year. Based on the modeling results, Questar Gas constructs a number of mains and new stations, as well as upgrades to existing stations.
The HP system models have more variables than the IHP system models. Engineers
consider gate stations, existing supply contracts, supply availability, line pack, and the piping system in conducting HP analysis. Because HP projects typically take longer to complete than similar IHP projects, Questar Gas must also identify the need for HP improvements earlier than would be required on IHP projects. Questar Gas and the interstate pipeline companies that supply its system collaborate to identify potential constraints to ensure that Questar Gas’ supply needs are met.
Model Verification
Questar Gas verified the accuracy of the steady-state (24 hour period) GNA models using recorded pressure data and calculated demands. Questar Gas’ engineers built steady-state models to represent the system conditions on Monday, January 14, 2013 using actual data from that day (verification day). Model settings were adjusted to match the actual temperatures and other conditions for this day. The model pressures were compared to actual pressures at verification points and were found to be within 7 percent of the actual pressures on that day. Based on this analysis, Questar Gas has deemed the loads and infrastructure utilized in the GNA models are accurate and the models can confidently be used for their intended purpose.
January 14, 2013 is the highest demand the Questar Gas HP system has ever endured.
System operation would not have gone as smoothly as it did without properly verified models that are the basis for system design. Questar Gas performs model verification annually to ensure that existing facilities and customer demands are accurately represented in the system models. Verified models provide confidence in peak day projected models. Figure 2 shows the hourly volume difference from the Central and Northern Gate stations.
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Figure 4.3: Central and Northern Gate Stations Jan 14 versus Feb 15, 2013
Questar Gas also compared the total modeled demand with the daily recorded deliveries
(sendout) for the same verification day at the gate stations. The results of this analysis showed that the demand the model predicted was within approximately 10 percent of the actual deliveries for the verification day. This difference is likely due to the fact that the steady-state model does not account for system line pack or any lost and unaccounted for gas. Actual system flows would provide for some line pack in the system. The results of the comparisons confirm the accuracy of the calculated demand used in the steady-state models.
Questar Gas verified the unsteady-state (hourly results for a 24-hour period) models in
the same manner as the steady-state models. Questar Gas matched the temperatures and the gate station flows and pressures as closely as possible. The Central and Northern Regions are the largest connected high pressure systems belonging to Questar Gas with 7 gate stations and 2 maximum allowable operating pressure (MAOP) zones. There are three smaller isolated systems which also require unsteady-state model analysis: Summit/Wasatch, Eastern, and Southern. This analysis has 47 pressure verification points as well as the known pressures and flows from the gate stations. None of the pressure differences at the verification points have error values higher than 7 percent, when compared to the actual minimum and average pressures. The results of these comparisons confirm the accuracy of the unsteady-state models.
The unsteady-state models provide the ability for engineers to design for the daily swings
in flow and pressure. This is paramount to system design since gate stations like Little Mountain may swing 1.5 times the average or more depending on the settings of other gate stations. Without the ability to model this phenomenon, the value of peak day model results would be greatly diminished.
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Gate Station Flows vs. Capacity
The gate stations, in the system models, must stay within the physical pressure and flow limits of each specific station. To ensure this, Questar Gas completed a capacity study for each of the gate stations. Questar Gas calculated the hourly and daily flow capacities for each station based on facility limitations, set pressures, and inlet pressures provided by Questar Pipeline and those identified in interconnect agreements with other suppliers. Gate station requirements are influenced by Questar Pipeline’s ability to supply gas at varying volumes throughout the day as the customers’ demands swings throughout the day.
Joint Operating Agreement
On January 26, 2012 Questar Gas and Questar Pipeline completed a joint operating agreement (JOA). The primary purpose of this agreement was to provide “a listing of the expected operating conditions projected for a peak day during the next winter heating season at each of the major Interconnect Facilities” (JOA Page 1). This agreement allowed the Questar Gas’ system planning group to more accurately model the inlet pressures to gate stations from Questar Pipeline. These improvements led to higher modeled pressures throughout the Questar Gas system. This agreement will be updated on an annual basis.
System Pressures Once Questar Gas verifies the system models and properly sets contractual obligations
and station capacities, Questar Gas uses the models to analyze the system to verify that the system has adequate pressures in order to supply Questar Gas customers. Questar Gas uses peak model(s) for this analysis. Peak models include firm loads for sales and transport customers. Questar Gas uses the daily contract limits for applicable customers and assumes that interruptible demands are off system during the peak day.
Northern The Northern Region includes the main system around Salt Lake City and northern Utah,
including Salt Lake, Tooele, Summit, Utah, Wasatch, Davis, Morgan, Weber, Cache, and Box Elder counties. Questar Gas serves this region through interconnects with Questar Pipeline at MAP 164 through the Hyrum, Little Mountain, Payson, Porter’s Lane, and Sunset stations. Questar Gas also serves the region through multiple smaller taps from Questar Pipeline (MAP 162) and KRGT at Hunter Park and Riverton stations.
Questar Gas meets the peak-day demands by serving customers in the Northern Region
from both Questar Pipeline and KRGT. Questar Gas utilizes the KRGT gate stations to provide up to 450 MMcfd of fixed flow gas. Questar Gas utilizes its firm capacity along with its no notice capacity to reserve capacity on Questar Pipeline to manage peak hourly and daily deliveries.
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In the steady-state model, the calculated low point in the main portion of the northern system is 267 psig at the endpoint of Feeder Line 36 (FL 36) in West Jordan. The next lowest pressure in the Northern Region is at Alta, with a steady-state pressure of 266 psig. These pressures remain higher than Questar Gas’ minimum allowable pressure of 125 psig.
The steady-state pressures at some of the key locations in the Northern Region are shown
in Table 1 and Figure 3. Questar Gas models these pressures on a peak day at system endpoints, low points in the area and important intersections. Questar Gas builds steady-state models using average daily flows that most closely represent average pressures for the peak day. The unsteady-state models profile the load throughout the day and represent the pressure fluctuations throughout the peak day.
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Figure 4.4: Northern Region Key Pressures
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Table 1: Steady-State Peak Day Pressures
Location Pressure (psig)
Endpoint of FL29 – Plymouth 308
Endpoint of FL36 – West Jordan 267
Endpoint of FL48 – Stockton 329
Endpoint of FL51 – Plain City 331
Endpoint of FL62 – Alta 266
Endpoint of FL63 – West Desert 324
Endpoint of FL70 – Promontory 323
Endpoint of FL74 – Preston 299
Endpoint of FL106 – Bear River City 330
Intersection of FL29 & FL23 – Brigham City 386
The curves shown in Figures 4, 5, and 6 are the expected peak-day pressures in the
Northern Region. In the unsteady-state models, the low point in the Northern Region is Charleston, at 126 psig, in the Summit Wasatch system. Questar Gas is currently monitoring the Summit Wasatch HP system in order to determine when system improvements are required in the area.
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Figure 4.5: 2013 Northern Peak Day Pressures (North of North Temple)
Figure 4.6: 2013 Northern Peak Day Pressures (South of North Temple)
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Figure 4.7: 2013 Northern Peak Day Pressures (Summit and Wasatch Counties)
The gate stations in the Northern system have varying flow throughout the day. Figure 7
shows the expected peak day flow rates for the large (average volumes greater than 40 MMcfd) gate stations in the Northern System. Little Mountain gate station is the key station in maintaining pressures in the entire Northern HP system. Without Little Mountain’s constantly adjusting flow rates, the current system configuration would not function on a peak day.
Figure 4.8: 2013 Peak Day Gate Station Flow
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Eastern (North)
The Eastern (North) Region includes Duchesne, Uintah, Carbon, and Emery counties, including the cities of Price and Vernal. The Vernal system is a system that was previously owned by Utah Gas Company. This area is served from Questar Pipeline by multiple taps through MAP 163. The pressure at the end of Feeder Line 90 (FL 90), in west Vernal, is being monitored. The minimum pressure calculated by the model is 154 psig during a peak event.
Figure 4.9: 2013 Eastern Peak Day Pressures
Eastern (Northwest Pipeline) The Eastern (Northwest Pipeline) Region includes the cities of Moab, Monticello and
Dutch John. Utah Gas Company previously owned the southeast systems. Questar Gas serves these areas from Northwest Pipeline with two stations in Moab, one station in Monticello, and one tap in Dutch John.
The system in this area is made up of separate subsystems with individual taps off
Northwest Pipeline. All of the segments in this area have adequate pressures and do not require any improvement to meet the existing general service demand.
Southern (Main System) The Southern (Main System) Region encompasses the areas served by the
Indianola/Wecco/Central facilities including Richfield, Cedar City and St. George. Questar Gas
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serves these areas from Questar Pipeline at Indianola station through MAP 166 and from KRGT at Central and Wecco stations.
Using the steady-state model, the lowest modeled pressure on a peak day is 506 psig at
Brian Head. This is higher than the pressures in the northern system due to the higher operating pressures that range between 625-700 psig. Using the unsteady-state model, the lowest pressure in the southern area is 469 psig at Brian Head.
Questar Gas is designing a new pressure station in Santa Clara on the 8-inch feeder line from the KRGT interconnect at Central Station, a pressure increase for Feeder Line 81 (FL 81) and compression at Central Station, in order to meet the growing demand in this area. Questar Gas is currently installing the compressor station and uprating FL 81 so that the uprated facilities will be operational prior to the 2013 heating season. 2013 models assume these improvements have been installed and are functioning.
Figure 4.10: 2013 Southern Peak Day Pressures
Southern (KRGT Taps) The Southern Region includes towns in Juab, Millard, Beaver, Iron, and Washington
counties (all of the towns that are served south of Payson Gate Station and are not part of the Indianola/Wecco/Central system). These areas are all single feed systems served by KRGT.
The system in this area is made up of separate subsystems with individual taps off
KRGT. All of the segments in this area have adequate pressures and do not require any improvement to meet the existing demand.
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Wyoming The Wyoming Region includes Rock Springs, Evanston, Lyman, Kemmerer, Baggs, and
Granger. These areas are served from Questar Pipeline through MAP 168, MAP 169, and MAP 177; from Colorado Interstate Gas (CIG) at Wamsutter and Rock Springs; and from Williams Field Services (WFS) at La Barge and Big Piney.
The Big Piney high pressures system is being uprated this year. The minimum expected
pressure for the 2013 heating season is 184 psig. The uprate will provide an additional pressure buffer and will support a limited amount of system growth in the area.
System Capacity Conclusions
Questar Gas’ HP feeder line system is capable of meeting the current peak day demands with adequate supply and capacity in the system. This system assessment is based on the fact that the gate stations and feeder line system have adequate capacity to meet average daily and peak hourly demands, the supply contracts are adequate, and system models show that pressures do not drop below the design minimum of 125 psig. The system will continue to grow along with the demand and Questar Gas will conduct an analysis annually to ensure that the system continues to meet the peak day needs.
Questar Gas is conducting analysis relating to several system constraints including the
following:
Increasing Demand in the Northern and Central Regions. Questar Gas is evaluating installing new interconnects with Questar Pipeline, KRGT, and/or Ruby Pipeline in order to meet the supply needs associated with long term growth of the Northern and Central Regions. Questar Gas is also considering upgrading existing stations and procuring additional supply contracts for areas experiencing growth.
Before April of 2014, the Payson Gate Station will be uprated along with a portion of Feeder Line 26 (FL 26) in order to facilitate delivery of higher pressures into FL 26. This improvement will allow this segment of FL 26 to operate near its expected MAOP of 720 psig and absorb a portion of the peak-day swing that Questar Pipeline allows Questar Gas. The expected peak day pressures in the Central system will increase as a result of this improvement. This project is discussed in more detail in the DNG Action Plan section of this IRP.
Growth in the Southern Region. Questar Gas’ Southern Region is reaching capacity.
The first improvement to mitigate capacity issues is to install compression on FL 81 at the Central Tap and uprate portions of FL 81. This project is discussed in more detail in the DNG Action Plan section of this IRP.
Low Pressures in the Northern Region. Questar Gas’ modeling shows that pressures near the end of FL 51 (Plain City), in the Northern Region, are low and will likely
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require improvements in the foreseeable future. Questar Gas is considering a variety of options to increase the pressures in that area including a replacement or increased pressures at one of the gate stations in the area.
Low Pressures in West Jordan. Questar Gas is currently installing a new regulator
station extending from Feeder Line 34 (FL 34) that will displace a portion of the demand in West Jordan, relieving FL 36 of the full demand. This will increase pressures in the area. This project is discussed in more detail in the “DNG Action Plan” section of this IRP. HP systems’ pressures in the West Jordan area will also be improved dramatically after completion of the FL 26 uprate project.
Low Pressures in Charleston. Questar Gas is planning improvements in the
Charleston area in Summit County. Current improvement plans upstream of Charleston will increase pressures. The main method being considered to increase pressures at the Charleston regulator station is to extend a high pressure line from Feeder Line 99, a 12-inch line. This improvement will increase pressures in Charleston and Park City. This project is discussed in more detail in the DNG Action Plan section of this IRP.
Growth in Vernal. Additional growth in Vernal may result in the need to reinforce
FL 90. Questar Gas will monitor growth in the area in order to determine when further reinforcement is appropriate. The Company is considering the potential of extending Feeder Line 89 (FL 89) across Vernal and tying to FL 90.
DNG Action Plan
Questar Gas is currently planning, designing and constructing several reinforcement and replacement projects on its system. The following is a brief description of the major projects anticipated by Questar Gas in 2013 and beyond.
Gate Station Projects 1. Hunter Park Gate Station Project: Questar Gas has been improving the capacity
and functionality of the Hunter Park Gate Station since 2008. This project was discussed in detail in the 2012-2013 IRP. Questar Gas also provided an update to this project in the 2nd Quarter 2012 IRP Variance Report. As indicated in these documents, in 2013, Questar Gas is installing a new line heater, two ultrasonic meters, two control valves, a filter separator for liquids and solids removal, a new control system, upgrades to the security system and electrical system, and backup generation for the entire facility. This project was bid in April of 2013 and began construction May 2013. As mentioned in the variance report, Questar Gas estimates the 2013 costs to be approximately $8,164,000 with a revenue requirement of $1.4 million. This amount exceeds the costs detailed in the 2012-2013 IRP. This increase in cost
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can mainly be attributed to increased costs in right-of-way, material procurement, construction contractors and inspection costs.
2. Central Gate Station Project: This project was discussed in detail in the 2012-2013 IRP and updated in the 2nd Quarter 2012 IRP variance report. The costs for KRGT to complete the upgrade on its facilities was $4,497,000, with a revenue requirement of $747,000. KRGT will construct this project in 2013. This project will give Questar Gas immediate capacity of 47 MMcfd at the station, with potential for possible future expansion to approximately 100 MMcfd.
Feeder Line Projects 1. St. George Reinforcement: This project was discussed in detail in the 2012-2013
IRP. Questar Gas started construction of these improvements in March 2013. The anticipated service date for the project is November 1, 2013. Estimated 2013 expenditures are $20,500,000 with a revenue requirement of $3 million.
2. Feeder Line 26 Uprate Project: This project was briefly discussed in the 2012-2013 IRP, and in more detail in the 1st Quarter IRP variance report. In August of 2011 Questar Gas responded to an RFP from PacifiCorp to provide up to 90,000 Dth/day of high pressure gas service to serve the expansion of its Lake Side power plant. In June of 2012, the Commission issued a Report and Order in Docket No. 12-057-04 approving the agreement with PacifiCorp. Questar Gas is uprating its FL 26 to 720 psig in order the meet the requirements of the agreement with PacifiCorp. Questar Gas is currently on schedule to have the project completed in 2013. The estimated total cost for the project is $13,712,000 with a revenue requirement of $2 million. As part of this project Questar Gas will:
• Install line heaters at nine district regulator stations.
• Install regulation and heaters at the cross-over between FL 26 and FL 24.
• Replace approximately two miles of FL 26.
• Install 3,000 lf of 24” diameter tap line to Lake Side power plant.
• Install receiver for in-line inspection tools at Lake Side power plant.
• Install regulation and in-line heaters for the portion of FL 26 north of the new
Lake Side tap.
• Uprate the portion of FL 26 from Payson Gate to Vineyard.
3. Charleston Feeder Line (Feeder Line 99 Extension): Questar Gas has been analyzing this project since 2010. A detailed description of this project can be
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seen in the 2011-12 IRP. Recent GNA modeling shows that growth in the area will require that this project be in service by fall of 2015. For this project Questar Gas plans to install approximately 8.5 miles of 12” HP pipeline from the current termination of FL 99 near Francis, Utah along state road SR-32, and terminating with a tie-in to Questar Gas’ FL 16 on SR-40. In 2014, Questar Gas will commence with right-of-way acquisition and preliminary engineering studies along the proposed route. Questar Gas estimates spending approximately $500,000 in 2014 with a revenue requirement of $99,000. Current plans are to construct the pipeline extension starting spring 2015. The estimated 2015 expenditure for this project is $11,040,000, with an estimated revenue requirement of $1.9 million.
4. Heber City Reinforcement: This project was discussed in detail in the 2011-2012 IRP. Questar Gas completed the preliminary design for this project in 2008. Since then Questar Gas has been monitoring the area for load growth to determine the appropriate time to construct the project. With current load growth projections, it does not appear this project will be required until 2016 or later. The Company will continue to monitor this area for growth and report any changes, if needed, as part of the IRP variance report process.
5. 90th South Feeder Line Extension (Feeder Line 34): The route alternatives for this project were discussed in detail in the 2011-12 IRP. Questar Gas finished the design phase and has started construction of certain sections of this project that required coordination with third-party entities. The majority of the project is currently scheduled to start construction in June 2013. The estimated cost for this project is $1,800,000 with a revenue requirement of $314,000. Any change in project scope or cost will be detailed, if needed, as part of the IRP variance report process.
6. Utah Feeder Line Reinforcement Projects: Questar Gas is currently starting
planning for feeder line projects in Mapleton and North Ogden. These projects will likely take place in the 2015 or 2016 construction seasons. At this time, Questar Gas has not established route possibilities or developed options for constructing these projects. Questar Gas will provide updates, including a comparison of options, as part of the IRP Variance Report process.
7. Feeder Line Replacement Project: Questar Gas is continuing its Feeder Line Replacement program in 2013 with replacements planned on FL 8, FL 14, FL 20, FL 36, FL 41 and FL 50. Pursuant to the Utah Commission’s order approving the Settlement Stipulation, in Docket No. 09-057-16, the Company filed an infrastructure replacement plan detailing the planned projects, the anticipated costs, and other relevant information.
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Intermediate High-Pressure Projects 1. Salt Lake City Belt Main Replacement: The Salt Lake belt main replacement
program was discussed in a technical conference with the Commission and Division on March 27 and in a follow-up meeting with the Division on April 29, 2013. The following is a summary. In 2011, Questar Gas began replacing large diameter IHP belt mains in Salt Lake City. Many of these mains are 1929 vintage and provide critical feed to the city. Questar Gas evaluated several replacement alternatives including bringing high-pressure into the downtown core to decrease IHP line sizes but this proved to be cost prohibitive. (The belt mains could only be downsized from 16 to 12-inch.) To date, approximately 5,500 linear feet or 3% of the total has been replaced. In 2013, Questar Gas will replace 2,300 linear feet of 16-inch IHP steel belt main on 1000 East from South Temple to 300 South. On south Temple, an additional 375 linear feet of 14-inch IHP steel main will also be replaced. Approximately 4,800 linear feet of 2-inch IHP plastic main will also be installed to remove services from the belt main. The total estimated project cost for 2013 is $1,500,000 with a revenue requirement of $249,000. There are no viable alternatives for replacement of vintage main. In 2014, Questar Gas plans to replace an additional 4,100 linear feet of 16-inch IHP steel belt main on 1000 East from 300 South to 800 South. A portion of this line will be relocated to 900 East (between 300 South to 500 South) to avoid crossing conflicts at 400 South. Approximately 3,000 linear feet of 2-inch IHP plastic main will also be installed to remove services from the belt main. The total estimated project cost for 2014 is $2,000,000 with a revenue requirement of $375,000. There are no viable alternatives for replacement of vintage main. In 2015, Questar Gas plans to replace 8,700 linear feet of 10-inch IHP steel belt main on 400 South from 1000 East to 200 West. The 10-inch steel main will be replaced with 8-inch plastic. Because the 8-inch plastic main can be shut down without valves, services will be tied to it. The total estimated project cost for 2015 is $2,500,000 with a revenue requirement of $469,000. There are no viable alternatives for replacement of vintage main.
2. Utah County Belt Main Replacement: The Utah County belt main replacement program was discussed in a technical conference with the Utah Commission, the Division and the Office on March 27 and in a follow-up meeting with the Division on April 29, 2013. The following is a summary. In 2011, Questar Gas began replacing large diameter IHP belt mains in Utah County. Many of these mains are 1931 vintage and provide critical feed to Provo City. To date, approximately 22,000 linear feet or 60% of total has been replaced.
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In 2013, Questar Gas will install 2,500 linear feet of 10-inch IHP steel main from State Street to a new regulator station on 900 South. This new station allowed the downsizing of 1.9 miles of belt main (from 16-inch steel to 8-inch plastic) to the south. Questar Gas plans to replace approximately 2,000 linear feet of 12-inch IHP steel belt main with 10-inch steel on 400 South from 500 East to 100 East. Approximately 1,900 linear feet of 4-inch IHP plastic main will also be installed to remove services from the belt main. Questar Gas also plans to replace approximately 500 linear feet of 10-inch IHP steel belt main with 8-inch plastic near 900 North 800 West, a portion of which crosses the Provo River. The total estimated project cost for 2013 is $1,250,000 with a revenue requirement of $208,000. There are no viable alternatives for replacement of vintage main. In 2014, Questar Gas plans to replace 5,100 linear feet of 10-inch and 12-inch IHP steel belt main on 400 South from 100 East to 800 West with 10-inch steel and 8-inch plastic. The total estimated project cost for 2014 is $700,000 with a revenue requirement of $131,000. There are no viable alternatives for replacement of vintage main. In 2015, Questar Gas plans to replace approximately 6,300 linear feet of 10-inch IHP steel belt main on 800 West from 900 North to 400 South with 8-inch plastic. Questar Gas also plans to replace approximately 1,000 linear feet of 10-inch IHP steel main on 300 North from 800 West to 600 West with 6-inch plastic. The total estimated project cost for 2015 is $700,000 with a revenue requirement of $131,000. There are no viable alternatives for replacement of vintage main.
3. Weber County Belt Main Replacement: The Weber County belt main replacement program was discussed in a technical conference with the Utah Commission, the Division and the Office on March 27 and in a follow-up meeting with the Division on April 29, 2013. Questar Gas will continue to evaluate these lines for future replacement and will offer further updates on the Company’s plans for replacement in future Variance Reports and/or Integrated Resource Plans.
4. Eastern Utah System Replacements: Questar Gas acquired the distribution systems in Moab, Vernal, and Monticello from Utah Gas Company in 2001. After several years of operation, it was determined that these systems were in need of replacement. In 2009, Questar Gas began a replacement program. Replacements in Monticello have been completed. Work in Moab and Vernal is underway. In 2013, Questar Gas will complete the work below. Moab Replacements: Approximately 70,000 lf of main and 500 services will be replaced. A majority of the main (53,000 lf) will be 2-inch plastic. The total estimated project cost for 2013 is $2,600,000 with a revenue requirement of $389,000. There are no viable alternatives for replacement.
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Vernal Replacements: The scope of work for Vernal is still being determined and will be based on budget availability. It is likely to cost less than $1 million.
Project Summary
2013 Projects:
1. Hunter Tap Gate Station. 2. Central Gate Station. 3. St. George Reinforcement. 4. Feeder Line 26 Uprate Project. 5. 90th South Extension (Feeder Line 34). 6. Continuation of the Feeder Line Replacement Project. 7. Continuation of the Belt Main Replacement Project.
2014 Projects:
1. Pre-engineering for Charleston Reinforcement Project (Feeder Line 99 Extension).
2. Continuation of the Feeder Line Replacement Project. 3. Continuation of the Belt Main Replacement Project.
2015 Projects:
1. Continuation of the Feeder Line Replacement Project. 2. Continuation of the Belt Main Replacement Project. 3. Charleston Reinforcement Project (Feeder Line 99 Extension).
Integrity Management Plan Activities and Associated Costs
Overview Questar Gas Company continues to implement integrity activities for transmission lines
as originally mandated by the “Pipeline Safety Improvement Act of 2002” and later codified in the Federal Regulations (see 49 CFR Part 192 Subpart O). The requirements for transmission integrity management require Questar Gas to identify all high consequence areas along the segments of feeder lines that are defined as transmission lines34. Once these high consequence areas are defined, a risk score is then calculated for each segment located in the high consequence area. These risk scores are then summed up for each unique feeder line. These risk scores establish the baseline and sets the priority for when these segments are assessed for integrity. The verification of high consequence areas and calculating the risk score is completed
34 Transmission Lines are those feeder lines (or segments of feeder lines) that are operating (i.e. Maximum Allowable Operating Pressure (MAOP) at or above a pressure that produces a hoop stress of 20% of specified Minimum Yield Strength (SMYS).
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on an annual basis. Questar Gas Company had ten years35 to complete the baseline assessment of all segments in high consequence areas. As explained in the technical conference on March 27, 2013, Questar Gas completed its baseline analysis, with the exception of 1,041 feet of non-contiguous pipe segments located in casing. Each segment must be reassessed at intervals not exceeding seven years or sooner depending on the results of the initial assessment.
Questar Gas Company is required by the transmission integrity rule to conduct additional
preventive and mitigative measures on feeder lines in high consequence areas and class36 3 and 4 locations. These additional measures include monitoring excavations (excavation standby) near these feeder lines and performing semi-annual leak surveys. Other integrity activities include annual high consequence area validation and the day-to-day administration of the program.
On December 4, 2009, the Pipeline and Hazardous Materials Safety Administration
(PHMSA) issued the final rule titled: “Integrity Management Program for Gas Distribution Pipelines.” This final rule became effective on February 12, 2010, with implementation required by August 2, 2011.
The distribution integrity management rule requires operators to develop, write, and
implement a distribution integrity management program with the following elements: Knowledge; identify threats; evaluate and rank risks; identify and implement measures to address risks; measure performance, monitor results, and evaluate effectiveness; periodically evaluate and improve program; and report results. Questar Gas Company continues to implement activities defined in its Distribution
Integrity Management plan for the distribution system. The activities are implemented to mitigate the threats that are identified in the plan.
Transmission Integrity Management
Costs See attached table (Table 2- Transmission Integrity Management Costs) for details on the
anticipated costs associated with transmission integrity management. Baseline Assessment Plan The baseline assessment plan prescribes the methods that will be used to assess each high
consequence area segment. These methods are determined by the known or anticipated threats to these segments. The most common threats on the pipeline include the following: external corrosion, internal corrosion, and third party damage. The assessment methods utilized to address these threats are external corrosion direct assessment (ECDA), internal corrosion direct assessment (ICDA), direct visual examination, and inline inspection.
35 The baseline assessment must be completed by 12/17/2012 (49 CFR §192.921 (d)). 36 Class location as defined by 49 CFR Part 192 (§192.5).
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The Baseline Assessment Plan was completed in December of 2012, with the exception
of 1,041 feet of non-contiguous pipe segments located in casings. There were a total of 10 segments located in casings that were not assessed prior to the December 17, 2012 deadline. These segments are scheduled for final assessment in May of 2013. Questar Gas filed for a special permit to extend the deadline for completing the baseline assessment for these 10 segments.
External Corrosion Direct Assessment ECDA is an assessment method that evaluates the integrity of pipeline segments for the
threat of external corrosion. This includes segments of cased gas transmission pipelines. Refer to Figure 1 for an overview of the ECDA process.
The ECDA methodology is a four-step process. The four steps of the process include: 1. Pre-Assessment - The Pre-Assessment step utilizes historic and current data to
determine whether ECDA is feasible, identify appropriate indirect inspection tools, and define ECDA regions. ECDA regions are areas along the pipeline that have similar characteristics. There may be multiple regions along a single pipeline segment. Examples of ECDA regions include segments in casings, or segments with different types of external coatings.
2. Indirect Inspection - The Indirect Inspection step utilizes above ground inspection
methods (such as close interval survey, pipeline current mapper or direct current voltage gradient survey) to identify and quantify the severity of coating faults and areas of diminished cathodic protection. The analysis of this data can help identify areas along the pipeline segment where corrosion may have occurred or may be occurring. A minimum of two indirect inspection tools are used over the entire pipeline segment to provide improved detection reliability across the wide variety of conditions encountered along a pipeline right-of-way. Indications for indirect inspections are categorized according to severity. A third indirect inspection tool is required for initial assessments of the segment.
3. Direct Examination – This step includes excavations of the pipe for direct
examination to determine if there is corrosion occurring on the pipeline. For initial assessments, a minimum of two excavations are required for each ECDA region and a minimum of four excavations in total for the ECDA project. The ECDA project may contain more than one pipeline and more than one ECDA region. Reassessments require a minimum of one excavation pre ECDA region and a minimum of two excavations in total for the ECDA project. The excavation sites are selected based on a review of the data collected during the pre-assessment and the indirect surveys. This information is used to identify the most likely areas on the pipeline within each region where external corrosion is most likely. The required excavations also include an excavation at a location where no indications are identified. This site is used to help validate the effectiveness of
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the ECDA process. During the Direct Examination step, when corrosion or other pipeline damage or coating damage is found, the pipe or coating is repaired. Additional sites may be selected for examination based on the findings of the required direct examinations.
4. Post-Assessment - The Post-Assessment step utilizes data collected from the
previous three steps to assess the effectiveness of the ECDA process and determine reassessment intervals and provide feedback for continuous improvement.
Internal Corrosion Direct Assessment ICDA is a process to predict the most likely areas of internal corrosion, including those
caused by chemical and microbiologically induced corrosion. ICDA focuses on directly examining locations at which internal corrosion is most likely to occur.
The basis of ICDA is the detailed examination of the most susceptible locations along a
pipeline where liquids, if any, would first accumulate in the pipeline. If the locations most likely to accumulate liquids have no indications of internal corrosion, all other locations further downstream are considered to be free from internal corrosion. ICDA relies on the ability to identify locations most likely to accumulate liquids.
The ICDA methodology is a four-step process that is intended to assess the threat of
internal corrosion in pipelines and assist in verifying pipeline integrity. ICDA was included in the initial baseline assessment plan but will not be required going
forward. After completing the initial assessments for internal corrosion and based on the findings of no internal corrosion, the ICDA process will not be required. The threat of internal corrosion is being addressed through the implementation of Questar Gas’ internal corrosion plan.
Visual Examination of Above-Ground Pipe and Pipe in Vaults Above ground piping (i.e. spans) and piping in vaults that are located in high
consequence areas that will not or cannot be assessed utilizing other methods are assessed by visual examination.
Inline Inspection Pipelines that are constructed and configured or are retro-fitted in such a way as to allow
for inline inspection are assessed by inline inspection tools also referred to in the industry as “smart pigs.” These tools are equipped with sensors that collect data as the tool travels through the pipeline and can reveal areas of wall loss and dents that may require repair or cutout. Some of the pipelines in Questar Gas’ system are currently capable of utilizing this method of assessment. As aging infrastructure is replaced, these new pipelines are being designed and built to accommodate inline inspection tools. There are also advancements being made in new technology that allow some limited application of inline inspection tools for non-piggable
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pipelines that Questar Gas has helped fund through their research and development program. These advanced tools have been used by Questar Gas to assess locations of their system that were not previously assessable without this new technology.
The inline inspection tools provide specific data on the condition of the pipeline segment
being inspected. The data that is collected along the pipeline segment is analyzed for defects and areas of concerns (e.g. wall loss or dents) are excavated for further evaluation and repair or cut out if necessary.
High Consequence Area (HCA) Validation Each year, Questar Gas conducts an on-the-ground survey of all transmission line
segments to validate the current HCAs as well as any new potential sites that may trigger a new HCA. Sites that may trigger a new HCA include the following: office buildings, businesses, community centers, churches, day care centers, retirement centers, hospitals, and prisons.
This information is maintained in Questar Gas’ mapping system and is used to calculate
HCA areas along each transmission segment on an annual basis.
Distribution Integrity Management
Costs See attached table (Table 3- Distribution Integrity Management Costs) for details on the
anticipated costs associated with distribution integrity management. Implementation Questar Gas implemented their written distribution integrity management plan in August
of 2011. Implementation included identifying the threats associated with the distribution system within each operating region as well as calculating a risk score for each identified threat. The risk scores are derived by utilizing known infrastructure data and leak history. The threats and the associated risk scores are validated by operating personnel within each operating region. Once the threats were identified and the risk scores calculated for each threat, each operating region identified possible measures that could be implemented or are currently being implemented that would help mitigate the risks on the distribution system. The process of identifying threats and calculating the risk for each threat is an ongoing process and will be done on an annual basis.
New Regulations That May Impact Future Costs Associated With Integrity The Pipeline Safety Improvement Act of 2011 requires the Office of Pipeline Safety to study the following items:
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1. Automatic and Remote-Controlled Shut-Off Valves for New Transmission Lines – The study will review the benefits of requiring operators to install either automatic or remote-controlled shut-off valves on transmission lines constructed or entirely replaced.
2. Integrity Management – The study will review if integrity management system
requirements or elements of integrity management should be expanded beyond HCAs.
3. Excess Flow Valves – The study is looking at expanding the current requirement
for installing excess flow valves on new or entirely replaced distribution branch services, multifamily facilities, and small commercial facilities.
Figure 10 – ECDA Process Overview
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Table 2 – Transmission Integrity Management Costs $ Thousands
Activity 2013 2014 2015
Transmission Integrity Management
ECDA (Utah Only)
Pre‐Assessment
2013 (FL18, 19, 21, 22, 47, 51, 53) (38 HCA miles @ 2K/mile) 76
2014 (FL23, 28, 29, 71, 81) (23 HCA miles @ 2K/mile) 46
2015 (FL64, 65, 66, 68, 69, 70, 72, 74, 83, 84, 99) (14 HCA miles @ 2K/mile) 28
Indirect Inspections
2013 (FL18, 19, 21, 22, 47, 51, 53) (38 HCA miles @ 30K/mile) 1140
2014 (FL23, 28, 29, 71, 81) (23 HCA miles @ 30K/mile) 690
2015 (FL64, 65, 66, 68, 69, 70, 72, 74, 83, 84, 99) (14 HCA miles @ 30K/mile) 420
Direct Examinations
2011 ECDA (casings – carried over) (FL11, 26, 34) (Pipetel34 ‐ 2 sites, 3 casings @ 125K/site) 250
2012 (FL06, 12, 13, 24, 33, 46) (13 excavations @ 12 K ea.) 156
2013 (FL18, 19, 21, 22, 47) (15 excavations @ 12 K ea.) 60 120
37Pipetel is a self‐propelled inline inspection tool equipped with wall loss sensors and cameras.
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Table 2 – Transmission Integrity Management Costs $ Thousands
Activity 2013 2014 2015
2013 (FL18, 19, 21, 22, 47) (Pipetel – 5 sites, 5 casings @ 150K site) 750
2014 (FL23, 28, 29, 71, 81) (20 excavations @ 12 K ea.) 120 120
2014 (FL23, 28, 29, 71, 81) (Pipetel ‐ 4 sites, 4 casings @ 150 K ea.) 600
2015 (FL64, 65, 66, 68, 69, 70, 72, 74, 83, 84, 99) (24 excavations @ 12K/ea.)(12 in 2015, 12 in 2016) 144
2015 (FL64, 65, 66, 68, 69, 70, 72, 74, 83, 84, 99) (Pipetel – 3 sites, 3 casings @ 150K/site) complete in 2016
Post Assessment
2013 (FL18, 19, 21, 22, 47) (38 HCA miles @ 1.5 K/mile) 57
2014 (FL23, 28, 29, 71, 81) (23 HCA miles @ 1.5 K/mile) 34.5
2015 (FL64, 65, 66, 68, 69, 70, 72, 74, 83, 84, 99) (14 HCA miles @ 1.5 K/mile) 21
ICDA (Utah Only)
ICDA Complete, no longer required
Inline Inspection
2011 ILI (FL 26) Excavations (2 @ 12K ea.) 24
2013 (FL04) 300
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Table 2 – Transmission Integrity Management Costs $ Thousands
Activity 2013 2014 2015
2013 Excavations/ Validation Digs/ Remediation (3 excavations @ 12 K ea) 36
2013 Casings – Pipetel (6 sites, 6 casings @ 150 K/site) 900
2014 (FL85) 350
2014 (FL71) 350
2014 Excavations/ Validations Digs/ Remediation (4 excavations @ 12 K ea) 180
2014 Casings – Pipetel (3 sites, 3 casings @ 150K/site) 450
2015 (FL26) 350
2015 (FL104) 350
2015 (FL71) 300
2015 Excavations/ Validations Digs/ Remediation (15 excavations @ 12 K ea) 180
2015 Casings – Pipetel (4 sites, 4 casings @ 150 K/site) 600
Direct Examination – Spans and Vaults
2013 ‐ Spans Reassessment (7 @ 10K/span) 70
2013 ‐ Vaults (8 @ 10K/vault) 80
2014 – Spans Reassessment (7 @ 10 K/span) 70
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Table 2 – Transmission Integrity Management Costs $ Thousands
Activity 2013 2014 2015
2014 – Vaults (8 @ 10K/span) 80
2015 – Spans Reassessment (7 @ 10K/span) 70
2015 ‐ Vaults (8 @ 10K/vault) 80
Pressure Test Assessment
2013 Casings (4 casings @ 100K/casing) 400
2014 Casings (4 casings @ 100K/casing) 400
2015 Casings (4 casings @ 100K/casing) 400
HCA Validation
Identified Site Survey (QPEC ‐ 1200 hrs @ $30.00/hr) 36 36 36
Identified Site Survey (misc. travel expenses 40 days @ $125/day) 5 5 5
Excavation Standby
4 employees (2080 hrs x 4 x $70.00/hr) 582.4 582.4 582.4
Additional Leak Survey
120 hrs @ $70.00/hr 8.4 8.4 8.4
Additional Cathodic Protection Survey
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Table 2 – Transmission Integrity Management Costs $ Thousands
Activity 2013 2014 2015
System Integrity Support ‐ Cathodic Protection (2080 hrs x $70.00/hr) 145.6 145.6 145.6
Administration
Project Coordination (3 employees (2080 hrs x 3 x $70.00/hr)) 436.8 436.8 436.8
Engineer ‐ Operations Support (0.5 employee (2080 hrs x 0.5 x $70.00/hr)) 72.8 72.8 72.8
Data Integration Specialists (1.5 employees (2080 hrs x 1.5 x $70/hr)) 218.4 218.4 218.4
Technical Writer – Intern (1 employee (1040 hrs @ $30/hr)) 31.2
Consultant – 3rd Party Plan Review 25 25
Supervisor (2080 hrs x $70/hr) 145.6 145.6 145.6
Manager (1040 hrs x $70/hr) 50% TIMP/ 50% DIMP 72.8 72.8 72.8
Training (for IM and Engineering personnel) 22.45 22.45 22.45
Transmission Integrity Management Total ($ Thousands) $ 5,351 $ 5,387 $ 5,134
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Table 3 – Distribution Integrity Management Costs $ Thousands
Activity 2013 2014 2015
Distribution Integrity Management NOTE: The costs estimated here are based on additional and accelerated actions initiated based on the threats identified. The costs also reflect the administration costs associated with this new regulation.
Additional and Accelerated Actions Stray Current Surveys
Additional Leak Survey Region Specific Accelerated Actions Administration Engineer – Operations Support (0.5 employee (2080 hrs x 0.5 x $70.00/hr)) Data Integration Specialists (0.5 employees (2080 hrs x 0.5 x $70/hr)) Manager (1040 hrs x $70/hr) 50% TIMP/50% DIMP Training (for IM and Engineering personnel)
350 350 350
300 300 300
150 150 150
72.8 72.8 72.8
72.8 72.8 72.8
72.8 72.8 72.8
12 12 12
Distribution Integrity Management Total ($ Thousands) $ 1,030.40 $ 1,055.40 $ 1,030.40
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Environmental Review
Questar Gas is committed to compliance with environmental laws and regulations. Some of the regulations with which Questar Gas must comply include the National Environmental Policy Act, the Endangered Species Act, the Clean Air Act, the Clean Water Act, and the National Historic Preservation Act, as well as similar state and local laws.
Agencies permitting and enforcing these regulations frequently place restrictions on
company activities. Requirements have become more stringent over time and can affect the location and construction of Questar Gas infrastructure. When projects may impact the environment, regulatory agencies require permit applications, agency review and public comment periods prior to permit approval. Permit conditions can be rigorous and costly, requiring compliance activities long after project completion, and sometimes for the life of the installation. For example, the U.S. Fish and Wildlife Service may designate critical habitat areas to protect certain listed threatened and endangered species. A critical habitat designation for a protected species, such as the sage grouse or desert tortoise, can result in restrictions to federal and state land use which can delay or prohibit access or use of that land. Because Questar Gas infrastructure crosses many miles of federal and state lands that include the critical habitat of listed plant and animal species, there can be a material impact on location of pipeline facilities and construction schedules. The Clean Water Act and similar state laws regulate discharges of storm water, hydrostatic test water, wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges or accidental releases could result in civil and criminal penalties, orders to cease such discharges, corrective actions, and other costs and damages.
Pre-existing conditions complicating project construction include situations where
Questar Gas’s pipelines, both new and existing, cross contaminated sites owned by third parties. These sites, usually regulated by the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or comparable state regulations, require corrective actions as construction activities proceed. Soils disposition must be determined prior to construction (when presence of the contamination is known), employees properly trained and equipped with protective equipment, and proper disposal and decontamination procedures invoked. Accidental spills and releases requiring cleanup may also occur in the ordinary course of business, requiring remediation; substantial costs may be incurred to take corrective actions in all of these cases. As standards change, the Company may incur significant costs in situations where past operations followed practices that were considered acceptable at the time but now require remedial actions to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions.
New and revised environmental policy is affecting industry, in general, and Questar Gas
specifically, and will result in additional costs to conduct business. For example, federal and
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state courts and administrative agencies are addressing claims and demands related to climate change under various laws pertaining to the environment, energy use and development.
The U.S. EPA adopted the Greenhouse Gas (GHG) Reporting Regulations for the measurement and reporting of carbon dioxide equivalent (CO2e) emissions emitted from combustion at large facilities (emitting more than 25,000 metric tons/year of CO2e) that began with 2010 emissions. That year Questar Gas reported 7.5 million metric tons of CO2e emissions attributable to combustion emissions for all of its customers except those emissions of downstream natural gas local distribution company customers and industrial customers using more than 460 MMCF of natural gas annually for 2010. Reporting under this regulation was expanded to include measurement and reporting of GHG emissions attributed to fugitive methane emissions starting in 2011, incorporating measurement and monitoring of gate-station methane emissions for Questar Gas. Questar Gas reported 7.7 million metric tons of CO2e emissions in Utah in 2011, with approximately 66,260 metric tons attributable to fugitive emissions. For 2012, Questar Gas’ Utah emissions totaled approximately 6.35 million metric tons, with about 67,500 metric tons due to fugitive methane. The difference in quantity of GHG emissions from 2011 to 2012 may be related to the mild winter conditions in 2012, resulting in less natural gas flowing into the Questar Gas distribution system for use in residential appliances.
Figure 11
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Questar Gas believes that it is important for the natural gas industry to be able to scientifically estimate methane emissions from fugitive emissions. In the past, Questar Gas has participated in industry studies to quantify these emissions. In 2013, Questar Gas will participate in the Environmental Defense Fund’s (EDF) project to estimate leakage from the local distribution system, one module of a 5-part study to quantify methane emissions across the natural gas value chain. This study, conducted collaboratively with industry, academia, a consultant and the EDF, will identify realistic GHG emissions factors for the natural gas industry that could then be applied in EPA’s GHG Reporting Rule.
Exhibit 4.1 - Northern System – Peak Day – Steady State
QPC
KRGT
QPC
Henefer:
0.708 MMcfd
Questar Gas (QGC)
Questar Pipeline (QPC)
Kern River Gas
Transmission (KRGT)
Payson:
142 MMcfd
Promontory:
25.4 MMcfd
Hyrum Station:
103.8 MMcfd
Ogden Valley:
4.57 MMcfd
Sunset:
75 MMcfd
Porters Ln:
134.4 MMcfd Hunter Park:
212.0 MMcfd Little Mtn:
112.7/145.5 MMcfd
Jeremy Ranch:
17.2 MMcfd Riverton:
175.0 MMcfd
Heber (Rockport):
6.2 MMcfd
Exhibit 4.2 - Eastern (North) System – Peak Day – Steady State
QPCGordon Creek:
8.0 MMcfd Wellington:
2.4 MMcfd
Myton:
5.50 MMcfd
Island Park:
4.33 MMcfd Bluebell:
5.89 MMcfd
Altamont:
0.27 MMcfd
Questar Gas (QGC)
Questar Pipeline (QPC)
Exhibit 4.3 - Eastern (Northwest Pipeline) System – Peak Day – Steady State
NW
Dutch John:
0.088 MMcfd
Arches:
0.014 MMcfd
Moab 1:
3.65 MMcfd
Monticello:
0.88 MMcfd
Moab 2:
0.97 MMcfd
Questar Gas (QGC)
Northwest Pipeline (NW)
Exhibit 4.4 - Southern (Main) System – Peak Day – Steady State
QPCQuestar Gas (QGC)
Questar Pipeline (QPC)
Kern River Gas
Transmission (KRGT)
KRGT
Wecco:
16.5 MMcfd
Indianola:
22.9 MMcfd
Central:
36.5 MMcfd
Exhibit 4.5 - Southern System (KRGT Taps) – Peak Day – Steady State
Questar Gas (QGC)
Questar Pipeline (QPC)
Kern River Gas
Transmission (KRGT)
KRGT
Beaver:
2.39 MMcfd
Fillmore:
1.59 MMcfd
Scipio:
0.62 MMcfd
Delta (Juab):
1.9 MMcfd
Holden:
0.15 MMcfd
Newcastle:
0.57 MMcfd
E
Exhibit 4.6 -
Questar
Questar
Williams
Colorado
QPC
- Wyoming
Gas (QGC)
Pipeline (QPC
s Field Service
o Interstate G
Hillia
6.7 M
System – P
C)
es (WFS)
Gas (CIG)
Q
Ly
2
Kemmerer
2.2 MMc
ard Flats:
MMcfd
eak Day – S
QPC
Big Piney:
1.2 MMcfd
La Barge:
0.28 MMc
yman:
2.4 MMcfd
r:
fd
Steady State
QPC
Wcfd
e
WFS
Kand
13.8
CIG
0.0
QPC
Wams
0.54
Baggs:
0.40 M
da:
8 MMcfd K
Tap:
1 MMcfd
CIG
utter:
MMcfd
:
MMcfd
Kent Ranch:
4.7 MMcfd
CIG
5-1
PURCHASED GAS Local Market Environment
Monthly index prices for natural gas delivered into Questar Pipeline’s system during the 2012 calendar year averaged $2.57 per Dth. This was lower than the 2011 average price of $3.75 per Dth, a decrease of $1.18 per Dth or 31%. The 2011 and 2012 monthly index prices are provided in Table 5.1 below.
Table 5.1 QPC First-of-Month (FOM) Index Price per Dth
Month 2011 * 2012 Difference
Jan $3.77 $3.09 ($0.68) Feb $4.09 $2.60 ($1.49) Mar $3.54 $2.30 ($1.24) Apr $3.91 $1.85 ($2.06) May $3.93 $1.75 ($2.18) Jun $3.93 $2.21 ($1.72) Jul $3.88 $2.47 ($1.41)
Aug $4.04 $2.68 ($1.36) Sep $3.61 $2.40 ($1.21) Oct $3.55 $2.69 ($0.86) Nov $3.38 $3.28 ($0.10) Dec $3.33 $3.50 $0.17
Average $3.75 $2.57 ($1.18)
* No published QPC index value for April and May 2011. Estimated index based on another local average. The price for natural gas on Questar Pipeline during the 2011-2012 heating season (November-March) averaged $2.94 per Dth compared to an average price of $3.32 per Dth during the 2012-2013 heating season, an increase of $0.38 or 13%. The monthly index prices for the two heating seasons are provided in Table 5.2 below.
Table 5.2 QPC FOM Index Price per Dth – Heating Season
Month 2011-2012 2012-2013 Difference
Nov $3.38 $3.28 ($0.10) Dec $3.33 $3.50 $0.17 Jan $3.09 $3.27 $0.18 Feb $2.60 $3.25 $0.65 Mar $2.30 $3.30 $1.00
Average $2.94 $3.32 $0.38
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Current forecasts of Rockies indices reflect an average price of approximately $4.39 per Dth through October 2013. Prices for the 2013-2014 heating season are forecasted to be approximately $4.63 per Dth.
SENDOUT Modeling Issues Among the most fundamental outcomes from the IRP modeling process each year is a determination of the characteristics of the portfolio of natural gas purchase contracts to be utilized by Questar Gas. A significant portion of the annual gas supply needs of the customers of Questar Gas are met with cost-of-service supplies provided under the Wexpro Agreement (see “Cost-of-Service Gas” section of this report). Supply needs not met by cost-of-service gas must be purchased from natural gas providers. Accordingly, the Company issues a request for proposals (RFP) to potential suppliers on upstream interconnecting interstate pipelines each year. Over the years, Questar Gas has determined that the most favorable time to issue its annual RFP (soliciting proposals for natural gas supplies) is in the late-winter/early-spring time frame. During this time period, sufficient supplies for the upcoming winter heating season are likely to be available and uncommitted. Time is needed for proposals to be developed and submitted by the RFP recipients. Then, the Company needs time to extract all the data, model all the gas supply packages proposed, and complete the contracting process. In the event final agreements do not materialize for packages selected, ample time remains before the winter heating season begins to remedy any shortfalls. On March 1, 2013, Questar Gas sent out its RFP to approximately 55 prospective suppliers. The RFP sought proposals for both base load and peaking supplies on the two major interstate pipeline systems interconnected with Questar Gas; Questar Pipeline and KRGT. The RFP required that base load supplies on Questar Pipeline have availabilities of 365, 180, 150, 120 and/or 90 days. Due to the fact that 50,000 Dth/Day of the 53,000 Dth/Day of capacity obtained by the Company from KRGT’s 2003 Expansion Project are only available during the five winter months of November through March, the RFP required base load supplies on KRGT to have availabilities of 150, 120, and/or 90 days. The Company sought multi-year winter-heating season proposals on both pipelines with terms ranging from two to five years. The Company sought proposals for peaking supplies were sought on both pipeline systems having availabilities of two to four months to meet customer demands during the coldest winter heating season months. Reliability of supplies is a critical issue for Questar Gas. The RFP required that all purchased gas proposals accepted by Questar Gas have, in the underlying confirmation letters, language specifying liquidated damages of $15.00 per Dth for failure to perform. All proposals were also required to have language ensuring creditworthiness and language specifying the minimum advance notice required before nomination deadlines for gas flow.
5-3
On March 14, responses to the purchased-gas RFP were due. Proposals for 223 gas supply packages were received from 15 potential suppliers. As part of the RFP requirements, submissions are required to specify if the same gas supply is offered under multiple proposals. This year supplies offered under base load proposals totaled 458 Dth/day, down from the 610 Dth/day offered last year. Peaking supplies offered on Questar Pipeline’s system totaled 380 Dth/day, also down from the 460 Dth/day offered last year. Peaking supplies offered on KRGT totaled 725 Dth/day, up from last year’s level of 687 Dth/day. Each spring, following the receipt of all the proposals, Questar Gas reviews all the packages offered and extracts the parameters needed as data inputs to the SENDOUT model.38 The pricing mechanisms utilized for each package must be identified and linked to the appropriate index price in the model. Also, the availability of receipt and delivery point capacity on the interstate pipeline system utilized must be resolved. To the extent that the same underlying gas supplies have been offered in different price and term packages, they must be identified to prevent the modeling of more gas than is actually available. This year, 223 supply packages were evaluated by the SENDOUT model.
After these purchased-gas packages are entered into the SENDOUT model, the model is allowed to find an optimal linear programming solution for any one or all of the packages of natural gas. During this optimization process, the SENDOUT model only incurs costs for a package of gas if it elects to include that package. This gives the model freedom to look at all packages and optimize them in a way that utilizes the least-cost combination of resources.
This year 1400 Monte Carlo draws were evaluated during the modeling process. At
the conclusion of the modeling, the draws were analyzed to see which were preferred. Using a statistical analysis package, a procedure was used to group (or cluster) optimized draws in similar ways. “Clustering” is the assignment of a set of observations into subsets so that observations in the same cluster are similar in some sense. For Questar Gas, the clustering is performed for peak day and annual demand.
Next, a follow-up statistical procedure is used to split clusters at cluster designed
levels. This year, as in other years, the cluster analysis was broken into 30 groups and plotted as representations of optimized solutions. A point on the graph represents a cluster and a cluster represents like draws. The resulting plot shows demand on the abscissa of the graph, and peak day on the ordinate axis. At a glance this plot shows how the SENDOUT model met high or low demand against peak day events.
Questar Gas now selects the cluster(s) that most closely meet forecasted annual
demand for the coming year. If it were to choose cluster(s) that also meet design peak day, it would over-purchase. Questar Gas examines the preferred draws that make up the cluster looking at the number of times a given package of gas was chosen and the volume of that package most often used. The more often SENDOUT used a specific package of gas the more favorable that package is in the optimization model.
38 The SENDOUT model and the Monte Carlo method are described in more detail in the Final Modeling Results Section of this report.
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Questar also reviews the original packages in order to verify that it does not entrust too much of its purchase gas to one vendor, that peaking versus base-load contracts seem reasonable, that packages are within the transportation limits of both KRGT and Questar Pipeline, and to verify that a cluster combined with cost-of-service, storage and spot will meet design peak day. Once this screening is completed the most often used packages emerge from the RFP process and are finalized with vendors. Questar Gas includes in its modeling process each year the availability of supplies that can be purchased from the Company’s interruptible transportation customers in Utah and Wyoming. As a condition to receiving interruptible transportation service, the Company’s Utah and Wyoming tariffs allow for the purchase of these supplies during periods of interruption for the benefit of Questar Gas’ firm sales customers. Upon notice by the Company, interruptible transportation customers are required to nominate levels of this resource as specified by the Company. The Company can purchase these supplies at the interconnecting upstream pipeline receipt point and use its own transportation capacity, or the purchase can take place at Questar Gas’ city gates. The tariffs specify a predetermined pricing mechanism for payment for these supplies. Questar Gas has planned on the availability of 50,000 Dth/day of this resource for its SENDOUT modeling process this year, for the months of December through February. The levels of purchased-gas packages selected from the SENDOUT modeling process this year are shown in the “Final Modeling Results” Section of this report. The median purchased-gas volumes from the Monte Carlo simulation for the upcoming gas-supply year are shown by month in Exhibits 9.53 to 9.64 along with each probability distribution. Individual packages of purchased-gas supplies for the base case are shown for the first two plan years in Exhibits 9.85 and 9.88. Of the 15 companies submitting proposals this year, 9 had at least one package selected by the modeling process. Questar Gas made commitments to purchase from the selected suppliers on May 2, 2013. Price Stabilization
During the winter of 2000-2001, the Office, Division and the Utah Commission developed a working depth of knowledge through information provided by the Company and seminars from outside consultants.
On May 31, 2001, the Utah Commission approved a Stipulation submitted May 1,
2001, in Docket Nos. 00-057-08 and 00-057-10 proposing price stabilization measures be used in conjunction with natural gas purchases during the winter months (October – March). Pursuant to the Stipulation, the Company proceeded to hedge portions of its base-load winter natural gas portfolio.
In Wyoming Docket No. 30010-GP-01-62, the Company requested to include costs to
reduce price volatility such as occurred during the winter of 2000-2001. In its October 30, 2001 Order, the Wyoming Commission approved the Company’s request to include stabilization costs in the 191 Account. The Company does not engage in any speculative
5-5
hedging transactions by limiting these price stabilization efforts to contracts or contract amendments that fix or cap prices for gas supplies that are contractually committed to Questar Gas’ system for delivery to end-use retail customers.
For the October 2012 – March 2013 time period, the Company fixed the prices for 25
percent of its base load purchased gas supplies. This resulted in 2.25 Bcf being hedged at an average price of $3.31/MMBtu. Given the forecast fo Company-owned production, the Company does not plan to enter into any such fixed-price agreements during the IRP year, but it may do so in the future.
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COST-OF-SERVICE GAS Cost-of-Service (COS) Modeling Factors For over three decades, the customers of Questar Gas have benefitted from natural gas produced pursuant to the Wexpro Agreement.39
The Wexpro Agreement, signed in 1981, defines the relationship between Wexpro and Questar Gas. Under this relationship, Wexpro manages and develops natural gas reserves within a limited and previously established group of properties. Production from these reserves is delivered to Questar Gas at cost-of-service, which historically, on average, has been lower-priced than market-based sources. In recent years, natural gas supplies provided pursuant to the Wexpro Agreement have exceeded one half of the total annual supplies required to meet the needs of Questar Gas customers. During calendar year 2012, Wexpro produced a record 57.5 Bcf of cost-of-service supplies.40 As development drilling continues to occur, Wexpro anticipates that there will be many more years of production from these sources, due in part to technological improvements in drilling and production methods. By year-end 2012, reserve additions for the year replaced 156 percent of the production for the year.41 From calendar year 2011 to 2012, the total costs, net of credits and overriding royalties, for cost-of-service production increased by approximately 5.0 percent. This increase in cost was accompanied by an approximately 13.2 percent increase in production for Questar Gas. Cost-of-service production is also an effective long-term hedge against price volatility. A continuous drilling program allows for the retention of valuable personnel. More information on Wexpro’s planned development-drilling programs is contained in the Future Resources part of the “Cost of Service” section of this report. A determination of the appropriate production profiles for the cost-of-service gas is among the most important results of the SENDOUT modeling process. This year, Questar Gas modeled 94 categories of cost-of-service production. Last year, it modeled 46 categories. Questar Gas substantially increased the number of modeled categories in order to provide for greater economic and operating precision in prioritizing supplies. Also, this year, Questar Gas extended the time horizon modeled by SENDOUT from 21 years to 31 years. A longer time horizon better reflects the fact that cost-of-service gas is a long term resource. More powerful computing capability has made both of these refinements possible. Questar Gas created these 94 categories of cost-of-service gas to naturally group wells which have common attributes including factors such as geography, economics and operational constraints. A large amount of data must be compiled to provide the inputs to the SENDOUT modeling process. Questar Gas has relied on the expertise of Wexpro personnel in assembling the data elements needed to model each category. Some of those data
39 “The Wexpro Stipulation and Agreement,” Executed October 14, 1981, Approved October 28, 1981, by Public Service Commission of Wyoming and December 31, 1981, by Public Service Commission of Utah. 40 Questar 2012 Annual Report, Page 3. (On a net revenue interest basis). 41 Ibid.
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elements are: reserve estimates, production decline parameters, depreciation and amortization rates, carrying costs, general and administrative costs, operating and maintenance costs, production taxes, royalties, income taxes, and oil revenue credits. The “Final Modeling Results” section of this IRP contains the probability curves and median levels of production for cost-of-service gas resulting from the SENDOUT modeling process this year. Since the late 1990s Questar Gas has submitted quarterly variance reports to Utah regulatory agencies, as required under the Utah Commission’s IRP standards and guidelines. These reports detail the material deviations between planned performance and actual performance of cost-of-service natural gas supplies. Under the 2009 IRP Standards, that process will continue into the future. There are many reasons the Quarterly Variance Reports often show variance between anticipated volumes and actual production. As part of the IRP modeling process, Wexpro and Questar Gas are required to anticipate the production capability of more than 1,300 wells. Some of these wells have not been drilled yet, but are included in the planning process. It is important to note that forecasting production from existing wells is not a precise science, and forecasting for wells not yet drilled involves even more uncertainty. New wells can be, and occasionally are, dry holes. Production from new wells can vary from non-commercial quantities to levels several times that anticipated during the planning process. Fortunately, non-commercial wells occur very rarely. Unanticipated delays during the partner approval process can also postpone planned production. Delays during permitting, drilling and completion can also affect the timing of production volumes. An unexpected archeological find on a drill site can cause extensive delays for all the wells planned for the site, or can cause the wells not to be drilled at all. Even small delays can cause schedules to conflict with environmental windows for the migration, mating and/or nesting of local species, resulting in greater delays. Pad drilling, with all its inherent cost efficiencies can also create delays. Since all the wells on a pad are typically hooked up to a single gathering system, any delay in one well affects the production timing of all the pad wells. For existing wells, a multiplicity of geotechnical factors can affect production levels. Although reservoir engineers are skilled in the utilization of sophisticated techniques to forecast future production decline rates, precisely predicting the performance of reservoirs many thousands of feet deep is complex and uncertain. The fact that the pressures of the connected gathering lines are constantly changing due to fluctuating supplies into, and demands from, the local gathering system further complicates the production process (a phenomenon often totally out of the control of the producers). New wells drilled by any party typically come in at very high pressures and, in the short term, can “pressure-off” old wells temporarily affecting existing production levels from a field. While compression can remedy such problems, those costs must be factored into the overall economics of the production stream. Also, the design and construction of compression facilities takes additional time to complete. There are many reasons for variances between planned and actual cost-of-service gas volumes.
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Producer Imbalances In most of the cost-of-service wells, there are multiple working interest partners. Each of these partners generally has the right to nominate its legal entitlements from a well subject to restrictions as defined in the operating agreement and/or gas balancing agreement governing that well. As the individual owners in a well each nominate supplies to meet their various marketing commitments, imbalances between the various owners are created. Imbalances are a natural occurrence in wells with multiple working interest owners. There are no fields or wells with multiple owners having individual marketing arrangements where an imbalance doesn’t exist. No individual working interest owner can control, in the short term, the level of producer imbalances associated with a well because they do not have control over the volumes that their partners are nominating. Anytime allocated wellhead volumes differ from legal entitlements for any one party an imbalance is created for all the parties in the well. The fact that it is not uncommon for the market of a working interest owner to be lost unexpectedly, either in part or in full, for a variety of reasons, further complicates matters. This can happen without the knowledge of the other parties for a significant period of time, and will contribute to an imbalance. For some wells with multiple working interest partners, contract-based producer- balancing provisions exist. These provisions generally allow for parties that are under-produced to nominate recoupment volumes from parties that are over-produced. Given the time lag in the accounting flow of imbalance information, delays of several months can occur. Complicating the process is the fact that advance notice of several weeks is typically required before imbalance recoupment can begin to be nominated. Over the past year, producer-imbalance recoupment has taken place in the Ace/Jacks Draw area. Table 6.1 shows the monthly volumes nominated in these areas for recoupment during calendar year 2012 and for the first two months of 2013. Separate but similar balancing agreements exist for Ace wells and Jacks Draw wells which are in close geographic proximity. The balancing agreements in these areas allow for an under-produced party to nominate 25 percent of the entitlements of the over-produced parties. Once recoupment starts, an under-produced party must continue taking its share of make-up gas for at least a year. In the Jacks Draw field, Questar Gas has been recouping against a partner. In the Ace field, it is a partner of Questar Gas that has been nominating recoupment. Also over the past year, other parties have been recouping from Questar Gas in the Mesa/Pinedale area and the Moxa Arch area as can be seen in Table 6.1. In the Moxa Arch area, a working interest partner of Questar Gas has been recouping in a number of Church Buttes Buffer wells. The largest recoupment volumes over the past year have been in the Mesa/Pinedale area where Questar Gas has been overproduced for a number of years. As of December 31, 2012, Questar Gas had a total net producer imbalance level for all of the fields from which it receives cost-of-service production of approximately 2.1 Bcf.42
42 A positive imbalance means volumes are owed to other parties.
Formatted: None
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By way of comparison, the total net producer imbalance level for December 31, 2011 was approximately 3.0 Bcf. The Hydrocarbon Monitor reviews producer imbalances as part of its responsibilities. In a recent audit report, the Hydrocarbon Monitor concluded that total producer imbalance levels had been reasonable.43 Future Resources
The current market price of natural gas coupled with future price expectations directly
drives the level of drilling in the U.S. But, other factors play into the drilling decision. Knowledgeable personnel such as reservoir engineers or geotechnical experts are among the most valued assets in any energy production company. Increasing or decreasing staff with swings in market prices generally results in the loss of valuable employees with specific knowledge. It can also make sense to drill when prices are down because drilling costs are generally lower then. By the time a well is drilled and turned to production, prices may have rebounded.
In many situations, drilling permits dictate that leases must be developed within a
specified period of time (such as two years) or the leases will be lost. These provisions generally prevent exploration and production companies from holding leases indefinitely without creating value for royalty owners. In the current price environment, a substantial portion of drilling in shale gas plays is being done on a non-voluntary basis to hold leases.
There can be other factors affecting the rate of leasehold development. For example,
Questar Gas’ customers benefit from the receipt of significant quantities of cost-of-service production from wells in the Pinedale Anticline Project Area (PAPA) in Sublette County, Wyoming. Development in the PAPA is governed by a Record of Decision (ROD), issued by the U.S. Department of Interior, Bureau of Land Management during September of 2008. The ROD was issued in response to certain environmental mitigation measures and operational safeguards proposed by the partners in PAPA.44 As a means of minimizing environmental impacts, the Pinedale ROD, in an orderly and systematic way, allows for concentrated development by limiting the number of well pads and requiring the maximum use of existing well pads before constructing new well pads. Operators are required to “stay on a well pad until the well pad is completely drilled out”.45 Drilling is fundamentally sequential with time limitations for development in certain areas. Wexpro’s focus is to maintain its long-term drilling plans, thereby continuing to benefit Questar Gas’ customers. For calendar year 2013, Wexpro plans on drilling approximately 40 net wells with a capital budget for those wells of approximately $140
43 Wexpro Hydrocarbon Auditor Review, Evans Consulting Company, April, 2013. 44 Record of Decision for the Supplemental Environmental Impact Statement, Pinedale Anticline Oil and Gas Exploration and Development Project, U.S. Department of the Interior, Bureau of Land Management, Cheyenne Wyoming, September 12, 2008. 45 Ibid., Summary, Page 20.
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million.46 For the years 2014 through 2017, the planned net wells are approximately 16, 15, 21 and 29 respectively, with annual investments in the range of $60 to $100 million. Given the uncertainties in the financial and natural gas markets, these longer term estimates could vary. Drilling activity through the remainder of 2013 is expected to focus primarily in the Pinedale field with much smaller drilling programs in Canyon Creek and Trail areas.
Plans, forecasts and budgets for drilling development wells under the Wexpro
Agreement are always subject to change. Many factors including economic conditions, ongoing success rates, partner approval, availability of resources (rigs, crews and services), access issues associated with environmentally sensitive areas, re-completion requirements, drainage issues and demand letters all have an impact on drilling and capital budget projections.
46 “Net wells” are the summation of working interests (total and partial ownership).
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GATHERING, TRANSPORTATION AND STORAGE Gathering and Processing Issues A substantial portion of the supplies utilized by Questar Gas’ customers each year is received pursuant to the Wexpro Agreement, as discussed in the previous section, “Cost-of-Service Gas.” In many situations, gathering and/or processing services are required for these supplies to enter into the interstate pipeline system where they can be delivered to Questar Gas’ city gates. Questar Gas is party to a number of gathering and processing agreements which facilitate these services. Many of these agreements have contractual escalation clauses requiring routine annual adjustments to gathering and processing rates which take place periodically throughout the year. The majority of supplies received pursuant to the Wexpro agreement are gathered under the System-Wide Gathering Agreement (SWGA) between Questar Gas and QEP Field Services (QEPFS). QEPFS was formerly Questar Gas Management Company, an affiliate of Questar Gas. Effective June 30, 2010, Questar Corporation spun off QEP Resources. QEPFS is currently a subsidiary of QEP Resources and is no longer affiliated with Questar Gas. The SWGA, effective September 1, 1993, incorporates a cost-of-service methodology to determine the reservation and usage rates for gathering services. Each year, new rates are calculated based on the previous calendar year costs-of-service allocable to Questar Gas and the previous calendar year gas throughput. Costs are allocated based on throughput during the five winter heating season months of November through March. New rates are effective each year from September 1 through August 31. As specified in the agreement, sixty percent of the annual cost of service is allocated to the reservation charge and forty percent is allocated to the usage charge. During the fall of 2010, Questar Gas requested an audit of the calculation of the gathering rates and charges. Based on the information provided by QEPFS, Questar Gas disputed the rates and charges. On May 1, 2012, Questar Gas filed a lawsuit against QEPFS. Questar Gas continues to dispute the monthly invoices, but makes payment based upon its own calculation of gathering costs under the SWGA. These payments are subject to adjustment pending the outcome of the litigation. In addition, Questar Gas continues to evaluate contracts between the parties. In recent months, the discovery process has been taking place and the Court has not yet set a trial date. The Commission ordered the Company to provide a quarterly update of the proceedings associated with the SWGA.47 The Company has done so in its quarterly variance reports. On March 13, 2013, at a Utah IRP technical conference, the Company presented another update of the SWGA lawsuit. Questar Gas will continue to provide
47 In the Matter of Questar Gas Company’s Integrated Resource Plan (IRP) for Plan Year: June 1, 2012 to May 31, 2013, Report and Order, Docket No. 12-057-07, Issued: August 6, 2012, Page 8.
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regular updates and when final results of proceedings are available, they will be provided to regulatory agencies. Questar Gas includes cost data for the gathering and processing functions each year in the SENDOUT modeling process. Questar Gas used an estimate of what it believes should be charged under the SWGA in this year’s modeling process. The modeling may be revised when the SWGA gathering dispute is resolved. The SENDOUT model uses a logical gas supply network to define the relationships between modeling variables. Exhibit 7.1 illustrates those logical relationships for the gathering, processing and transportation functions as utilized by the model. Transportation Issues Questar Gas holds firm transportation contracts on Questar Pipeline, KRGT and Northwest Pipeline. Questar Gas continues to review capacity requirements to determine the amount of transportation required. As part of the five-year planning process, Questar Gas will evaluate its existing contracts including the Contract No. 241 with Questar Pipeline, Contract No. 1715 with KRGT, and Contract Nos. 139525, 139527, and 139528 with Williams Northwest Pipeline. Contract No. 2945
Questar Gas has contracts for transportation capacity on multiple pipelines. One of these contracts, Contract No. 2945 with Questar Pipeline, was set to expire on October 5, 2013. The term of this contract was for 52,000 Dth/day for 10 years. The analysis of the options associated with this potential term expiration included options from KRGT, Ruby Pipeline, and Questar Pipeline.
The analysis of these options focused on meeting specific requirements. The
requirements for this capacity were to provide access to cost-efficient supply points, to provide pressure support to Questar Gas’ system and, preferably, to provide seasonal capacity to the Wasatch Front. Questar Gas also considered the unique benefits each option provided.
Questar Gas reviewed the proposals and determined that the Questar Pipeline
proposal was the most cost-effective proposal. Questar Pipeline presented a proposal for extending the existing Contract No. 2945 contract with seasonal capacity which includes a pressure guarantee at Hyrum station. In order to maximize the additional benefits of extending the contract, Questar Gas submitted this proposal, with amendments to the existing Contract No. 241 to Questar Pipeline as part of an open season request for 40,000 Dth/day of capacity through the Simon compressor. The amendments provided better access to desirable supply points such as Granger and Shute Creek and also provide the additional benefits of providing for capacity on Overthrust Pipeline that can be used for injections into Ryckman Creek storage in the summer months. Questar Pipeline accepted the proposal as part of its open season. Contract No. 2945 was extended beginning 11/1/2012 through 3/31/2018.
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Kern River Gas Transmission Rate Case Update
Questar Gas is a relatively small Shipper on KRGT’s system holding 50,000 Dth per day of seasonal capacity and 3,000 Dth per day of year-round capacity made available from KRGT’s 2003 Expansion Project. Questar Gas also holds 1,885 Dth per day of year-round ten-year capacity from KRGT’s 2010 Expansion Project. By FERC order, the rates paid for the 2010 Expansion Project are the maximum recourse rates for the 2003 Expansion Project.
KRGT filed its Section 4 rate case with the FERC on April 30, 2004. In its 2012 IRP, the Company provided a more detailed summary of the KRGT rate case that has been ongoing for the better part of a decade.48 By way of an update and in response to FERC’s Order 486-E, Questar Gas sought clarification of the conditions of eligibility filed by KRGT for Period Two rates. KRGT agreed with and FERC acknowledged Questar Gas’ contention that Questar Gas was eligible for Period Two rates with regard to Contract No. 1715.
In the event that Questar Gas continues to need its Contract No. 1715 capacity when its Period One expires in 2018, eligibility for the much lower Period Two rates could potentially save Questar Gas’ customers many millions of dollars.
On March 4, 2013, KRGT filed a petition with the United States Court of Appeals for the District of Columbia Circuit to review FERC Opinions Nos. 486, 486-A, 486-C, 486-D, 486-E, 486-F, and Order Granting Motion for Clarification (Docket Nos. RP04-274-000, RP10-1406-000, and RP11-1499-000). On March 21, 2013, Questar Gas filed a motion in that proceeding for leave to intervene as did a number of other KRGT shippers. Questar Gas continues its active involvement in the Kern River rate case and awaits a decision by the D.C. Circuit on KRGT’s petition. Questar Pipeline Gas Quality
On January 4, 2012, Questar Pipeline filed an abbreviated application, under Section 7(c) of the Natural Gas Act, with the Federal Energy Regulatory Commission (FERC) seeking authority to modify existing facilities and construct new facilities on its southern transmission system.49 This project was designed to provide Uinta Basin oil producers transmission access to the Chipeta Plant where associated natural gas, rich in liquids, could be processed by utilizing Questar Pipeline’s Jurisdictional Lateral (JL) 46, JL 47, and a portion of Main Line (ML) 40.
On July 19, 2012, the FERC issued a certificate of public convenience and
necessity to Questar Pipeline authorizing the Uinta Basin Liquids Project.50 Construction 48 See the Gathering, Transportation and Storage section of the Questar Gas Company Integrated Resource Plan, For Plan Year: June 1, 2012 to May 31, 2013, Submitted: June 8, 2012, pages 7-7 to 7-10. 49 Federal Energy Regulatory Commission, “Abbreviated Application of Questar Pipeline Company To Construct and Modify Pipeline Facilities,” Docket No. CP12-40-000, January 4, 2012. 50 Federal Energy Regulatory Commission, “Order Issuing Certificate,” Questar Pipeline Company, Docket No. CP12-40-000, July 19, 2012.
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commenced on August 13, 2012 and was completed on February 6, 2013. The Uinta Basin Liquids Project commenced service on February 7, 2013.51
As part of the certificate order issued by the FERC, Questar Pipeline was required
to file its modified cricondentherm-hydrocarbon-dew-point52 (CHDP) zone map. On December 17, 2012, the FERC, by letter order, accepted Questar Pipeline’s updated CHDP Zone Map.53 Questar Pipeline’s filing did not modify natural gas quality specifications in Questar Pipeline’s Tariff, but it did change the CHDP zone map by subdividing the previous Zone 8 into two zones. The facilities used to transport liquids-rich natural gas to the Chipeta Plant are in a new Zone 11 designated as a wet zone (35 degree Fahrenheit CHDP limit) with liquids handling facilities.
Questar Gas does not have any cost-of-service supplies in the new Zone 11, but
benefits by its purchases of processed gas from the Chipeta Plant on ML 104. The modified CHDP map with the new Zone 11 is shown in Exhibit 7.2.
Questar Pipeline’s implementation of its CHDP provisions has worked well in
recent years, as no major gas quality problems have occurred.54 By utilizing these provisions, Questar Pipeline has been effective in equitably meeting the delivery needs of its Shippers.
The most prevalent measure of fuel gas interchangeability in the U.S. is the
Wobbe Index.55 Natural gas appliances are rated to operate safely and efficiently within a specific Wobbe Index range. Questar Gas used a consulting firm to establish the Wobbe operating ranges for its service areas. For example, Exhibit 7.3 shows the upper and lower Wobbe operating limits for the Utah Wasatch Front (North) region for various levels of heating value and specific gravity. Questar Pipeline updated this exhibit this year to show the daily averages for 2012 of various sources of natural gas on Questar Pipeline’s system flowing to customers in this region. Charts for other Utah regions are also included this year (see Exhibit 7.4 and Exhibit 7.5). Exhibit 7.6 and Exhibit 7.7 show the same information for the Wyoming eastern and western regions. Although the data for 2012 is similar to that for 2011 for both Utah and Wyoming, these Wobbe values have generally been trending downward in recent years. The construction of natural-gas-liquids processing plants near natural gas fields flowing supplies into the interstate pipelines within the area has contributed to that decline. Should this become a concern in the future on any of the pipelines delivering gas to Questar Gas, there are a number of 51 Federal Energy Regulatory Commission, “Notice of Completion of Construction and Commencement of Service,” Questar Pipeline Company, Docket No. CP12-40-000, February 7, 2013. 52 The cricondentherm hydrocarbon dew point is the maximum temperature at which hydrocarbon components in the gas stream start to condense. 53 Questar Pipeline Company, Docket No. RP13-336-000, Correspondence from Nils Nichols, Director Division of Pipeline Regulation, Office of Energy Market Regulation, Federal Energy Regulatory Commission, to L. Bradley Burton, General Manager Federal Regulatory Affairs and FERC Compliance Officer, Questar Pipeline Company, Reference: Update the Cricondentherm Hydrocarbon Dew Point Map, December 17, 2012. 54 Questar Pipeline Company, Docket No. RP07-457-000, FERC Gas Tariff Filing, May 18, 2007. 55 The Wobbe Index number consists of the higher heating value of a fuel gas divided by the square root of the specific gravity (relative to air) of the fuel gas. Fuel gases with the same index number generate the same heat output over time from a burner given constant pressure and orifice size.
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tools that can be used to manage gas interchangeability including injecting inert gases (or air) in the gas stream, injecting propane, and blending supplies from various sources. Though there are limits as to how much blending can take place on Questar Pipeline’s system, it is a reticulated system, characterized by a diversity of receipt and delivery points and a number of looped-line segments, which Questar Pipeline is able to utilize to optimize its deliveries for its Shippers.
It is difficult to predict the interchangeability of future gas streams received by
Questar Gas. The Company may need to arrange for additional processing or blending in the event it is required to ensure that the gas received from the transmission systems of either Questar Pipeline or KRGT are compatible with the needs of Questar Gas’ customers. Questar Gas will evaluate this on an ongoing basis as it bears the burden of processing pipeline-quality gas to meet its specific requirements.
No Notice Transportation Service On April 8, 1992, the FERC issued Order 636 which required interstate pipeline
accompanies to unbundle their sales and transportation services ensuring that all natural gas suppliers could receive the same quality of transportation services. No-notice transportation service” was among those services which the FERC required interstate pipeline companies to provide on an unbundled basis. FERC explained the requirement to provide this service in Order 636 as follows:
As discussed above, the Commission is adding Section 284.8
(a)(4) to its regulations to require pipelines to provide a "no-notice" firm transportation service if they are providing a "no-notice" bundled, city-gate, firm sales service on the effective date of this rule. The Commission expects the pipelines and all interested participants to craft in the restructuring proceedings the operating conditions needed to ensure that the pipelines can provide a "no-notice" transportation service pursuant to which firm shippers can receive delivery of gas on demand up to their firm entitlements on a daily basis without incurring daily balancing and scheduling penalties. This "no-notice" service will enable pipeline customers to continue to receive unnominated volumes to meet unexpected requirements caused, for example, by unexpected changes in temperature. Thus, pipeline customers will be able to receive varying volumes of gas to meet their fluctuating needs during a twenty-four hour period. So, for example, constant rate of flow requirements would not apply to prohibit delivery on demand throughout the day up to a customer's daily firm entitlement under this service.56
56 FERC Order No.636, Final Rule, Docket Nos. RM91-11-000 and RM87-34-065, pages 88-89.
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In FERC Order No. 636-A, issued August 3, 1992, the FERC shed additional light on its previous order by providing:
The Commission clarifies that former bundled sales customers are
entitled to receive the same quality and quantity of transportation service they were previously receiving as part of their sales service before unbundling.57
Questar Gas was entitled to the provision of no-notice transportation (NNT)
service from Questar Pipeline because it had been receiving “’no-notice’ bundled, city-gate, firm sales service” from Questar Pipeline previous to Order 636. In its Order 636 restructuring application, Questar Pipeline filed a NNT service rate schedule. In order to receive the same “quality and quantity of transportation service” needed previously, Questar Gas subscribed to this NNT service offered by Questar Pipeline. And, it was primarily the rationale given by the FERC which necessitated the receipt of this service by Questar Gas . . . “unexpected changes in temperature.”
NNT service provides flexibility that allows Questar Gas to receive volumes of
gas to meet demand caused, for example, by unexpected changes in temperatures.58 Temperatures within Questar Gas’ service area can be among the coldest in the nation. Temperature swings along the Wasatch Front can be large, sudden and difficult to predict. The daily and even hourly gas demand resulting from changes in temperatures can be substantial. NNT service provides Questar Gas the ability to provide service within this ever-changing environment. NNT service allows Questar Gas to reserve transportation and storage capacity on Questar Pipeline during the regular nomination cycles the day prior to actual gas flow. Questar Gas uses its NNT quantity to facilitate withdrawals and/or injections of gas utilizing Questar Gas’ capacity in Clay Basin and the aquifers in order to meet Questar Gas customers’ actual changing load without incurring overrun penalties and imbalances (see subsequent “Storage Issues” section).
With its NNT service, as long as Questar Gas makes the gas supplies available on
demand, Questar Gas can make deliveries that exceed nominations in order to meet its actual demand requirements, and to avoid the nomination restrictions that would otherwise limit Questar Gas’ ability to match its nominations to its needs. NNT service also allows Questar Gas to take less gas than it nominates, if circumstances warrant, without incurring penalties or imbalances. NNT service does not give Questar Gas the right to exceed its daily contract capacity and the daily swings must be within the NNT quantity contracted for by Questar Gas.
Questar Gas utilized its NNT every day throughout the 2012/2013 heating season. Questar Gas used NNT service 86 days during the heating season to provide reduce nominations by reducing withdrawals or injecting into storage. Questar Gas used NNT
57 FERC Order No. 636-A, Order Denying Rehearing in Part, Granting Rehearing in Part, and Clarifying Order No. 636, Docket Nos. RM91-11-002 and RM87-34-068, page 141. 58 For a more detailed discussion of the need for NNT service, see Questar Gas Company Integrated Resource Plan for Plan Year: May 1, 2008 to April 30, 2009, submitted May 1, 2008, pages 7-2 to 7-4 and Exhibits 7.2, 7.3 and 7.4.
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the remaining 65 days to provide for additional storage withdrawal. The maximum daily storage withdrawal reduction for the heating season was 203,542 Dth with an average daily withdrawal reduction of 89,014 Dth. The maximum daily storage withdrawal increase for the heating season was 181,602 Dth with an average daily increase of 51,155 Dth. The NNT usage for the heating season is shown in Figure 1 below.
Figure 7.1: No Notice Transportation Usage – 2012/2013 Heating Season
Storage Issues Questar Gas holds firm contracts for storage services at four underground gas storage fields to respond to seasonal winter and peak demands. The fields are Leroy, Coalville, Chalk Creek and Clay Basin. Leroy, Coalville, and Chalk Creek are aquifer storage facilities owned by Questar Pipeline that are utilized primarily for short term peaking. Questar Gas fully subscribes the aquifer facilities. Questar Gas will be reviewing these contracts as part of the five-year planning process. Clay Basin is a depleted dry gas reservoir used for both seasonal base load and peaking purposes. Clay Basin, also owned by Questar Pipeline, is utilized by both Questar Gas and other storage customers. Questar Gas’ inventory for its storage facilities are outlined in the following table:
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Table 7.1
Facility Maximum Inventory (MDth)
Clay Basin 13,419 Leroy 886 Coalville 720 Chalk Creek 321
The storage facilities of Leroy, Coalville, Chalk Creek, and Clay Basin are used as primary sources in conjunction with Questar Gas’ NNT service. The ability to reserve capacity and change nominations to match changing demands aids Questar Gas in meeting its daily load profile.
Leroy and Coalville Storage Since the year 2000, the operation of the Leroy and Coalville storage facilities has
been modified from procedures followed historically to provide more flexibility and enhance storage efficiency. Following the end of the withdrawal season, the inventories in these facilities have maintained a working gas inventory of approximately 30–50% of maximum capacity through the summer months. Previous practice was to completely deplete the facilities each year at the end of the withdrawal season. The advantages of this revised mode of operation are as follows:
Wells in the aquifer storage are not “watered out” at the end of the withdrawal cycle, which improves well efficiency when storage injections are initiated in the fall.
Injection compression fuel gas requirements are reduced (only 50-70% of the working capacity needs to be injected in the fall to fill the reservoir).
A shorter, more predictable, and easily managed withdrawal/depletion schedule results at the end of the heating season.
A shorter injection season for reservoir refill is required in the fall. With the aquifer inventories at 50%, the flexibility exists to inject
significant volumes due to gas displacing water in the reservoir.
In general, current operating practices at both the Leroy and Coalville facilities are as follows:
Injections into the reservoirs commence in early September from an initial
inventory of approximately 30-50% of maximum working inventory. Injections continue until an inventory of approximately 75% of maximum is reached by early October. Injections follow a specific schedule determined by well and reservoir characteristics which minimizes the potential for “fingering” (gas being trapped behind water in the aquifer and resulting gas loss).
In early October, scheduled aquifer injections are halted to balance gas supplies with Questar Pipeline’s testing program conducted at the Clay
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Basin storage facility. The testing requires one day of injection at a controlled rate followed by a 7-day no flow period for pressure stabilization. Depending upon system demand and the gas supply situation during the no flow period, the 75% inventory at Leroy and Coalville affords the flexibility to either inject or withdraw to meet system balancing requirements.
Following the Clay Basin test, controlled injections again commence in Coalville and Leroy with maximum inventory being reached by early November for the heating season.
Both Coalville and Leroy are utilized to meet peak load requirements through the heating season as well as manage the morning and evening load swings on high demand days. During periods of lower winter demand, the reservoirs are refilled to maximum inventory when possible.
During March, when the need for peaking withdrawals has passed, the reservoirs are partially drawn down (for use) to inventories ranging from 50–75% in preparation for Clay Basin testing conducted during April. The April Clay Basin test consists of a one week withdrawal period followed by 2 days of controlled withdrawal. Following the withdrawal period, Clay Basin is shut in for 14 days for pressure stabilization. Maintaining Coalville and Leroy at the indicated inventory range during this period provides the flexibility to either inject or withdraw based upon system balancing needs.
At the end of the spring Clay Basin test, Leroy and Coalville are then drawn down to inventory levels of approximately 30–50% and then maintained at that level until refill commences in the fall. Periodically, Questar Pipeline will completely draw down one aquifer when necessary to conduct an inventory volume verification analysis. During the summer of 2012, the Coalville aquifer was drawn down completely. Questar Pipeline reported that the inventory verification process went well for Coalville.
Chalk Creek Storage Due to the nature of the Chalk Creek storage formation and in order to minimize
losses, Questar Pipeline does not practice cycling and partial inventory maintenance during the summer. Operation at Chalk Creek is as follows:
Injections from zero working gas inventory commence in early November
following a controlled well and injection profile. Maximum inventory is reached by mid-December. From December through early March, Chalk Creek is typically held in
reserve unless very high demand periods are experienced. In early March, the reservoir is blown down in a controlled manner to zero
working gas inventory and is then shut in until refill injections commence in the fall.
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Questar Pipeline places emphasis upon following these operating procedures in order to minimize gas losses and to ensure efficient storage facility operation.
Clay Basin Storage
The Clay Basin storage facility is located in the northeast corner of Utah, roughly
50 miles from Rock Springs, Wyoming. The Clay Basin field has two producing sandstone formations, the Frontier and the Dakota. The Frontier formation is still producing natural gas today and the Dakota formation is used for storing gas. The Dakota formation was largely depleted by 1976 when construction of the storage facilities began. Today, the Clay Basin reservoir has the largest capacity of any underground storage facility in the Rocky Mountain Region.
Questar Gas receives storage service at Clay Basin under rate schedule FSS.
Billing under rate schedule FSS consists of two monthly reservation charges and separate per unit usage fees for injection and withdrawal. The first reservation charge is based on each shippers minimum required deliverability (MRD) as stated in each shipper's storage service agreement. The tariff provisions governing Clay Basin assure that customers will receive at least their MRD. To the extent that shippers have inventory in excess of that necessary for their last day of withdrawals, additional deliverability is available for allocation according to predetermined formulas. The second monthly reservation fee is an inventory capacity charge based on each shipper’s annual working gas quantity.
On October 4, 2011, Questar Pipeline held a non-binding open season to
determine interest in an additional 8 Bcf of firm storage capacity at Clay Basin. A unique feature of the firm capacity in this non-binding open season was that it did not guarantee an MRD, making less valuable than existing firm capacity. The open season continued until October 31, 2011. Questar Gas participated in this non-binding open season and performed some modeling analysis on this potential new capacity. The response to this non-binding open season suggested positive market support. Questar Gas will continue to monitor the situation.
Clay Basin Contract No. 997 Questar Gas’s firm storage Contract No. 997 with Questar Pipeline had a term
expiration of April 30, 2013. This is one of three Clay Basin firm storage contracts between Questar Gas and Questar Pipeline. The terms of this contract are for 3,727,500 Dth for 20 years, beginning 9/13/1993 and ending 4/30/2013. This section will examine the storage options that Questar Gas reviewed as part of the analysis of the potential term expiration of the Contract No. 997 with Questar Pipeline.
As part of the analysis associated with the expiration of Contract No.997, Questar
Gas evaluated multiple alternatives. Questar Gas considered the options of renewing the existing Contract No. 997, reducing the total storage volume held by Questar Gas, or replacing the contract with a new contract with Ryckman Creek Gas Storage Project (Ryckman or Ryckman Creek) through their open season. Questar Gas reviewed each of these options in detail and evaluated each to identify the best available alternative.
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Questar Gas provided a response to the Ryckman open season to closely match the costs and capacity of Clay Basin Contract No. 997. However, the price submitted to Ryckman Creek was not sufficient to have the bid accepted. This put Questar Gas lower on the priority list for negotiations for capacity. Questar Gas analyzed the different options including a direct analysis of carrying costs, a full 31-yr cost analysis using the SENDOUT model, and a review of all other potential issues, concerns, or advantages of the available options. The review of 5-year shut-in costs and the SENDOUT analysis both showed cost savings associated with re-contracting for storage capacity rather than reducing the overall storage capacity. Based on the cost savings for carrying costs, the savings projected by the SENDOUT model and the results of the additional considerations, the contract capacity associated with Contract No. 997 was extended. The new terms of the agreements match the previous terms and the term was extended through 3/31/2020. Questar Gas chose this date for term expiration based on maximizing the cost savings associated with the contract. The maximum cost savings were actually realized in January 2020, however, ending the contract in January would not allow for the storage to be fully emptied in the event of a warmer winter in 2020.
Clay Basin Gas Quality During 2007, when Questar Pipeline was resolving CHDP issues on its
transmission system, it also remedied CHDP issues at its Clay Basin storage facility. On August 23, 2007, Questar Pipeline filed revisions to its tariff with the FERC. Questar Pipeline also filed the “Stipulation and Agreement” negotiated with all of the Clay Basin storage customers. The filing included the “Joint Petition of Questar Pipeline and Firm Customers for Approval of Stipulation and Agreement and Request for Expeditious Action.”59 The FERC accepted the revised tariff sheets on November 7, 2007, to be effective on January 1, 2008, and also approved the Stipulation and Petition.60 As a result of these FERC actions, Questar Pipeline refunctionalized the Kastler Processing Plant as a Clay Basin storage asset (it was previously a transmission asset) and installed additional processing facilities, thus ensuring a total delivery capability of 320,000 Dth per day to either Northwest Pipeline or Questar Pipeline. Questar Pipeline completed this project in December of 2008 at a cost of approximately $12 million. Questar Pipeline credits revenues received from the sale of natural gas liquids each year to the cost-of-service conditioning- storage gas. Questar Pipeline returns any revenue above the cost-of-service to Clay Basin shippers. If revenue from liquids does not cover the cost of service, Clay Basin shippers pay an increased in-kind fuel reimbursement to make up the difference. On April 18, 2013, Questar Pipeline indicated that for the May 2012 through April 2013 time period, it expected that the liquids revenues would fall short of the costs of service. Any such shortfall would have the effect of increasing, during July of 2013, the in-kind 59 Questar Pipeline Company, Docket No. RP07-606-000, FERC Gas Tariff Filing, August 22, 2007; and Questar Pipeline Company, Docket No. RP07-606-001, Amended FERC Gas Tariff Filing, August 30, 2007. 60 Federal Energy Regulatory Commission, Questar Pipeline Company, Docket Nos. RP07-606-000 and RP07-606-001, Letter Order Accepting Tariff Sheets dated November 7, 2007, “Reference: Stipulation, Petition, and Revised Tariff Sheets.”
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Fuel Reimbursement required of Questar Gas and all other Clay Basin Shippers under Questar Pipeline’s tariff. Preliminarily, it is expected that the dollar impact on Questar Gas will be roughly $150,000. The refunctionalization of the Kastler Plant and the installation of new processing facilities have effectively resolved the liquids issues at Clay Basin.
Ryckman Creek Gas Storage Ryckman Creek was discussed at length in the Company’s 2012-2013 IRP. The
Ryckman Creek storage project involves the utilization of a partially depleted oil and gas field located approximately 25 miles southwest of the Opal Hub in southwestern Wyoming (see Exhibit 7.8). Working gas capacity for the first phase of the project was designed to be 18 Bcf. Initial injection rates are expected to be approximately 210 MMcfd and withdrawal rates are expected to be approximately 210 MMcfd. It is expected that the working gas inventory will be able to be cycled from one to three times per year. Ryckman purchased the existing Canyon Creek Compression facilities which have been incorporated into the project. The facility interconnects with KRGT, Questar Pipeline, Northwest Pipeline, Overthrust Pipeline and the Ruby Pipeline.
Ryckman held a non-binding open season from October 6, 2010 to November 1,
2010. Though Questar Gas was not invited to bid for capacity in the open season, the Company subsequently contacted Ryckman and engaged in discussions. Effective April 18, 2011, Questar Gas entered into a Firm Gas Storage Service Precedent Agreement with Ryckman for 2,500 MDth of storage capacity. On April 22, 2011, the staff of the FERC issued an environmental assessment of the Ryckman project. And, on July 28, 2011, the FERC issued a certificate of public convenience and necessity to construct and operate the proposed facilities.61 With the approval of its gas tariff by the FERC, Ryckman filed notice of commencement of service for certain project facilities on August 21, 2012.62 On this date, Ryckman began receiving injection nominations.
During the Fall of 2012, Ryckman conducted a non-binding open season for up to
8 Bcf of firm, high-deliverability, multi-cycle working gas storage capacity beginning April 1, 2013. The open season ran from October 3, 2012 to November 2, 2012. Ryckman reported that responses totaling 3.5 times the capacity offered were received.63 Questar Gas responded to this Open Season and Ryckman did not accept Questar Gas’ proposal. Questar Gas and Ryckman continue to discuss storage options.
Ryckman filed its Final Request for In-Service Authorization on February 21,
2013, seeking approval to place the last remaining project facilities in service on or
61 Federal Energy Regulatory Commission, Ryckman Creek Resources, LLC, CP11-24 and CP08-433, “Order Issuing Certificate and Approving Abandonment,” July 28, 2011. 62 Correspondence from Thomas E. Knight, Attorney for Ryckman Creek Resources, LLC, to Kimberly D. Bose, Secretary Federal Energy Regulatory Commission, Subject: Notification of Commencement of Service,” Docket No. CP11-24-000, dated August 21, 2012. 63 “Ryckman Creek’s Opal hub gas storage open season oversubscribed,” Oil and Gas Journal, Houston, www.ogj.com/articles/2012/11/ryckman-creeks-opal-hub-gas-storage-open-season-oversubscribed.html, November 16, 2012
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before February 27, 2012.64 The FERC approved this request on February 26, 2013, subject to compliance with all remaining terms and conditions of the July 28, 2011 order.65
Ryckman has been unable to withdraw gas that meets the gas quality standards of
all of the interconnecting pipelines. In order to resolve this issue, Ryckman installed a nitrogen rejection unit (NRU). However, before it was fully operational, there was a fire at the NRU. On April 22, 2013, Ryckman posted a critical notice effective April 20, 2013, 5:38 PM, indicating that the storage facility had been shut down due to the fire and that force majeure had been invoked as per Section 6.19 of the Ryckman Tariff. All services were suspended. Though services have since been reinstated, the gas quality issue has not yet been resolved and the current status of the NRU is in unknown. In April 2013, Ryckman indicated that the storage facility may be fully functional as early as April of 2014. Questar Gas will not consider signing a firm storage agreement until the facility is fully functional and able to withdraw gas that meets the gas quality standards of the interconnecting pipelines. Questar Gas has made no injections into its 2,500 MDth of capacity under its Firm Gas Storage Service Precedent Agreement and has made no associated demand charge payments.
Ryckman Creek Park-and-Loan In October of 2012, Questar Gas entered into a park-and-loan agreement with
Ryckman Creek. The purpose of the contract was to provide greater injection capability during the October Clay Basin Test. Warm weather was predicted which resulted in injection requirements above the injection capabilities of the aquifers. It was determined that a park-and-loan contract with Ryckman Creek was the most cost effective alternative. The terms of the agreement allowed for the storage of 138,000 Dth. The injection period was 10/5/2012 though 10/18/2012 and the withdrawal period was originally 4/1/2013 through 4/30/2013. The contract allowed for injection rates up to 23,000 Dth/day and withdrawal rates up to 4,600 Dth/day. Questar Gas has injected 138,000 Dth under the agreement. However, due to the issues at the storage facility, Questar Gas cannot withdraw those volumes. Questar Gas is working with Ryckman to extend the term of that agreement.
Magnum Gas Storage The Magnum Gas Storage Project (Magnum) consists of the construction and
operation of a high deliverability, multi-cycle salt cavern storage facility, and a connecting header pipeline. The proposed caverns, with a working gas capacity of some 42 Bcf, have a planned location approximately one mile north of the town of Delta, Utah. Magnum anticipates that the project will be capable of injecting up to 0.3 Bcf per day and withdrawing up to 0.5 Bcf per day with an inventory cycling capability of from nine to 64 Correspondence from Thomas E. Knight, Attorney for Ryckman Creek Resources, LLC, to Kimberly D. Bose, Secretary Federal Energy Regulatory Commission, Subject: Final Request for In-Service Authorization,” Docket No. CP11-24-000, dated February 21, 2013. 65 Correspondence from Lauren H. O’Donnell, Director Division of Gas – Environment and Engineering, to Thomas E. Knight, Attorney for Ryckman Creek Resources, LLC, Re: Authorization to Commence Partial Service, dated February 26, 2013.
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twelve times each year. The storage facility has been designed to interconnect with the interstate transmission systems of KRGT and Questar Pipeline near the town of Goshen, Utah.
During March of 2012, Magnum notified the FERC that it was adding facilities to
its project to facilitate the storage of natural gas liquids (NGLs) such as butane and propane.66 During June of 2012, Magnum requested an extension of its Construction Permit to begin the solution mining of the gas storage caverns from Utah State officials due to unforeseen changes in the natural gas markets.67 In a status report filed with the FERC on July 23, 2012, Magnum indicated that solution mining of the first NGL cavern would begin in late August 2013. Expectations are that solution mining of the first natural gas cavern will start in March of 2014. Construction of the natural gas pipeline and associated compression facilities will not take place until 2015.68 For more information on the Magnum Gas Storage Project (including maps) and the involvement of Questar Gas, see Questar Gas’ Integrated Resource Plan for plan year June 1, 2012 to May 31, 2013, Gathering, Transportation and Storage Section.
Storage Modeling in SENDOUT The costs, contractual terms and operating parameters for each of the four storage
facilities subscribed to by Questar Gas are modeled in SENDOUT. A forecast of the storage inventory available at the beginning of the first gas-supply year is also needed for each storage facility for the SENDOUT modeling process. When Questar Gas modeled storage and inventory, it expected that the inventory at Clay Basin on June 1, 2013 would be approximately 0.75 Bcf.
66 Correspondence from Tiffany A. James, Vice President, Project Development and Governmental Affairs, Magnum Gas Storage, LLC to the Honorable Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, RE: Notification of the Addition of State Jurisdictional Facilities within the Magnum Gas Storage Project Boundary, dated March 16, 2012. 67 Correspondence from Walter L. Baker, P.E., Director of the Department of Environmental Quality, State of Utah, to Tiffany A James, Vice President of Magnum Gas Storage, Subject: Extension of Construction Permit, Magnum Gas Storage, LLC Evaporation Ponds, dated August 7, 2012. 68 Magnum Gas Storage, LLC, Docket No. CP10-22-000, Magnum Gas Storage Project, Bi-Weekly Report No. 16, Reporting Period – July 3, to July 16, 2012, dated July 23, 2012.
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ENERGY-EFFICIENCY PROGRAMS
Utah Energy-Efficiency Results 2012
The Company’s 2012 Commission-approved energy-efficiency programs and measures were similar to 2011, but also included new measures, minor changes to qualifying equipment, and changes to rebate levels. The major change for the ThermWise® programs in 2012 was the transition of rebate processing from Nexant and PECI to a new rebate processing contractor.
On June 16, 2011 the Company published an RFP to over forty rebate processing
contractors as well as posted the RFP on an industry website known as ACEEE. The RFP sought proposals from contractors interested in performing work related to rebate processing for both the Utah and Wyoming ThermWise® rebate programs. The terms of the RFP required a Proposal Response Letter (PRL), stating the intent of interested contractors to submit a proposal by the due date, to be delivered to the Company on or before June 28, 2011. Of the contractors initially contacted, eight (8) returned the PRL. The eight PRL respondents were given until July 15, 2011 to send clarifying questions to the Company. The Company collected questions from all contractors up until that date and responded to all by group e-mail. Completed proposals were required to be delivered to the Company on or before July 28, 2011. Of the eight PRL respondents, seven delivered final proposals to the Company.
The Company began evaluation of the proposals in early August. During the RFP and
evaluation process, the Company sought advice and support from the DSM Advisory Group. Ultimately, the Company found the proposal from Helgeson Enterprises Inc., a Minnesota based company, to be most responsive to the Company’s rebate processing needs. The Company notified Helgeson on September 13, 2011 and finalized the terms of an agreement with them in early 2012.
The Company began work on the design and implementation for the transition to
Helgeson in February of 2012. The new rebate processing system was launched in a phased process with the Business, Business Custom, and Weatherization programs transitioning (from Nexant) on June 4, 2012 and the Appliance and Builder programs transitioning (from PECI) on July 2, 2012. The rebate processing transition officially concluded with the return of all un-cashed rebate funds from Nexant and PECI in October of 2012. Since that time, minor changes and adjustments have been made to further refine the Company’s rebate processing operations.
ThermWise® Appliance Rebates
The Company continued this program in 2012 with a few changes relating to appliance
efficiency and the addition of new equipment to the overall offerings of rebates for customers. Those changes and additions were as follows: 1) a tiered rebate for energy-efficient boilers having an efficiency rating of 85% or higher; and 2) an increased rebate for 95% AFUE furnaces, which include an electrically commutated motor (ECM). PECI assisted with design, outreach, marketing and technical assistance for the entire 2012 program year. PECI also
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provided services related to rebate processing through July 1, 2012. Helgeson Enterprises took over rebate processing work for this program on July 2, 2012.
ThermWise® Builder Rebates
The Company continued this program in 2012 with several changes. The Company offered five (5) whole house builder options. The overriding goal of these builder options was to encourage above-code new construction. Some of the options were designed to encourage builders to begin moving towards practices that would be required if the state of Utah were to adopt the IECC 2009 Energy Code. Certain other options were directly tied to ENERGY STAR® requirements. A top tier option was also available to reward builders that exceeded ENERGY STAR® requirements. In addition, rebates continued to be offered for the installation of energy efficient stand-alone measures.
PECI assisted with design, outreach, marketing and technical assistance for the entire
2012 program year. PECI also provided services related to rebate processing through July 1, 2012. Helgeson Enterprises took over rebate processing work for this program on July 2, 2012.
ThermWise® Business Rebates
The Company continued this program in 2012 with the following improvements: 1) increased the rebate from $0.12/sq. ft. to $0.16/sq. ft. for retrofit roof insulation; 2) increased the rebate from $0.08/sq. ft. to $0.12/sq. ft. for retrofit wall insulation; and 3) elimination of the maximum size limit on high-efficiency gas furnaces. These improvements more closely aligned the program with market conditions as well as helped to ensure that program savings were achieved as desired. Nexant assisted with design, outreach, marketing and technical assistance for the entire 2012 program year. Nexant also provided services related to rebate processing through June 3, 2012. Helgeson Enterprises took over rebate processing work for this program on June 4, 2012.
ThermWise® Weatherization Rebates
The Company continued this program in 2012 with the following improvements: 1)
offered a rebate for air sealing; 2) added air sealing contractors to the Authorized Contractor program; 3) increased the rebate from $0.20/sq. ft. to $0.25/sq. ft. for Tier 1 attic insulation; and 5) offered a rebate for high-efficiency R-5 windows.
The Company continued to administer all residential (single and multifamily)
weatherization incentives under a single program in 2012. Incentives in 2012 were paid, tracked, modeled for cost effectiveness, and reported as single or multifamily. For qualifying multifamily residences, a pre-qualification inspection continued to be required.
Nexant assisted with design, outreach, marketing and technical assistance and rebate
processing for this program through June 3, 2012. Helgeson Enterprises took over rebate processing work for this program on June 4, 2012.
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ThermWise® Home Energy Audit
The Company continued this program in 2012 with no significant changes.
Low-Income Weatherization Assistance
The Company continued funding the LIWAP in 2012 at $500,000 per year from the energy-efficiency budget, and an additional $250,000 that is contributed outside of the energy-efficiency budget ($750,00069 total Company funding). The Company disbursed $250,000 from the energy-efficiency budget every six months, with the disbursements occurring in January and July.
Beginning in October of 2012 the Company instituted a direct rebate payment process for
approved non-profit or governmental agencies. In order to qualify for the direct payment process, the approved entities were required to satisfy certain requirements. Equipment rebated through the direct payment process was tracked, modeled for cost effectiveness, and reported through the Company’s Low-Income program.
ThermWise® Business Custom Rebates
The Company continued this program in 2012 with no changes. A summary of the projected and actual benefit-cost ratios for each of the 2012
ThermWise programs is shown below.
Table 8.1 – Utah 2012 Projected & Actual B/C ratios by program and California Standard Practice Test
69 $500,000 of funding comes from the energy-efficiency budget. The remaining $250,000 is funded through general rates and is disbursed in semi-annual disbursements of $125,000 each.
Program
Total Resource Cost Test
Participant Test Utility Cost Test Ratepayer Impact
Measure Test
2012 Projected
B/C
2012 Actual
B/C
2012 Projected
B/C
2012 Actual
B/C
2012 Projected
B/C
2012 Actual
B/C
2012 Projected
B/C
2012 Actual
B/C
ThermWise® Appliance Program 1.1 0.9 2.1 2.0 1.9 1.4 1.1 0.8
ThermWise® Builder Program 1.1 0.6 2.1 1.3 2.0 1.6 1.2 1.0
ThermWise® Business Custom Program 1.8 1.0 8.0 5.0 1.9 1.3 1.1 0.8
ThermWise® Business Program 1.0 1.2 2.0 3.3 1.6 1.8 1.0 1.0
ThermWise® Weatherization Program 1.3 1.2 2.7 2.6 1.5 1.4 1.0 0.9
ThermWise® Home Energy Audit 0.4 0.3 26.4 29.9 0.4 0.3 0.4 0.3
Low Income Weatherization 1.3 1.1 3.2 7.1 1.7 1.3 1.0 0.8
Market Transformation 0.0 0.0 N/A N/A 0.0 0.0 0.0 0.0
TOTALS 1.10 .91 2.42 2.17 1.52 1.35 0.97 0.86
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While actual benefit/cost results for 2012 were lower than the corresponding budget
projections, the ThermWise® programs as a whole passed both the Participant and Utility Cost tests. Actual cost-effectiveness results were lower than projected primarily due to lower avoided gas costs taken from the IRP (and used in cost-effectiveness modeling Q2-Q4 2012) than were forecasted and used in cost-effectiveness modeling for the 2012 ThermWise budget filing (Docket No. 11-057-12).
Customer participation in the ThermWise® programs remained high in 2012 (71,998
actual rebates paid) but finished the year below the Company’s 2012 estimate (91,787). Actual participation (9,080) surpassed estimated participation (5,082) in the Builder program. The Weatherization and Appliance programs had the highest total number of participants (43,622 and 15,167 respectively). The prescriptive Business program was short of the 2012 participation goal (56%) yet still achieved 82% of the 2012 program savings goal.
During 2012, the DSM Advisory Group continued to meet to discuss the Company’s
energy-efficiency initiative. The DSM Advisory Group met four times, on the following dates: March 29, July 19, September 18 and December 13. Wyoming Energy-Efficiency Results 2012
The Company filed for approval (Docket No. 30010-119-GT-12) of a fourth year of Wyoming ThermWise® programs on August 15, 2012. The Company modified the fourth year Wyoming programs to more closely align with the proposed 2013 Utah ThermWise® programs. The Company did so in an effort to achieve cost savings for both states while also taking current energy-efficiency and equipment standards into account. The Wyoming Public Service Commission approved the fourth year filing (ORDER February 6, 2013) and ordered the changes effective January 1, 2013.
The Wyoming energy-efficiency programs (Appliance, Builder, Business, Home Energy Audit, and Weatherization) have seen good participation and interest from customers since they were launched on July 1, 2009. In the third full program year (July 2011 through June 2012) the Wyoming ThermWise® programs had 659 participants or 2.4% of the Company’s December 31, 2012 Wyoming residential GS customer base. In contrast, the second program year (July 2010 through June 2011) of the Wyoming programs resulted in 1,013 participants or 154% of the third year program results. The Company has forecasted 1,310 participants in the fourth year of the Wyoming ThermWise® programs.
Utah Energy-Efficiency Plan 2013
Based on work with the DSM Advisory Group, Utah-based trade allies, program administrators and other energy-efficiency stakeholders, the Company proposed and the Utah Public Service Commission approved the continuation of the seven energy-efficiency programs
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from 2012 as well as the ThermWise® Market Transformation initiative. The ThermWise®
energy-efficiency programs continuing in 2013 are: 1) the ThermWise® Appliance Rebates Program; 2) the ThermWise® Builder Rebates Program; 3) the ThermWise® Business Rebates Program; 4) the ThermWise® Weatherization Rebates Program; 5) the ThermWise® Home Energy Audit Program; 6) funding of $500,000 for the Low-Income Weatherization Assistance Program administered by the Utah Department of Workforce Services; and 7) the ThermWise® Business Custom Rebates Program.
ThermWise® Appliance Rebates
The Company will continue this program in 2013 with the elimination of rebates for lower tiered furnaces and a minor clarification to the solar assisted water heating measure. The Company will eliminate the tier 1 (90% < 91.9% efficient) and tier 2 (92% < 94.9% efficient) furnaces from the list of eligible rebate measures in 2013. These changes anticipate the U.S. Department of Energy’s (DOE) proposed May 1, 2013 increase in the furnace standard. The proposed standard would increase the minimum efficiency to 90% for furnaces sold in the climate zones covered in the Company’s Utah service territory. The Company will continue to offer these programs to customers in the Company’s Utah service territory. PECI will continue to assist with design, outreach, marketing and technical assistance for this program. Helgeson Enterprises will continue work related to rebate processing for this program in 2013.
ThermWise® Builder Rebates
The Company will continue this program in 2013 with several changes. The Company
will eliminate the lower tiers for furnaces from the Builder Program and adopt the minor solar assisted water heating clarification for the reasons listed in the 2013 Appliance Rebates section. The Company will also remove the ENERGY STAR® Version 2.5 whole home measure. The ENERGY STAR® Version 2.5 whole home measure is no longer a valid ENERGY STAR® tier. The Company will continue to offer this program to customers in the Company’s Utah service territory. PECI will continue to assist with design, outreach, marketing and technical assistance for this program. Helgeson Enterprises will continue work related to rebate processing for this program in 2013.
ThermWise® Business Rebates
The Company will continue this program in 2013 with the following changes: 1)
eliminate the two lowest tiers of furnaces as eligible rebate measures for the reasons listed in the Appliance Rebates discussion; 2) eliminate rebates for the roof top furnace measure. The roof top furnace will instead be eligible for rebates under the Business Custom Program. These improvements will more closely align the program with market conditions as well as help to ensure that program savings are achieved as desired. This program will continue to be available to GS commercial customers in the Company’s Utah service territory. Nexant will continue to assist with design, outreach, marketing and technical assistance for this program. Helgeson Enterprises will continue work related to rebate processing for this program in 2013.
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ThermWise® Weatherization Rebates
The Company continued this program in 2013 with no significant changes. All residential weatherization incentives will continue to be administered under a single program. In 2013 the weatherization program will include all residences receiving service on the GS rate schedule. A qualifying single-family residence is defined as a new structure of up to four residential dwelling units. A qualifying multifamily residence is defined as an existing structure having five or more residential dwelling units. Incentives in 2013 will be paid, tracked, modeled for cost effectiveness, and reported as single or multifamily. For qualifying multifamily residences, a pre-qualification inspection will continue to be required.
This program will continue to be available to existing residential customers in the
Company’s Utah service territory. Nexant will continue to assist with design and technical assistance for this program. Helgeson Enterprises will continue work related to rebate processing for this program in 2013.
ThermWise® Home Energy Plan (formerly the Home Energy Audit Program)
The Company will continue this program in 2013 with the following changes: 1) the
Company will change the name from the Home Energy Audit to the Home Energy Plan program; 2) in an effort to reach the rental market as well as make the program more cost-effective, the Company will remove the single family restriction for the Home Energy Plan program. The program will continue to provide certain low-cost energy efficiency measures at no charge for installation at single family. Multi-family properties will also be eligible to receive no charge efficiency measures; 3) in an effort to reach senior home owners the Company will implement a pilot program in which it will waive the $25 audit fee for lower-income seniors targeted for participation in the Home Energy Plan program. The Company anticipates that waiving the $25 fee for targeted seniors will not have a material effect on cost effectiveness, but will have a beneficial impact on the Company’s ability to reach this underserved market segment.
The ThermWise® Home Energy Plan program is offered and administered by Questar
Gas with periodic consulting and assistance from Nexant. This program includes two primary components: in-home energy plan performed by trained and experienced Questar Gas Auditors and “do-it-yourself” mail-in plan with on-line data input availability. This program will continue to be available to customers in the Company’s Utah service territory and administered by Questar Gas.
Low-Income Weatherization Assistance
The Company will continue funding the LIWAP in 2013 at $500,000 per year from the
energy-efficiency budget ($750,000 total Company funding). The Company will disburse $250,000 every six months, with the disbursements occurring in January and July.
The Company will also continue the direct rebate payment process for approved non-
profit or governmental agencies. In order to qualify for the direct payment process, the approved
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entities must satisfy certain requirements. Equipment rebated through the direct payment process will be tracked, modeled for cost effectiveness, and reported through the Company’s Low-Income program. Helgeson Enterprises will continue work related to rebate processing for this program in 2013.
ThermWise® Business Custom Rebates
The Company is continuing this program with one significant change. In 2013 the
Company will begin coordinating the benchmarking of commercial customer facilities and will contribute to the initial engineering analysis for commercial customers showing the potential for large savings as a result of the benchmarking activities. The purpose of commercial benchmarking is to compare the energy intensity of a subject building with the energy intensity of buildings similarly occupied. The benchmarking results show the overall energy efficiency, or lack thereof, of a given building and can be used to identify possible energy efficiency opportunities. Nexant will continue to assist with design, outreach, marketing and technical assistance for this program. Helgeson Enterprises will continue work related to rebate processing for this program in 2013.
A summary of the cost-effectiveness used in the energy-efficiency model for each ThermWise® program as provided with the 2013 budget filing.
Table 8.2 – Utah 2013 projected NPV & B/C ratios by program and California Standard Practice Test
2013 Projections
Total Resource Cost
Participant Test Utility Cost Test Ratepayer Impact
Measure Test
NPV* B/C NPV* B/C NPV* B/C NPV* B/C
ThermWise®
Appliance Program 1.61 1.22 13.66 2.84 2.70 1.50 -.73 .92
ThermWise®
Builder Program -1.07 0.79 3.84 1.70 .82 1.30 -.63 .85
ThermWise®
Business Custom Program .57 1.53 2.49 5.99 .82 2.00 .12 1.08
ThermWise®
Business Program .68 1.26 5.03 3.05 1.71 2.07 .32 1.11
ThermWise®
Weatherization Program 1.53 1.17 16.72 2.68 2.60 1.32 -1.62 .87
ThermWise®
Home Energy Plan -.02 .97 1.83 32.17 -.03 .96 -.41 .67
Low Income Weatherization .51 1.39 3.06 4.28 .59 1.49 -.17 .92
Market Transformation -1.99 0 0.00 N/A -1.99 0 -1.99 0
TOTALS 1.82 1.06 46.64 2.74 7.21 1.32 -5.11 .85
*Shown in millions
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Table 3 shows the Utah cost-effectiveness results using the projections included in the budget filing updated to include the gas cost forward curve used in the SENDOUT model.
Table 3 – Utah 2013 NPV & B/C ratios using gas cost forward curve from SENDOUT model.
2013 IRP Forward Curve
Total Resource Cost
Participant Test Utility Cost Test Ratepayer Impact
Measure Test
NPV* B/C NPV* B/C NPV* B/C NPV* B/C
ThermWise®
Appliance Program 1.41 1.19 13.66 2.84 2.50 1.47 -.94 .89
ThermWise®
Builder Program -1.18 .77 3.84 1.70 .70 1.25 -.74 .82
ThermWise®
Business Custom Program .55 1.52 2.49 5.99 .80 1.98 .10 1.07
ThermWise®
Business Program .59 1.22 5.03 3.05 1.62 2.02 .22 1.08
ThermWise®
Weatherization Program 1.11 1.12 16.72 2.68 2.17 1.27 -2.04 .84
ThermWise®
Home Energy Plan .00 1.00 1.83 32.17 .00 .99 -.38 .69
Low Income Weatherization .46 1.35 3.06 4.28 .54 1.45 -.22 .89
Market Transformation -1.99 0 0 N/A -1.99 0 -1.99 0
TOTALS .94 1.03 46.64 2.74 6.34 1.28 5.98 .83
*Shown in millions Wyoming Energy-Efficiency Plan 2013
The Company expects fourth year participation in the portfolio of Wyoming ThermWise® programs to increase slightly from the high of 1,013 in the second program year (July 2010 to June 2011). This projected increase is due to the expansion of eligibility from single-family and business GS customers to all customers receiving service on the GS rate schedule. This change will allow residential properties with more than four dwelling units to participate in the programs. The Company believes that multi-family dwelling represent an underserved market segment where customers could realize significant savings.
SENDOUT Model Results for 2013
Projections from the approved 2013 energy-efficiency budget were entered into the SENDOUT model in response to the Utah Commission’s request. Data entries for the 2013 energy-efficiency programs included participants and deemed lifetime Dth savings per program
8-9
measure. Incentive (variable) and administration (fixed) costs for each program measure were also incorporated into the SENDOUT model.
The SENDOUT model used the projected 2013 participation and administration costs as
the baseline for its analysis of each program. For each program, the model then examined what would happen if participation was reduced to as low as 25% or increased to as high as 150% of the 2013 projection. The model also examined different scenarios involving the escalation of annual administration costs per program. In these scenarios, administration costs per program were increased to 150% and 200% of the 2013 projection. SENDOUT then made the judgment as to whether a program should be “accepted” (100% on the included graph) or “rejected” (0% on the included graph) based on a given level of participation and administration costs. Please see Exhibit 8.1 for the SENDOUT results in a table format.
The 2013 ThermWise® Business and Weatherization programs were accepted by the
model at 25% of 2013 projected participation if administration costs were increased to 200% of the 2013 budget projection. The Appliance and Builder programs were accepted at 50% of participation and 200% of projected administration costs. The Business Custom program was accepted 100% of participation if administration costs were increased to 200% of the 2013 budget projection. The Home Energy Plan program was not accepted by the model at any combination of participation and administration costs. This is not a concern to the Company at this time because the Home Energy Plan program acts as a feeder program to the rebate programs and also has other benefits which to date have not been quantified. The Company is examining options to make the Home Energy Plan program more cost-effective in the 2013 program year.
Another way to view the results of the SENDOUT model is to analyze the level that
administration costs could increase to if participation was held at 100% of the 2013 projection. In this scenario, SENDOUT would suggest that the administration costs for the Business and Weatherization programs could increase by eight times the 2013 budget projection and still be accepted. The Appliance and Builder programs could increase projected administration costs by four times and the Business Custom program could double administrative costs and still be accepted by SENDOUT.
In summary, the SENDOUT model results indicate that as a gas supply resource at the approved budget and participation levels, the 2013 energy-efficiency programs are accepted as qualifying and cost-effective resources when compared to other available resources. Furthermore, this holds true when participation rates are held constant and program administrative costs are increased by as much as eight times 2013 budget levels.
In comparison to the SENDOUT model which is a comprehensive resource planning and evaluation tool, the Questar Gas Energy-Efficiency model which was developed in-house by the Company with the assistance of the Questar Gas Energy-Efficiency Advisory Group and reviewed by the Commission, is used for the sole purpose of modeling Questar Gas’ Energy-Efficiency programs. To this end, the Company relies on the Questar Gas Energy-Efficiency
8-10
model for energy-efficiency program planning purposes and more importantly energy-efficiency program cost effectiveness (based on the California Standard Practices Model).
Using the Questar Gas Energy-Efficiency model, the Company analyzed the approved
2013 energy-efficiency programs at a “break-even” benefit / cost ratio (B/C = 1.00) by holding participation (and incentive payments) constant and increasing all other costs in a linear manner. This analysis resulted in a projected potential total energy-efficiency spending limit of $29.13 (UCT) million per year versus the current approved $22.79 million per year for the 2013 projected natural gas savings of 589,606 Dth. This analysis indicates that the maximum potential spending on energy-efficiency is directly related to the cost-effectiveness of realizing each Dth saved. Therefore, as long as the Company’s energy-efficiency programs are determined cost-effective in the Questar Gas Energy-Efficiency model, accepted by the SENDOUT model when compared to other available resources and do not negatively impact company operations, energy-efficiency programs are an appropriate resource.
Avoided Costs Resulting From Energy-Efficiency The ThermWise® Cost Effectiveness Model calculates the avoided cost of gas purchases as the sole benefit of the energy-efficiency programs. In 2012, the avoided gas cost attributable to energy-efficiency was calculated as $30.44 million. For 2013, the avoided gas cost attributable to energy-efficiency is estimated to be $29.13 million. The avoided purchased gas is valued at the same price level as used in the IRP modeling.
Exhibit 8.1
2013 Energy‐Efficiency Modeling Results from SENDOUT
25% 50% 100% 150%
ThermWise® Appliance Program
ThermWise® Builder Program
ThermWise® Business Custom Program
ThermWise® Business Program
ThermWise® Home Energy Plan
ThermWise® Weatherization Program
Accepted by SENDOUT Model as a resource =
Not Accepted by SENDOUT Model as a resource =
25% 50% 100% 150%
ThermWise® Appliance Program
ThermWise® Builder Program
ThermWise® Business Custom Program
ThermWise® Business Program
ThermWise® Home Energy Plan
ThermWise® Weatherization Program
Accepted by SENDOUT Model as a resource =
Not Accepted by SENDOUT Model as a resource =
25% 50% 100% 150%
ThermWise® Appliance Program
ThermWise® Builder Program
ThermWise® Business Custom Program
ThermWise® Business Program
ThermWise® Home Energy Plan
ThermWise® Weatherization Program
Accepted by SENDOUT Model as a resource =
Not Accepted by SENDOUT Model as a resource =
% of 2013 Budget ParticipationProgram @ 100% of 2013 Budget $
Program @ 150% of 2013 Budget $% of 2013 Budget Participation
Program @ 200% of 2013 Budget $% of 2013 Budget Participation
8‐11
9-1
FINAL MODELING RESULTS Linear Programming Optimization Model
Questar Gas has utilized for a number of years, a computer-based linear-programming
optimization (LPO) model to evaluate both supply-side and demand-side resources. This software product, marketed under the name of “SENDOUT,” is maintained by Ventyx headquartered in Atlanta, Georgia. Ventyx is owned by ABB, a global power and automation technology group headquartered in Zurich, Switzerland with approximately 145,000 employees. SENDOUT is used by roughly 100 energy companies for gas supply planning and portfolio optimization.
SENDOUT has the capability of performing Monte Carlo simulations thereby
facilitating risk analysis. The Monte Carlo method utilizes repeated random sampling to generate probabilistic results. It is best applied where relative frequency distributions of key variables can be developed or where draws can be made from historic data. Because of the need for numerous random draws, this method has been facilitated by the availability of high-speed computer technology.
Questar Gas is using a new release of SENDOUT this year, Version 14.2.
SENDOUT Version 14.2 has an enhanced network diagramming and portfolio schematic visualization feature.
In performing gas supply modeling, Questar Gas representatives work closely with
consultants from Ventyx. The Ventyx consultants are very familiar with the gas supply modeling approach of the Company and they are comfortable with how the Company utilizes and configures the SENDOUT model.
Constraints and Linear Programming
While the concepts of linear programming date back to at least the early 19th century, it was not until the middle of the 20th century that this approach began to be more widely accepted as a method for achieving optimal solutions in practical applications. In summary, linear programming problems involve the optimization of a linear objective function subject to linear constraints. Constraints are necessary in the determination of a maximum or minimum solution. Constraints must be linear functions and can either represent equalities or inequalities. An example of an inequality constraint in the natural gas business would be that the quantity of natural gas that can be transported over a certain segment of an interstate pipeline must be “less than or equal to” a certain level previously contracted for with that pipeline company. Another example of an inequality constraint would be the production available from a group of wells providing cost-of-service natural gas. The levels of this resource that can be taken can never exceed the maximum level available as production naturally declines over time. All resources are defined by constraints including purchased gas. Some peaking contracts have minimum levels that must be taken during an agreed-upon period of time which would be translated into a “greater than or equal to” constraint.
9-2
Constraints must be carefully defined to accurately reflect the problem being solved. The arbitrary removal of required constraints results in an inaccurate solution. For example, if the constraint on how quickly the Company’s capacity at the Clay Basin storage facility can be refilled were to be removed, the model would assume that it could be done instantaneously, resulting in an unrealistic solution. The removal of all constraints in a linear programming problem results in no solution being obtained. Questar Gas periodically reevaluates the constraints in its SENDOUT model to determine if they accurately reflect the realities of the problem being solved. Monte Carlo Method When performing Monte Carlo analysis, the length of computer run times can become an issue. To have a meaningful simulation, it is important to have a sufficient number of draws (typically hundreds). Each draw consists of one deterministic linear programming computer run. With the complexity of the Company’s modeling approach, one simulation usually takes several days to run. The base Monte Carlo simulation developed by the Company this year utilized 1400 draws. When the developers of SENDOUT incorporated the Monte Carlo methodology, they limited the number of variables for which stochastic analysis can be applied to avoid excessive computer run times. The two variables which they appropriately determined should be included are price and weather (within SENDOUT demand is modeled as a function of weather). No other variables have a more profound impact on the cost minimization problem being solved by SENDOUT than these two. The output reports generated from the SENDOUT modeling results consist primarily of data and graphs. Most of the graphs are frequency distribution profiles from a Monte Carlo simulation. Many of the numerical-data reports show probability distributions for key variables in a simulation run. The heading “max” in these reports refers to the value of the draw in a simulation with the highest quantity. The heading “min” refers to the value of the draw in a simulation with the lowest quantity. The heading “med” refers to the median draw (or the draw in the middle of all draws). Questar Gas believes that the mean and median values are good indicators of likely occurrence, given the underlying assumptions in a simulation. Many exhibits in this report also include a base case number to show how the base case compares to the mean and median. The base case will be discussed in more detail later in this section. Also in these data reports are the headings “p95,” “p90,” “p10,” and “p5.” The label “p95” on an output report means, based on input assumptions, that a 95 percent confidence exists that the resulting variable will be less than or equal to that number. Likewise, a “p10” number suggests that there is a 10 percent likelihood that a variable will be less than or equal to that number. These statistics and/or the shape of a frequency curve help define the range and likelihood of potential outcomes.
9-3
Natural Gas Price
The price for which natural gas supplies can be purchased in the future is extremely difficult to accurately model. Most of the natural gas purchased by Questar Gas is tied contractually to one or more of nine area price indices. Three of those indices are published first-of-month prices for deliveries to the following interstate pipeline systems; KRGT, Questar Pipeline, and Northwest Pipeline. The remaining are published daily indices for KRGT (3), Questar Pipeline (1), SoCal Gas (1), White River Hub (1), and one basket combining two KRGT indices. To develop a future probability distribution, Questar Gas assembled historical data and determined the means and standard deviations associated with each price index. Questar Gas then utilized the average of two price forecasts developed by PIRA70 (19 months) and IHS CERA71 (271 months) as the basis for projecting the stochastic modeling inputs. Forecasted standard deviations have been scaled up a pro rata based on prices to more accurately mirror reality. Exhibits 9.1 through 9.36 show, for the first model year, the resulting monthly price distribution curves for the first-of-month prices and the daily prices for each of the price indices used in the base simulation.
Weather and Demand In addition to the price of natural gas, the other single most unpredictable variable in natural gas resource modeling is weather induced demand. Questar Gas makes available to the SENDOUT model 84 years of weather data. It should be noted that when forecasting future demands, heating degree days are stochastic with a mean and standard deviation by month. Questar Gas uses this number, along with usage-per-customer-per-degree-day and the number of customers, to calculate the customer demand profile used by the model. The stochastic nature of the heating-degree-days creates a normal plot for degree days based on the 1400 draws. For each month of simulation, the model randomly selects a monthly-degree-day standard-deviation multiplier to create a draw-specific monthly-degree-day total. It then scans through 84 years of monthly data to find the closest matching month. Then the model allocates daily degree-day values according to the degree-days in this historic month pattern. Exhibits 9.37 through 9.49 show first the annual and then the monthly demand distribution curves for the first year of the base simulation. Exhibit 9.50 shows the annual heating-degree-day distribution. In prior years, before Questar Gas utilized Monte Carlo modeling techniques, a high demand and a low demand scenario were modeled as part of a sensitivity analysis. Currently, with the use of a Monte Carlo modeling approach, the wide variability in weather-induced demand resulting from historical weather data is broader than any reasonable range of load growth scenarios. This year there are 1400 deterministic cases in the Monte Carlo
70 PIRA Energy Group, Inc. (PIRA) is an international energy consulting firm with expertise in energy market analysis and intelligence. PIRA’s client base exceeds 500 companies in some 60 countries. 71 IHS CERA is part of the global information company, IHS, which employs more than 6,000 people in more than 31 countries. IHS CERA is a leading advisor to international energy companies, governments, financial institution, and technology providers delivering critical knowledge and independent analysis on energy markets, geopolitics and industry trends.
9-4
simulation, each with a different demand level, thus obviating the need to model just one high and one low demand case. Peak Day and Base Load Purchase Contracts The need to have adequate resources sufficient to meet a design-peak day is an important consideration in the modeling process. The design-peak day for the 2013/2014 winter-heating season has been determined to be 1.27 million Dth per day at the city gates.72 The design-peak day for many years has been defined to be a 1-in-20-year weather occurrence. The most likely day for a design peak to occur is on January 2, although, the probability of a design peak occurring on any day between mid-December and mid-February is relatively flat. Even though it is unlikely that a design-peak day will occur this year, the Company must be prepared to meet such a need should it occur. Selecting a draw from a Monte Carlo simulation that utilizes on the maximum demand day a level of resources approximately equaling the design-peak day has proven to be problematic in that the SENDOUT model selects too much base-load purchased gas for a typical weather year. The draws which have a design-peak-day occurrence also tend to be much colder than normal throughout the entire year. The solution to this dilemma is to perform a statistical clustering analysis of all the Monte Carlo draws for first-year peak demand versus the median level of first-year annual demand.72 The result of this clustering exercise is a scatter plot that shows groups of draws. These cluster points or groups represent draws that are most closely alike in terms of peak-day requirements and annual demand. A cluster point is then chosen that we believe will meet annual demand without falling short on peak day. A second SENDOUT scenario is then executed, with the unused RFP packages removed, and only those “cluster point” packages remaining. One of the purposes of this run is to verify that adequate purchased gas resources at the least cost will be available in the remote event that a design-peak day were to occur. The optimizing nature of the SENDOUT model helps to make this happen. This year, of the 1400 draws generated in this process, 5 draws would exceed the design peak-day requirement of 1.27 MMDth. In other words, this scenario has enough resources to meet a peak-day event. Most of the base-load purchased-gas resources, with their associated time-availabilities, must be committed, during the springtime, prior to the beginning of the gas supply year, to be ready for cold weather in the fall. Patterns of usage for storage resources, spot gas, and cost-of-service gas do not need to be committed to before the gas year begins. This modeling approach also lends itself to performing operational analysis periodically during the year as natural gas prices change. Exhibit 9.51 shows the resources utilized to meet the design-peak day. Exhibit 9.52 shows the firm-peak-day demand distribution for the base simulation for the first plan year. Understandably, the design-peak day for Questar Gas is in the upper tail of the curve.
72 See the cluster analysis discussion in the Modeling Issues subsection of the Purchased Gas section of this report.
9-5
Base Case Identification
Whenever one draw of a stochastic analysis is identified as a base case, there is a general tendency to assume that there is a greater likelihood of all the attributes of that draw occurring than actually exists. Nevertheless, it is useful to identify a base case for ease of discussion and to facilitate the measurement of deviations.
In determining a base case, Questar Gas made available to the SENDOUT model, all of the optimal purchase gas resources selected to meet the design-peak day occurrence as described previously. Then, another Monte Carlo simulation was performed. Re-running the simulation allowed the model for each draw to size the appropriate level of purchased-gas resources from packages which, for the most part, will actually be under contract. Inevitably, when purchased-gas RFP responses are made, a few of the deals will fall through for a variety of reasons. These deals can usually be replaced under fairly similar terms.
There are a number of criteria, however, that could be used to determine a base case
from the simulation. The draw with the median demand level could be used, for example, but that draw will not be the same as a draw with the median price for any one of the price distributions used and vice versa. Questar Gas developed an algorithm to systematically select its base case. Using the distributions for 31-year total cost, first year demand, first-year purchase gas and first-year cost-of-service gas, each distribution was ordered from least to greatest result value. Then, in the stated order above, starting with the median value, a window of draws was selected centered at the median. Those selected draws were then taken as the starting point to look in the second distribution with the same size matching draws. If matches were found, then those were taken to the third distribution as the starting point. The first draw that was found within the window and that existed in all distributions was selected as the base case. When no match was found from one distribution to the next, the process started over and the bounds of the window were increased to include the next highest and next lowest draws.
Purchased-Gas Resources Exhibits 9.53 through 9.64 show the probability distributions for purchased gas for each month of the first plan year from the base simulation. Exhibit 9.65 shows the annual distribution from the simulation. Exhibit 9.66 shows the numerical monthly data with confidence limits. Purchased gas for the first plan year from the base case is approximately 35 million Dth. Questar Gas is confident that for a colder-than-normal year, sufficient purchased-gas resources will be available in the market. Likewise, Questar Gas is confident that in the event of a warmer-than-normal year, it has not “over-bought” base-load purchase contracts.
9-6
Cost-of-Service Gas Another important output from the SENDOUT modeling exercise each year is a determination of the level of cost-of-service gas to be produced during the upcoming gas-supply year. Exhibits 9.67 through 9.78 show the distributions for cost of service gas for each month of the first plan year from the base simulation. Exhibit 9.79 shows the annual distribution from the simulation. Exhibit 9.80 shows the numerical monthly data with confidence limits. Cost-of-service production for the first plan year from the base case is approximately 80 million Dth. First-Year and Total System Costs The linear-programming objective function for the SENDOUT model is the minimization of variable cost. A distribution curve for first-year total cost from the base simulation is shown in Exhibit 9.81. The first year total cost from the base case is approximately $647 million. A similar curve for the total 31-year modeling time horizon is shown in Exhibit 9.82. The base case cost for this time period is approximately $12.3 billion. Gas Supply Plan Exhibits 9.83 through 9.88 show additional planning detail for the first two years of the base case. Monthly data for each category of cost-of-service gas and each purchase-gas package are listed. Also included are injections into and withdrawals from each of the five storage facilities utilized by the Company. Although no actual gas-supply year will ever perfectly mirror the plan, these exhibits are among the most useful products of the IRP process. They are used extensively in making monthly and day-to-day nomination decisions. Normal Temperature Case One of the drawbacks of the base case, as well as all stochastic scenarios, is the lack of normal temperatures for an entire year. This issue surfaced as the Company worked on data for its rate pass-through cases. To provide clarity regarding the pass-through data and in response to requests received from regulators that a report be included in the IRP that showed numbers associated with a normal temperature scenario, the Company has included this case which should not be confused with the base case. In this document, the normal temperature scenario can be seen in normal case Exhibits 9.89 through 9.91. Gas Supply/Demand Balance Exhibits 9.92 and 9.93 show monthly natural gas supply and demand broken out by geographical area, residential, commercial and the non-GS categories of commercial, industrial and electric generation.
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This report is available in SENDOUT and is called “Natural Gas Requirements Versus Supply.” The data in these exhibits represent the selected base case. The SENDOUT report has been slightly adapted to show geographical areas and lost-and-unaccounted-for gas. Because demand is measured at the customer meter and modeling occurs at the city gate, in years past the demand has been grossed up by the lost-and-unaccounted-for amount to model natural gas demand at the city gate. In recent years, lost-and-unaccounted-for gas was modeled as a percent of the other demand classes and is shown as its own specific demand class. Exhibit 9.92 of the report shows Requirements of the System. Those are specifically Demand, Fuel Consumed, and Storage Injection. This gives the total requirement at 129.350 MMDth for the base case. Exhibit 9.93 shows sources of supply which include purchased gas categories, cost-of-service gas, Clay Basin and the Aquifers. The total supply is 129.327 MMDth for the base case.
Exhibit 9.01
Exhibit 9.02
Exhibit 9.03
Exhibit 9.04
Exhibit 9.05
Exhibit 9.06
Exhibit 9.07
Exhibit 9.08
Exhibit 9.09
Exhibit 9.10
Exhibit 9.11
Exhibit 9.12
Exhibit 9.13
Exhibit 9.14
Exhibit 9.15
Exhibit 9.16
Exhibit 9.17
Exhibit 9.18
Exhibit 9.19
Exhibit 9.20
Exhibit 9.21
Exhibit 9.22
Exhibit 9.23
Exhibit 9.24
Exhibit 9.25
Exhibit 9.26
Exhibit 9.27
Exhibit 9.28
Exhibit 9.29
Exhibit 9.30
Exhibit 9.31
Exhibit 9.32
Exhibit 9.33
Exhibit 9.34
Exhibit 9.35
Exhibit 9.36
Exhibit 9.37
Mean: 109.26 MMDthMedian: 109.22 MMDthBase Case: 109.80 MMDth
Exhibit 9.38
Exhibit 9.39
Exhibit 9.40
Exhibit 9.41
Exhibit 9.42
Exhibit 9.43
Exhibit 9.44
Exhibit 9.45
Exhibit 9.46
Exhibit 9.47
Exhibit 9.48
Exhibit 9.49
Exhibit 9.50
Mean: 5536.34 HDDMedian: 5531.15 HDDBase Case: 5590.29 HDD
Exhibit 9.51
0
200
400
600
800
1000
1200
1400
Source
Spot
Peaking Purchase
Future Contracts
Cost‐of‐Service Gas
Clay Basin
Aquifers
2013 ‐ 2014 Sources for Peak Day1.287 MMDth
Exhibit 9.52
Mean: 0.920 MMDthMedian: 0.910 MMDthBase Case: 0.822 MMDth
Exhibit 9.53
Exhibit 9.54
Exhibit 9.55
Exhibit 9.56
Exhibit 9.57
Exhibit 9.58
Exhibit 9.59
Exhibit 9.60
Exhibit 9.61
Exhibit 9.62
Exhibit 9.63
Exhibit 9.64
Exhibit 9.65
Mean: 35.36 MMDthMedian: 35.43 MMDthBase Case: 35.39 MMDth
Exhibit 9.66
Monthly Gas Purchase Distribution
2013 Plan Year
Scenario 1001 : 1400 Draws
MMDth
year month mean max p95 p90 med p10 p5 min
2013 6 0.07 1.72 0.44 0.19 0.00 0.00 0.00 0.00
2013 7 0.00 0.09 0.04 0.00 0.00 0.00 0.00 0.00
2013 8 0.03 0.10 0.10 0.09 0.00 0.00 0.00 0.00
2013 9 0.29 3.18 1.36 1.00 0.05 0.00 0.00 0.00
2013 10 1.30 4.41 3.22 2.89 1.22 0.00 0.00 0.00
2013 11 3.66 7.73 6.43 6.12 3.93 1.21 0.79 0.46
2013 12 5.84 11.49 9.48 8.78 5.41 3.67 3.23 1.77
2014 1 8.97 15.24 11.87 11.30 8.93 6.74 6.07 4.22
2014 2 7.66 11.35 9.73 9.39 7.72 5.92 5.43 3.11
2014 3 4.76 7.19 6.17 5.93 4.91 3.26 2.80 1.63
2014 4 2.70 7.78 5.08 4.51 2.70 0.82 0.37 0.00
2014 5 0.08 2.10 0.33 0.18 0.00 0.00 0.00 0.00
Exhibit 9.67
Exhibit 9.68
Exhibit 9.69
Exhibit 9.70
Exhibit 9.71
Exhibit 9.72
Exhibit 9.73
Exhibit 9.74
Exhibit 9.75
Exhibit 9.76
Exhibit 9.77
Exhibit 9.78
Exhibit 9.79
Mean: 80.03 MMDthMedian: 80.08 MMDthBase Case: 80.06 MMDth
Exhibit 9.80
Monthly Cost‐of‐Service Gas Distribution
2013 Plan Year
Scenario 1001 : 1400 Draws
MMDth
year month mean max p95 p90 med p10 p5 min
2013 6 5.65 5.80 5.80 5.80 5.76 5.33 5.33 5.31
2013 7 5.40 5.51 5.47 5.44 5.39 5.37 5.37 5.37
2013 8 5.32 5.42 5.38 5.35 5.31 5.29 5.29 5.28
2013 9 6.24 6.33 6.33 6.33 6.32 6.05 5.85 5.62
2013 10 7.47 7.58 7.56 7.54 7.52 7.32 7.24 6.98
2013 11 7.36 7.37 7.37 7.36 7.36 7.36 7.36 7.30
2013 12 7.78 7.79 7.78 7.78 7.78 7.78 7.78 7.78
2014 1 7.42 7.42 7.42 7.42 7.42 7.41 7.41 7.41
2014 2 6.44 6.45 6.44 6.44 6.44 6.44 6.44 6.44
2014 3 7.32 7.33 7.33 7.33 7.32 7.32 7.31 7.21
2014 4 6.81 6.84 6.83 6.83 6.80 6.79 6.79 6.62
2014 5 6.82 6.85 6.84 6.84 6.84 6.83 6.69 6.01
Exhibit 9.81
Mean: 645.786 Million DollarsMedian: 644.423 Million DollarsBase Case: 646.543 Million Dollars
Exhibit 9.82
Mean: 12.242 Billion DollarsMedian: 12.257 Billion DollarsBase Case: 12.269 Billion Dollars
Exhibit 9.92Supply v. Requirements
MDthDemand
Area Class Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 Demand
Ut/Id FS_COM 384.1 240.3 236.8 228.8 299.6 393.4 406.5 412.8 340.6 349.9 358.9 268.4 3920.1Ut/Id FS_IND 204.4 122.2 115.4 111.5 128.3 160.7 160.1 165.2 147.8 154.3 150.5 130.4 1750.7Ut/Id GS_COM 1363.7 525.4 444.9 429.6 1015.9 2421.8 3643.3 4917.1 3877.3 4062.4 3163.4 1283.7 27148.5Ut/Id GS_RES 1528.6 1444.5 1447.7 1396.3 4410.6 7486.5 10170.1 11400.6 7833.5 7157.0 6213.4 2131.9 62620.6Ut/Id IS_COM 46.7 29.8 28.5 27.5 38.6 70.8 83.8 104.1 78.7 88.5 67.3 48.5 712.7Ut/Id IS_ELC 11.1 5.7 8.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.3 26.9Ut/Id IS_IND 323.8 187.7 196.1 119.8 169.7 173.0 126.1 126.0 115.7 120.9 147.0 146.0 1951.7Ut/Id L_and_U 19.3 12.7 12.4 11.5 30.3 53.5 72.8 85.4 61.8 59.5 50.4 20.1 489.5
Wy QGC FS_COM 17.8 12.8 12.8 12.4 17.3 23.7 26.4 32.2 25.1 28.7 26.1 16.5 251.8Wy QGC GS_COM 84.9 25.4 19.8 19.1 53.5 128.1 185.8 259.9 202.4 244.7 187.6 89.4 1500.5Wy QGC GS_RES 77.5 31.2 42.3 30.1 139.6 257.3 306.8 385.7 284.5 295.9 233.5 90.1 2174.5Wy QGC IS_COM 6.3 3.3 5.6 3.1 9.5 13.7 19.3 16.3 18.3 21.5 17.6 8.2 142.8Wy QGC IS_IND 3.0 3.6 3.5 1.6 4.2 2.9 2.8 2.5 1.5 1.6 3.6 3.9 34.6Wy QGC L_and_U 0.9 0.4 0.4 0.3 1.1 2.1 2.7 3.4 2.6 2.9 2.3 1.0 20.3Ut Geo GS_COM 108.4 41.0 35.1 34.0 68.6 159.0 233.4 314.1 250.2 265.2 208.5 92.5 1810.1Ut Geo GS_RES 126.7 114.4 116.2 110.6 303.1 499.1 661.2 738.1 513.5 473.7 413.5 157.0 4227.1Ut Geo L_and_U 1.2 0.8 0.8 0.7 1.8 3.3 4.4 5.2 3.8 3.7 3.1 1.2 29.8Ut KRGT GS_COM 9.3 3.5 3.0 2.9 5.9 13.7 20.0 26.9 21.4 22.8 17.9 7.9 155.2Ut KRGT GS_RES 10.9 9.8 10.0 9.5 26.0 42.8 56.7 63.3 44.0 40.6 35.5 13.5 362.5Ut KRGT L_and_U 0.1 0.1 0.1 0.1 0.2 0.3 0.4 0.5 0.3 0.3 0.3 0.1 2.6UT NPC GS_COM 8.3 3.1 2.7 2.6 5.3 12.2 17.9 24.0 19.2 20.3 16.0 7.1 138.8UT NPC GS_RES 9.7 8.8 8.9 8.5 23.2 38.3 50.7 56.6 39.4 36.3 31.7 12.0 324.0UT NPC L_and_U 0.1 0.1 0.1 0.1 0.1 0.3 0.3 0.4 0.3 0.3 0.2 0.1 2.3
4346.6 2826.4 2751.7 2560.4 6752.6 11956.3 16251.5 19140.2 13881.9 13451.0 11347.9 4531.0 109797.5
Fuel Injected 30.8 50.5 49.7 68.8 14.8 2.6 0.0 0.0 42.9 0.0 8.5 45.9 314.6Fuel Withdrawal 2.0 0.3 0.3 0.4 2.7 31.1 13.3 68.2 0.4 16.4 2.9 1.0 139.0Fuel Transport 259.9 224.3 220.5 231.9 353.6 434.2 476.4 518.4 407.1 429.0 405.3 294.3 4254.9
Total 292.8 275.1 270.5 301.1 371.1 467.9 489.6 586.6 450.4 445.4 416.7 341.3 4708.6
Inject Clay Basin 1474.8 2418.9 2253.0 2057.5 396.0 101.4 0.0 0.0 2054.9 0.0 405.7 1754.3 12916.5Inject Aquifer 0.0 0.0 149.8 999.9 388.9 28.6 0.0 0.0 0.0 0.0 0.0 0.0 1567.1Inject Rykman 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 361.2 361.2
Total 1474.8 2418.9 2402.8 3057.4 784.9 129.9 0.0 0.0 2054.9 0.0 405.7 2115.5 14844.7
Total Required 6114.2 5520.4 5425.0 5918.9 7908.5 12554.1 16741.1 19726.9 16387.2 13896.4 12170.4 6987.8 129350.8
OffSystem Demand 74.9 77.4 72.5 74.9 72.5 74.9 68.2 63.2 69.9 72.5 74.9 72.5 868.1
Supply v. RequirementsMDth
Exhibit 9.93
Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 Total
Supply Exist Cont 0.0 0.0 0.0 0.0 0.0 0.0 775.0 0.0 0.0 0.0 0.0 0.0 775.0
Supply Peak Cont 0.0 0.0 0.0 0.0 0.0 0.0 0.0 36.6 414.0 0.0 0.0 0.0 450.6
Supply Spot 48.2 0.0 0.0 0.0 0.0 1419.1 6698.1 7027.4 9472.3 4571.1 4931.9 0.0 34168.0
48.2 0.0 0.0 0.0 0.0 1419.1 7473.1 7064.0 9886.2 4571.1 4931.9 0.0 35393.6
Withdrawal Aquifer 0.0 0.0 0.0 0.0 0.0 0.0 140.8 1677.1 0.0 0.0 0.0 0.0 1817.9
Withdrawal Clay Basin 265.1 43.3 39.9 37.5 384.8 3769.8 1343.5 3567.9 57.9 1997.0 405.7 145.6 12057.8
Withdrawal Company 5798.9 5475.0 5383.2 5879.4 7521.8 7363.3 7781.9 7416.3 6441.3 7326.3 6830.8 6840.2 80058.3
6063.9 5518.3 5423.1 5916.9 7906.6 11133.0 9266.2 12661.2 6499.1 9323.4 7236.5 6985.8 93934.0
Total Supply 6112.2 5518.3 5423.1 5916.9 7906.6 12552.1 16739.3 19725.2 16385.4 13894.5 12168.4 6985.8 129327.6
Withdrawal Off_System 76.9 79.4 74.4 76.9 74.4 76.9 70.0 64.8 71.8 74.4 76.9 74.4 891.2
Exhibit 9.83Base Case Supply : IRP Year 1
Mdth : WellheadNomination Groups Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 Total
ACEJD D24 12.7 13.0 12.9 12.4 12.7 12.2 12.5 12.4 11.1 12.2 11.7 12.0 147.8
ACEJD PC 3.9 4.0 0.0 3.8 3.9 3.9 4.0 4.0 3.6 4.0 3.8 3.9 42.8
BKSPUNT 6 PC 3.1 0.1 0.1 0.0 3.2 3.2 3.2 3.2 2.9 3.2 3.1 3.1 28.4
BRADY 19.0 19.4 19.2 8.6 8.8 8.4 8.6 8.6 7.7 8.4 8.0 8.2 132.9
BRCH CRK 179.5 184.3 183.1 176.1 180.8 173.8 178.5 177.3 159.1 175.1 168.3 172.8 2108.7
BRDTPJCK D24 4.8 4.9 4.8 4.6 4.7 4.5 4.6 4.5 4.0 4.4 4.2 4.3 54.3
BRFM D24 2.6 2.7 0.0 2.6 2.6 2.6 2.6 2.6 2.4 2.6 2.5 2.6 28.4
BRFQ D24 235.7 240.6 237.7 227.4 232.3 222.3 227.3 224.9 201.0 220.3 211.1 216.0 2696.6
BRFQ PC 32.4 1.1 1.1 0.0 33.0 32.8 33.7 33.5 30.1 33.1 31.9 32.8 295.5
BRFQMT D24 22.5 22.6 0.0 21.5 21.8 21.6 22.2 22.0 19.8 21.8 21.0 21.6 238.4
BRFW D24 90.2 92.3 10.0 87.7 87.1 86.0 88.1 87.3 78.1 85.7 82.2 84.2 958.9
BRFW PC 10.0 0.3 0.3 0.0 10.2 10.1 10.4 10.3 9.2 10.2 9.8 10.1 90.9
CBFR D24 15.8 16.3 0.5 15.6 16.0 15.9 16.4 16.3 14.6 16.1 15.5 16.0 175.0
CBFR PC 49.5 28.6 1.7 0.0 50.0 49.7 51.1 50.8 45.6 50.2 48.4 49.8 475.4
CCRUNIT D24 1128.1 1125.3 1088.7 1021.3 1019.0 964.5 970.6 946.4 834.4 902.7 854.4 864.1 11719.5
CCRUNIT PC 67.1 52.7 2.3 0.0 66.7 66.3 68.1 67.7 60.8 67.0 64.5 66.4 649.6
CHBTBUFF D24 0.8 0.9 0.9 0.8 0.8 0.8 0.8 0.8 0.7 0.8 0.8 0.8 9.7
CHBTCAT1 D24 1.4 1.4 0.1 1.4 1.3 1.3 1.4 1.4 1.2 1.3 1.3 1.3 14.8
CHBTCAT1 PC 48.6 1.7 1.7 0.0 49.6 49.2 50.5 50.2 45.1 49.6 47.8 49.1 443.1
CHBTCAT2 D24 130.1 130.9 4.3 122.1 122.8 121.7 124.6 123.6 110.7 121.6 116.8 120.0 1349.2
CHBTCAT2 PC 3.9 0.1 0.1 0.0 3.9 3.9 4.0 3.9 3.5 3.9 3.7 3.8 34.7
CHBTCAT3 D24 263.3 269.7 267.3 256.5 262.7 252.1 258.3 256.2 229.5 252.0 242.0 248.0 3057.6
DRYPINY6 D24 1.6 1.7 1.6 1.6 1.6 1.6 1.6 1.6 1.4 1.6 1.5 1.6 19.0
DRYPINY6 PC 1.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 0.9 1.0 1.0 1.0 8.9
DRYPINYU D24 13.2 13.5 0.4 12.8 12.5 12.4 12.7 12.6 11.3 12.4 12.0 12.3 138.1
DRYPINYU PC 12.9 0.4 0.4 0.0 13.1 13.0 13.3 13.3 11.9 13.1 12.6 12.9 116.9
DRYPINYU PW 0.6 0.0 0.0 0.0 0.6 0.6 0.6 0.6 0.5 0.6 0.6 0.6 5.3
FOGARTY PC 0.0 0.0 0.0 0.0 0.6 0.6 0.6 0.6 0.5 0.6 0.5 0.0 4.0
HWA DEEP D24 22.6 23.2 0.8 22.1 22.5 22.3 22.9 22.8 20.5 22.5 21.7 22.3 246.2
HWA DEEP PC 6.3 6.5 0.2 6.2 6.3 6.2 6.4 6.4 5.7 6.3 6.1 6.2 68.8
HWPLT1&3 D24 86.8 88.4 2.8 82.2 80.8 80.1 82.1 81.4 73.0 80.2 77.1 79.2 894.1
HWPLT1&3 PC 60.2 2.1 2.1 0.0 61.3 60.8 62.3 61.9 55.5 61.1 58.7 60.4 546.4
HWPLT2 D24 11.2 11.5 11.4 11.0 11.2 10.8 11.1 11.0 9.9 10.8 10.4 10.7 131.0
HWPLT2 PC 1.1 0.0 0.0 0.0 1.0 1.0 1.1 1.0 0.9 1.0 1.0 1.0 9.1
ISLAND D24 97.6 100.2 99.6 95.7 98.3 94.5 97.0 96.4 86.5 95.2 91.6 94.0 1146.6
ISLAND PC 2.6 2.7 2.7 2.6 2.6 2.5 2.6 2.6 2.3 2.6 2.5 2.5 30.8
JNSNRDG D24 2.6 2.7 0.1 2.6 2.6 2.6 2.7 2.7 2.4 2.6 2.5 2.6 28.7
JNSNRDG PC 2.8 0.1 0.1 0.0 2.8 2.8 2.9 2.8 2.5 2.8 2.7 2.7 25.0
JRDG WFS D24 3.2 3.3 3.3 3.1 3.2 3.1 3.2 3.2 2.8 3.1 3.0 3.1 37.6
KNY FLD D24 24.6 24.9 24.4 23.2 22.7 22.3 22.7 22.3 19.8 21.6 20.5 20.9 269.9
KNY FLD PC 14.2 0.5 0.5 0.0 14.5 14.4 14.8 14.7 13.2 14.6 14.0 14.4 129.8
LEUCITE D24 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.5 0.6 0.5 0.6 7.0
LEUCITE PC 1.0 1.0 0.0 1.0 1.0 1.0 1.0 1.0 0.9 1.0 1.0 1.0 10.9
MDBXCOMP PC 4.7 0.2 0.2 0.0 4.8 4.7 4.9 4.8 4.3 4.8 4.6 4.7 42.7
MESA D24 1147.1 1164.9 1145.8 1091.6 1111.2 1060.0 1080.2 1065.8 950.3 1039.0 993.3 1014.3 12863.5
MOSU D24 4.8 0.2 0.2 0.0 4.8 4.8 4.9 4.8 4.3 4.8 4.6 4.7 42.9
MOSU PC 3.4 0.1 0.1 0.0 3.5 3.4 3.5 3.5 3.1 3.4 3.3 3.4 30.7
MOSU PW 0.6 0.6 0.0 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 6.6
MUSSCOMP PC 1.8 1.9 0.1 1.7 1.8 1.8 1.8 1.8 1.6 1.8 1.7 1.8 19.6
NBXCAMP PC 4.2 4.4 0.1 4.2 4.3 4.3 4.4 4.4 3.9 4.4 4.2 4.3 47.1
NOBXFLD PC 2.6 0.1 0.1 0.0 2.6 2.5 2.6 2.6 2.3 2.5 2.4 2.5 22.8
PDW1A1B D24 3.9 4.0 4.0 3.9 4.0 3.8 3.9 3.9 3.5 3.8 3.7 3.8 46.2
PDW1A1B PC 21.7 0.7 0.7 0.0 21.8 21.6 22.1 21.9 19.6 21.5 20.6 21.2 193.4
PDWCUT D24 26.8 27.4 27.1 26.0 26.6 25.5 26.1 25.9 23.1 25.4 24.4 24.9 309.2
PDWCUT PC 5.6 5.8 0.2 5.5 5.6 5.6 5.7 5.7 5.1 5.7 5.5 5.6 61.6
Exhibit 9.84
Base Case Supply : IRP Year 1
Mdth : Wellhead … ContinuedPDWMT D24 315.2 317.8 310.5 293.9 297.3 281.9 285.7 280.4 248.7 270.6 257.5 261.8 3421.3PDWMT PC 1.7 0.1 0.1 0.0 1.6 1.6 1.6 1.6 1.4 1.6 1.5 1.5 14.3PDWPLT2 D24 138.0 140.3 138.2 131.9 134.4 128.4 131.0 129.4 115.6 126.5 121.1 123.8 1558.6PDWPLT2 PC 29.7 30.5 1.0 20.2 29.5 29.2 29.9 29.7 26.6 29.2 28.1 28.8 312.4PDWPLT3 D24 64.0 65.4 64.6 61.8 63.2 60.4 61.8 61.1 54.7 59.9 57.4 58.7 733.0PDWPLT3 PC 14.9 0.5 0.5 0.0 14.9 14.7 15.0 14.9 13.3 14.6 14.0 14.4 131.7RBTMTN D24 8.3 8.5 8.4 8.1 8.3 8.0 8.2 8.2 7.3 8.1 7.8 8.0 97.2RBTMTN PC 5.3 5.5 5.5 5.3 5.4 5.2 5.4 5.3 4.8 5.3 5.1 5.2 63.3SBXSOUR PC 0.0 0.0 0.0 30.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 30.0SBXSWEET D24 0.3 0.4 0.0 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 3.4SGRLF D24 24.3 24.7 24.3 23.1 23.5 22.3 22.7 22.4 19.9 21.7 20.7 21.1 270.7SGRLF PC 44.9 1.5 1.5 0.0 45.6 45.1 46.2 45.8 41.0 45.0 43.2 44.4 404.2TRAIL D24 588.6 591.6 261.7 543.8 531.0 519.1 524.8 513.8 454.8 493.8 469.0 475.9 5967.9TRAIL PC 1.7 1.7 0.1 1.7 1.7 1.7 1.7 1.7 1.5 1.7 1.6 1.7 18.5WHLA D24 58.9 60.3 59.8 57.3 58.7 56.3 57.7 57.2 51.2 56.2 53.9 55.2 682.7WHLA PC 12.6 0.4 0.4 0.0 12.6 12.5 12.8 12.6 11.3 12.4 11.9 12.2 111.7WWILSON D24 3.9 4.0 4.0 3.8 3.9 3.7 3.8 3.8 3.4 3.7 3.6 3.7 45.3WWILSON PC 23.8 0.8 0.8 0.0 24.2 24.0 24.7 24.5 22.0 24.2 23.3 23.9 216.2z13 CCRU D24 166.7 163.5 155.8 144.1 142.7 132.7 132.1 127.5 111.3 119.4 112.0 112.4 1620.2z13 MESA D24 272.8 248.3 1081.1 1102.3 2285.8 2331.3 2666.3 2379.8 1960.1 2007.2 1815.2 1766.4 19916.6z13 TRAL D24 104.2 102.9 98.6 91.7 91.3 85.3 85.2 82.5 72.3 77.7 73.1 73.5 1038.3z14 MESA D24 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 428.6 348.1 314.8 1091.5
5798.9 5475.0 5383.2 5879.4 7521.8 7363.3 7781.9 7416.3 6441.3 7326.3 6830.8 6840.2 80058.4
Exhibit 9.85
Base Case Supply : IRP Year 1
Mdth : ReservoirStorage Withdrawals Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 TotalChalk Creek 0.0 0.0 0.0 0.0 0.0 0.0 25.0 296.0 0.0 0.0 0.0 0.0 321.0Clay Bsn 935 49.5 0.0 0.0 36.2 0.0 1740.9 202.2 1585.7 0.0 882.4 23.6 0.0 4520.5Clay Bsn 988 50.2 0.0 0.0 0.0 312.7 1183.7 378.7 991.1 17.8 572.1 117.9 0.0 3624.0Clay Bsn 997 165.3 43.3 39.9 1.2 72.1 845.2 762.6 991.1 40.0 542.6 264.3 145.6 3913.3Coalville 0.0 0.0 0.0 0.0 0.0 0.0 53.2 604.7 0.0 0.0 0.0 0.0 658.0Leroy 0.0 0.0 0.0 0.0 0.0 0.0 62.6 776.3 0.0 0.0 0.0 0.0 838.9
265.1 43.3 39.9 37.5 384.8 3769.8 1484.3 5244.9 57.8 1997.0 405.7 145.6 13875.7
Mdth : WellheadPurchase Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 Total
Spot 46.9 0.0 0.0 0.0 0.0 1307.0 4569.4 3249.3 6445.0 2745.2 4694.9 0.0 23057.6SpotKR_Opal 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1606.3 793.9 0.0 4.9 0.0 2405.1SpotKR_Gosh 0.0 0.0 0.0 0.0 0.0 0.0 1701.4 1701.4 1536.8 1701.4 4.9 0.0 6646.0SpotKR_Wecco 0.0 0.0 0.0 0.0 0.0 112.0 427.3 470.3 690.7 124.5 146.6 0.0 1971.3SpotKRCG 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 78.1 0.0 78.1Spot‐2‐NPC 1.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.9 0.0 2.6 0.0 9.9Bfr‐contract 0.0 0.0 0.0 0.0 0.0 0.0 775.0 0.0 0.0 0.0 0.0 0.0 775.0Purchase 1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 20.0 174.0 0.0 0.0 0.0 194.0Purchase 2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 16.6 120.0 0.0 0.0 0.0 136.6Purchase 3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 120.0 0.0 0.0 0.0 120.0
48.2 0.0 0.0 0.0 0.0 1419.1 7473.2 7064.0 9886.2 4571.1 4931.9 0.0 35393.6
Mdth : ReservoirStorage Inject Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 Total
Chalk Creek 0.0 0.0 0.0 146.5 161.5 13.0 0.0 0.0 0.0 0.0 0.0 0.0 321.0Clay Bsn 935 162.2 1094.1 1023.5 941.4 29.2 30.8 0.0 0.0 882.4 0.0 23.6 273.1 4460.3Clay Bsn 988 655.7 662.7 617.5 550.1 186.5 35.4 0.0 0.0 589.9 0.0 117.9 740.6 4156.3Clay Bsn 997 656.8 662.1 612.1 566.0 180.3 35.2 0.0 0.0 582.6 0.0 264.3 740.6 4300.0Coalville 0.0 0.0 149.8 282.5 210.2 15.5 0.0 0.0 0.0 0.0 0.0 0.0 658.0Leroy 0.0 0.0 0.0 570.9 17.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 588.1Ryckman 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 361.2 361.2
1474.8 2418.9 2402.8 3057.4 784.9 129.9 0.0 0.0 2054.9 0.0 405.7 2115.5 14844.7
Exhibit 9.86
Base Case Supply : IRP Year 2Mdth : Wellhead
Nomination Groups Jun‐14 Jul‐14 Aug‐14 Sep‐14 Oct‐14 Nov‐14 Dec‐14 Jan‐15 Feb‐15 Mar‐15 Apr‐15 May‐15 TotalACEJD D24 11.5 11.8 11.7 11.3 11.5 11.1 11.4 11.3 10.1 11.1 10.7 11.0 134.5ACEJD PC 3.8 0.0 0.0 3.8 3.8 3.7 3.8 3.8 3.4 3.8 3.7 3.8 37.3BKSPUNT 6 PC 0.0 0.0 0.0 2.1 3.0 3.0 3.1 3.0 2.7 3.0 2.9 3.0 25.7BRADY 7.9 8.1 8.0 7.6 7.8 7.5 7.7 7.6 6.8 7.5 7.2 7.3 90.9BRCH CRK 166.2 170.7 169.6 163.1 167.4 161.0 165.3 164.3 147.5 162.2 156.0 160.2 1953.4BRDTPJCK D24 4.1 4.1 4.1 3.9 4.0 3.8 3.9 3.8 3.4 3.7 3.5 3.6 45.7BRFM D24 2.5 0.0 0.0 2.4 2.4 2.4 2.5 2.5 2.2 2.4 2.3 2.4 24.1BRFQ D24 207.0 211.9 210.0 201.3 206.2 197.8 202.6 200.8 179.9 197.5 189.5 194.2 2398.7BRFQ PC 31.5 0.0 0.0 30.2 31.1 30.9 31.7 31.5 28.3 31.1 30.0 30.8 307.1BRFQMT D24 20.7 0.0 0.0 20.6 20.4 20.3 20.9 20.7 18.6 20.5 19.7 20.3 202.6BRFW D24 80.8 82.7 60.1 78.7 78.3 77.4 79.3 78.7 70.5 77.4 74.3 76.1 914.1BRFW PC 0.0 0.0 0.0 9.3 9.6 9.5 9.8 9.7 8.7 9.6 9.3 9.5 85.2CBFR D24 15.4 0.0 0.0 15.3 15.2 15.1 15.5 15.4 13.9 15.3 14.7 15.2 150.9CBFR PC 47.9 0.0 0.0 45.9 47.3 47.0 48.3 48.0 43.1 47.4 45.7 47.0 467.6CCRUNIT D24 819.2 829.8 814.0 773.2 784.7 746.1 758.0 745.5 662.6 722.2 688.2 700.6 9044.1CCRUNIT PC 63.9 0.0 0.0 61.5 63.1 62.7 64.5 64.1 57.6 63.4 61.1 62.9 624.6CHBTBUFF D24 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.7 0.8 0.7 0.8 9.2CHBTCAT1 D24 1.3 1.3 0.0 1.3 1.3 1.2 1.3 1.3 1.1 1.3 1.2 1.2 13.7CHBTCAT1 PC 47.2 0.0 0.0 45.3 46.6 46.3 47.5 47.2 42.4 46.6 44.9 46.2 460.1CHBTCAT2 D24 115.1 0.0 0.0 113.8 113.0 111.9 114.7 113.6 101.8 111.7 107.4 110.3 1113.2CHBTCAT2 PC 0.0 0.0 0.0 2.6 3.6 3.6 3.7 3.7 3.3 3.6 3.5 3.6 31.0CHBTCAT3 D24 238.2 244.2 242.3 232.7 238.6 229.2 235.0 233.3 209.1 229.8 220.8 226.5 2779.4DRYPINY6 D24 1.5 1.5 1.5 1.5 1.5 1.4 1.5 1.5 1.3 1.5 1.4 1.4 17.5DRYPINY6 PC 0.0 0.0 0.0 0.7 0.9 0.9 1.0 0.9 0.9 0.9 0.9 0.9 8.0DRYPINYU D24 11.8 12.1 0.0 11.6 11.5 11.5 11.8 11.7 10.5 11.5 11.1 11.4 126.4DRYPINYU PC 0.0 0.0 0.0 8.7 12.3 12.2 12.5 12.4 11.1 12.3 11.8 12.1 105.4DRYPINYU PW 0.0 0.0 0.0 0.4 0.6 0.6 0.6 0.6 0.5 0.6 0.5 0.6 4.8FOGARTY PC 0.0 0.0 0.0 0.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.0 3.8HWA DEEP D24 21.5 0.0 0.0 21.3 21.2 21.1 21.6 21.5 19.3 21.2 20.5 21.1 210.2HWA DEEP PC 6.0 0.0 0.0 6.0 5.9 5.9 6.1 6.0 5.4 5.9 5.7 5.9 58.8HWPLT1&3 D24 76.0 34.0 0.0 74.9 74.4 73.7 75.6 74.9 67.1 73.7 70.9 72.8 767.8HWPLT1&3 PC 0.0 0.0 0.0 40.6 57.6 57.2 58.7 58.2 52.2 57.4 55.3 56.8 494.0HWPLT2 D24 10.3 10.5 10.4 10.0 10.3 9.9 10.1 10.1 9.0 9.9 9.5 9.8 119.9HWPLT2 PC 0.0 0.0 0.0 0.7 0.9 0.9 1.0 0.9 0.8 0.9 0.9 0.9 7.9ISLAND D24 90.4 92.9 92.3 88.8 91.1 87.7 90.0 89.5 80.3 88.4 85.0 87.3 1063.7ISLAND PC 2.4 2.5 2.5 2.4 2.4 2.3 2.4 2.4 2.1 2.4 2.3 2.3 28.3JNSNRDG D24 2.5 0.0 0.0 2.5 2.4 2.4 2.5 2.5 2.2 2.4 2.3 2.4 24.0JNSNRDG PC 0.0 0.0 0.0 1.8 2.6 2.6 2.6 2.6 2.3 2.6 2.5 2.5 22.2JRDG WFS D24 2.9 3.0 3.0 2.9 3.0 2.8 2.9 2.9 2.6 2.9 2.8 2.8 34.5KNY FLD D24 19.9 20.3 20.0 19.1 19.5 18.6 19.0 18.7 16.7 18.3 17.5 17.9 225.5KNY FLD PC 13.9 0.0 0.0 13.3 13.7 13.7 14.0 14.0 12.5 13.8 13.3 13.7 135.9LEUCITE D24 0.5 0.6 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 6.2LEUCITE PC 1.0 0.0 0.0 1.0 1.0 1.0 1.0 1.0 0.9 1.0 1.0 1.0 9.7MDBXCOMP PC 4.5 0.0 0.0 4.4 4.5 4.5 4.6 4.5 4.1 4.5 4.3 4.4 44.3MESA D24 970.3 991.4 980.6 938.8 959.9 919.4 940.4 931.1 832.8 913.2 875.5 896.3 11149.5MOSU D24 4.5 0.0 0.0 4.3 4.4 4.4 4.5 4.5 4.0 4.4 4.2 4.3 43.5MOSU PC 0.0 0.0 0.0 2.3 3.2 3.2 3.3 3.2 2.9 3.2 3.0 3.1 27.3MOSU PW 0.6 0.0 0.0 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 5.9MUSSCOMP PC 1.7 0.0 0.0 1.7 1.7 1.7 1.7 1.7 1.5 1.7 1.6 1.7 16.7NBXCAMP PC 4.2 0.0 0.0 4.1 4.1 4.1 4.2 4.2 3.8 4.2 4.0 4.1 40.9NOBXFLD PC 0.0 0.0 0.0 1.7 2.4 2.3 2.4 2.4 2.1 2.3 2.2 2.3 20.2PDW1A1B D24 3.6 3.7 3.7 3.6 3.7 3.5 3.6 3.6 3.2 3.6 3.4 3.5 42.7PDW1A1B PC 6.6 0.0 0.0 19.5 20.0 19.8 20.3 20.1 18.0 19.8 19.0 19.5 182.6PDWCUT D24 23.9 24.5 24.3 23.3 23.9 23.0 23.5 23.4 20.9 23.0 22.1 22.6 278.5PDWCUT PC 5.4 0.0 0.0 5.4 5.4 5.3 5.5 5.5 4.9 5.4 5.2 5.4 53.2
Exhibit 9.87
Base Case Supply : IRP Year 2
Mdth : Wellhead… ContinuedPDWMT D24 249.3 253.7 250.0 238.4 242.9 231.9 236.4 233.4 208.1 227.6 217.5 222.1 2811.4
PDWMT PC 0.0 0.0 0.0 1.0 1.4 1.4 1.4 1.4 1.2 1.3 1.3 0.0 10.5PDWPLT2 D24 118.5 121.3 120.0 115.0 117.7 112.9 115.5 114.5 102.5 112.5 107.9 110.5 1368.9PDWPLT2 PC 27.7 0.0 0.0 26.5 27.2 26.9 27.6 27.3 24.5 26.9 25.9 26.6 267.0PDWPLT3 D24 56.3 57.6 57.1 54.7 56.0 53.7 55.0 54.6 48.9 53.6 51.5 52.7 651.6
PDWPLT3 PC 0.0 0.0 0.0 9.6 13.6 13.5 13.8 13.6 12.2 13.4 12.8 13.2 115.6RBTMTN D24 7.7 7.9 7.8 7.5 7.7 7.4 7.6 7.6 6.8 7.5 7.2 7.4 90.0RBTMTN PC 5.0 5.2 5.1 4.9 5.1 4.9 5.0 5.0 4.5 5.0 4.8 4.9 59.4SBXSWEET D24 0.3 0.3 0.0 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 3.6SGRLF D24 20.2 20.6 20.3 19.4 19.8 18.9 19.3 19.1 17.1 18.7 17.9 18.3 229.3
SGRLF PC 0.0 0.0 0.0 29.8 42.2 41.8 42.8 42.4 38.0 41.7 40.1 41.1 359.9TRAIL D24 452.5 459.6 452.0 430.5 429.9 417.3 424.9 418.8 372.9 407.2 388.8 396.5 5050.9TRAIL PC 1.6 1.7 0.0 1.6 1.6 1.6 1.7 1.7 1.5 1.7 1.6 1.7 18.1WHLA D24 53.0 54.3 53.9 51.7 53.0 50.9 52.2 51.8 46.4 51.0 48.9 50.2 617.4WHLA PC 0.0 0.0 0.0 8.2 11.6 11.4 11.7 11.6 10.4 11.3 10.9 11.2 98.2
WWILSON D24 3.5 3.6 3.6 3.4 3.5 3.3 3.4 3.4 3.0 3.3 3.2 3.3 40.4WWILSON PC 0.0 0.0 0.0 18.9 22.8 22.7 23.3 23.1 20.7 22.8 21.9 22.6 198.8z13 CCRU D24 105.8 106.4 103.7 97.9 98.7 93.3 94.3 92.3 81.6 88.6 84.0 85.2 1131.7z13 MESA D24 1619.7 1593.7 1523.8 1414.8 1406.7 1313.3 1312.1 1271.1 1114.1 1198.9 1129.2 1137.2 16034.4z13 TRAL D24 69.3 69.9 68.2 64.5 65.2 61.7 62.5 61.2 54.2 58.9 55.9 56.7 748.2
z14 MESA D24 273.6 258.4 409.2 601.2 804.4 936.7 1116.9 1254.6 1019.0 1035.2 931.6 903.6 9544.5
6234.8 5776.5 5733.9 6344.7 6658.7 6537.2 6809.2 6856.9 6003.1 6473.1 6121.2 6193.3 75742.6
Exhibit 9.88
Base Case Supply : IRP Year 2
Mdth : Reservoir
Storage Withdrawals Jun‐14 Jul‐14 Aug‐14 Sep‐14 Oct‐14 Nov‐14 Dec‐14 Jan‐15 Feb‐15 Mar‐15 Apr‐15 May‐15 TotalChalk Creek 0.0 0.0 0.0 0.0 0.0 0.0 321.0 0.0 0.0 0.0 0.0 0.0 321.0Clay Bsn 935 0.0 0.0 0.0 0.0 0.0 1894.5 2065.8 31.9 1345.3 0.0 189.4 0.0 5526.8Clay Bsn 988 8.8 52.0 0.0 0.7 0.0 1630.6 1285.9 0.0 795.1 0.0 119.1 0.0 3892.1Clay Bsn 997 66.7 0.0 0.0 0.0 0.0 1533.9 1285.9 0.0 795.1 0.0 119.1 87.3 3887.8Coalville 0.0 0.0 0.0 0.0 0.0 0.0 693.3 0.0 0.0 0.0 0.0 0.0 693.3Leroy 0.0 0.0 0.0 0.0 0.0 0.0 887.0 0.0 0.0 0.0 0.0 0.0 887.0Ryckman 0.0 0.0 0.0 0.0 0.0 498.0 514.6 321.7 448.2 0.0 0.0 0.0 1782.5
75.5 52.0 0.0 0.7 0.0 5557.0 7053.4 353.5 3383.7 0.0 427.5 87.3 16990.4
Mdth : Wellhead
Purchase Jun‐14 Jul‐14 Aug‐14 Sep‐14 Oct‐14 Nov‐14 Dec‐14 Jan‐15 Feb‐15 Mar‐15 Apr‐15 May‐15 Totala IT Supply 0.0 0.0 0.0 0.0 0.0 0.0 50.0 0.0 0.0 0.0 0.0 0.0 50.0
Spot 0.0 0.0 0.0 465.2 2029.1 1657.7 3225.8 5685.7 4566.3 3698.9 3357.7 0.0 24686.4
SpotKR_Opal 0.0 0.0 0.0 0.0 0.0 0.0 54.2 1653.6 163.9 63.0 4.9 0.0 1939.5
SpotKR_Gosh 0.0 0.0 0.0 7.5 58.2 0.0 1646.6 1701.4 1536.8 1695.7 4.9 0.0 6651.0
SpotKR_Wecco 0.0 0.0 51.8 106.8 148.2 145.8 458.9 796.4 385.2 551.4 65.9 0.0 2710.3
SpotKRCG 0.0 0.0 0.0 0.0 6.3 0.0 0.0 0.0 0.0 0.0 3.1 0.0 9.3
Spot‐2‐NPC 0.0 0.0 0.0 12.8 23.8 0.0 7.2 0.0 0.5 0.0 2.2 0.0 46.4
Bfr‐contract 0.0 0.0 0.0 150.0 0.0 0.0 775.0 0.0 0.0 0.0 0.0 0.0 925.0
Purchase1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 36.7 60.0 0.0 0.0 0.0 96.7
0.0 0.0 51.8 742.3 2265.4 1803.4 6217.5 9873.9 6712.6 6009.0 3438.6 0.0 37114.6
Mdth : Wellhead
Storage Injection Jun‐14 Jul‐14 Aug‐14 Sep‐14 Oct‐14 Nov‐14 Dec‐14 Jan‐15 Feb‐15 Mar‐15 Apr‐15 May‐15 TotalChalk Creek 0.0 0.0 0.0 59.9 261.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 321.0Clay Bsn 935 1125.2 1071.8 985.1 854.2 818.3 0.0 0.0 209.7 0.0 152.3 37.1 844.1 6097.7Clay Bsn 988 658.7 628.2 581.6 504.3 483.1 0.0 0.0 154.7 21.9 95.2 23.9 740.6 3892.1Clay Bsn 997 670.1 643.7 591.6 513.0 491.4 0.0 0.0 154.7 21.9 95.2 23.9 740.6 3946.2Coalville 0.0 0.0 155.0 274.4 256.2 7.6 0.0 0.0 0.0 0.0 0.0 0.0 693.3Leroy 0.0 0.0 0.0 316.6 570.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 887.0Ryckman 349.5 361.2 361.2 349.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 361.2 1782.5
2803.6 2704.7 2674.4 2871.9 2880.6 7.6 0.0 519.1 43.7 342.7 84.9 2686.4 17619.7
Exhibit 9.89
Normal Case : Year 1Mdth : Wellhead
Nomination Groups Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 TotalACEJD D24 12.7 13.0 12.9 12.4 12.7 12.2 12.5 12.4 11.1 12.2 11.7 12.0 147.4ACEJD PC 3.6 4.0 0.0 3.8 4.1 3.9 4.0 4.0 3.6 4.0 3.8 3.9 42.7BKSPUNT 6 PC 2.9 0.5 0.0 3.1 3.2 3.1 3.2 3.2 2.9 3.2 3.0 3.1 31.3BRADY 19.0 19.4 19.2 8.6 8.8 8.4 8.6 8.6 7.7 8.4 8.0 8.2 132.9BRCH CRK 179.5 184.3 183.1 176.1 180.8 173.8 178.5 177.3 159.1 175.1 168.3 172.8 2108.7BRDTPJCK D24 4.8 4.9 4.8 4.6 4.7 4.5 4.6 4.5 4.0 4.4 4.2 4.3 54.2BRFM D24 2.4 2.7 0.0 2.6 2.7 2.6 2.7 2.6 2.4 2.6 2.5 2.6 28.3BRFQ D24 235.7 240.6 237.7 227.4 232.3 222.3 227.3 224.9 201.0 220.3 211.1 216.0 2696.5BRFQ PC 30.2 5.6 0.0 31.9 32.9 32.6 33.5 33.3 29.9 32.9 31.7 32.6 327.0BRFQMT D24 20.5 22.6 0.0 21.5 22.5 21.6 22.2 22.1 19.8 21.8 21.0 21.6 237.1BRFW D24 90.2 92.3 9.7 87.7 89.7 86.0 88.1 87.3 78.1 85.7 82.2 84.2 961.1BRFW PC 9.3 1.7 0.0 9.8 10.1 10.0 10.3 10.2 9.2 10.1 9.7 10.0 100.5CBFR D24 14.7 16.3 0.0 15.6 16.6 15.9 16.4 16.3 14.6 16.1 15.5 16.0 174.0CBFR PC 46.1 8.5 0.0 48.5 51.6 49.6 50.9 50.6 45.5 50.1 48.2 49.6 499.3CCRUNIT D24 1128.1 1125.3 1088.7 1021.3 1024.8 964.5 970.6 946.4 834.4 902.7 854.4 864.1 11725.3CCRUNIT PC 62.5 11.5 0.0 65.2 68.9 66.2 68.0 67.6 60.7 66.9 64.4 66.3 668.0CHBTBUFF D24 0.8 0.9 0.9 0.8 0.8 0.8 0.8 0.8 0.7 0.8 0.8 0.8 9.8CHBTCAT1 D24 1.4 1.4 0.0 1.4 1.4 1.3 1.4 1.4 1.2 1.3 1.3 1.3 14.8CHBTCAT1 PC 45.3 8.3 0.0 47.9 50.1 49.0 50.2 49.9 44.8 49.3 47.5 48.8 491.1CHBTCAT2 D24 126.2 128.8 0.0 124.0 127.2 121.9 124.7 123.6 110.8 121.7 116.8 120.0 1345.6CHBTCAT2 PC 3.6 0.7 0.0 3.8 3.9 3.8 3.9 3.9 3.5 3.8 3.7 3.8 38.4CHBTCAT3 D24 263.3 269.7 267.3 256.5 262.7 252.1 258.3 256.2 229.5 252.0 242.0 248.0 3057.7DRYPINY6 D24 1.6 1.7 1.6 1.6 1.6 1.6 1.6 1.6 1.4 1.6 1.5 1.6 18.9DRYPINY6 PC 0.9 0.2 0.0 1.0 1.0 1.0 1.0 1.0 0.9 1.0 1.0 1.0 9.9DRYPINYU D24 13.2 13.5 0.0 12.8 12.9 12.4 12.7 12.6 11.3 12.4 12.0 12.3 137.9DRYPINYU PC 12.0 2.2 0.0 12.7 13.1 12.9 13.3 13.2 11.8 13.0 12.5 12.8 129.3DRYPINYU PW 0.5 0.1 0.0 0.6 0.6 0.6 0.6 0.6 0.5 0.6 0.6 0.6 5.9FOGARTY PC 0.6 0.1 0.0 0.6 0.6 0.6 0.6 0.6 0.5 0.5 0.5 0.5 5.6HWA DEEP D24 21.0 23.2 0.0 22.1 23.3 22.4 22.9 22.8 20.5 22.6 21.7 22.3 244.8HWA DEEP PC 5.9 6.5 0.0 6.2 6.5 6.2 6.4 6.4 5.7 6.3 6.1 6.2 68.3HWPLT1&3 D24 86.8 88.0 0.0 83.1 83.7 80.2 82.1 81.4 73.0 80.2 77.0 79.2 894.7HWPLT1&3 PC 56.0 10.3 0.0 59.2 60.9 60.4 61.9 61.5 55.2 60.7 58.3 60.0 604.4HWPLT2 D24 11.2 11.5 11.4 11.0 11.2 10.8 11.1 11.0 9.9 10.8 10.4 10.7 130.9HWPLT2 PC 1.0 0.2 0.0 1.0 1.0 1.0 1.0 1.0 0.9 1.0 1.0 1.0 10.1ISLAND D24 97.6 100.2 99.6 95.7 98.3 94.5 97.0 96.4 86.5 95.2 91.6 94.0 1146.8ISLAND PC 2.6 2.7 2.7 2.6 2.6 2.5 2.6 2.6 2.3 2.6 2.5 2.5 30.7JNSNRDG D24 2.5 2.7 0.0 2.6 2.7 2.6 2.7 2.7 2.4 2.6 2.5 2.6 28.5JNSNRDG PC 2.6 0.5 0.0 2.7 2.8 2.8 2.8 2.8 2.5 2.8 2.6 2.7 27.6JRDG WFS D24 3.2 3.3 3.3 3.1 3.2 3.1 3.2 3.2 2.8 3.1 3.0 3.1 37.5KNY FLD D24 24.6 24.9 24.4 23.2 23.5 22.3 22.7 22.3 19.8 21.6 20.5 20.9 270.8KNY FLD PC 13.2 2.4 0.0 14.0 14.9 14.3 14.7 14.6 13.2 14.5 14.0 14.4 144.2LEUCITE D24 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.5 0.6 0.5 0.6 6.8LEUCITE PC 0.9 1.0 0.0 1.0 1.1 1.0 1.0 1.0 0.9 1.0 1.0 1.0 11.1MDBXCOMP PC 4.3 0.8 0.0 4.6 4.9 4.7 4.8 4.8 4.3 4.7 4.6 4.7 47.3MESA D24 1147.1 1164.9 1145.8 1091.6 1111.2 1060.0 1080.2 1065.8 950.3 1039.0 993.3 1014.3 12863.5MOSU D24 4.5 1.3 0.0 4.7 4.9 4.7 4.8 4.8 4.3 4.7 4.5 4.7 48.0MOSU PC 3.2 0.6 0.0 3.3 3.4 3.4 3.5 3.4 3.1 3.4 3.3 3.3 33.9MOSU PW 0.6 0.6 0.0 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 6.7MUSSCOMP PC 1.7 1.9 0.0 1.7 1.8 1.8 1.8 1.8 1.6 1.8 1.7 1.8 19.4NBXCAMP PC 4.0 4.4 0.0 4.2 4.5 4.3 4.4 4.4 4.0 4.4 4.2 4.3 46.9NOBXFLD PC 2.4 0.4 0.0 2.5 2.5 2.5 2.6 2.5 2.3 2.5 2.4 2.5 25.1PDW1A1B D24 3.9 4.0 4.0 3.9 4.0 3.8 3.9 3.9 3.5 3.8 3.7 3.8 46.1PDW1A1B PC 20.2 3.7 0.0 21.3 22.3 21.4 21.9 21.7 19.4 21.3 20.4 21.0 214.6PDWCUT D24 26.8 27.4 27.1 26.0 26.6 25.5 26.1 25.9 23.1 25.4 24.4 24.9 309.3PDWCUT PC 5.2 5.8 0.0 5.5 5.8 5.6 5.7 5.7 5.1 5.7 5.5 5.6 61.1
Exhibit 9.90
Normal Case : Year 1Mdth : Wellhead… Continued
PDWMT D24 315.2 317.8 310.5 293.9 297.3 281.9 285.7 280.4 248.7 270.6 257.5 261.8 3421.2PDWMT PC 1.5 0.3 0.0 1.6 1.6 1.6 1.6 1.6 1.4 1.5 1.5 1.5 15.7PDWPLT2 D24 138.0 140.3 138.2 131.9 134.4 128.4 131.0 129.4 115.6 126.5 121.1 123.8 1558.5PDWPLT2 PC 27.7 5.1 0.0 29.2 30.7 29.4 30.1 29.8 26.7 29.4 28.2 29.0 295.2PDWPLT3 D24 64.0 65.4 64.6 61.8 63.2 60.4 61.8 61.1 54.7 59.9 57.4 58.7 732.9PDWPLT3 PC 13.8 2.6 0.0 14.6 15.3 14.6 14.9 14.7 13.2 14.5 13.9 14.2 146.1RBTMTN D24 8.3 8.5 8.4 8.1 8.3 8.0 8.2 8.2 7.3 8.1 7.8 8.0 97.1RBTMTN PC 5.3 5.5 5.5 5.3 5.4 5.2 5.4 5.3 4.8 5.3 5.1 5.2 63.1SBXSOUR PC 0.0 0.0 0.0 30.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 30.0SBXSWEET D24 0.3 0.4 0.0 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 3.7SGRLF D24 24.3 24.7 24.3 23.1 23.5 22.3 22.7 22.4 19.9 21.7 20.7 21.1 270.6SGRLF PC 41.8 7.7 0.0 44.0 45.2 44.8 45.8 45.4 40.7 44.7 42.8 44.0 446.9TRAIL D24 588.6 591.6 215.5 543.8 548.7 519.1 524.8 513.8 454.8 493.8 469.0 475.9 5939.4TRAIL PC 1.7 1.7 0.0 1.7 1.7 1.7 1.7 1.7 1.5 1.7 1.6 1.7 18.4WHLA D24 58.9 60.3 59.8 57.3 58.7 56.3 57.7 57.2 51.2 56.2 53.9 55.2 682.5WHLA PC 11.8 2.2 0.0 12.4 12.5 12.4 12.7 12.5 11.2 12.3 11.8 12.1 123.7WWILSON D24 3.9 4.0 4.0 3.8 3.9 3.7 3.8 3.8 3.4 3.7 3.6 3.7 45.3WWILSON PC 22.1 4.1 0.0 23.4 24.1 23.9 24.5 24.3 21.9 24.0 23.1 23.8 239.2z13 CCRU D24 166.7 163.5 155.8 144.1 142.7 132.7 132.1 127.5 111.3 119.4 112.0 112.4 1620.3z13 MESA D24 272.8 248.3 1081.1 1102.3 2285.8 2331.3 2666.3 2379.8 1960.1 2007.2 1815.2 1766.4 19916.6z13 TRAL D24 104.2 102.9 98.6 91.7 91.3 85.3 85.2 82.5 72.3 77.7 73.1 73.5 1038.3z14 MESA D24 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 428.6 348.1 314.8 1091.4
5756.2 5431.0 5310.9 6325.6 7565.4 7361.4 7779.7 7413.7 6439.4 7324.3 6828.1 6838.2 80373.9
Exhibit 9.91
Normal Case : Year 1Mdth : Reservoir
Storage Withdrawals Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 TotalChalk Creek 0.0 0.0 0.0 0.0 0.0 0.0 321.0 0.0 0.0 0.0 0.0 0.0 321.0Clay Bsn 935 0.0 0.0 0.0 47.6 5.1 0.0 2126.3 1710.1 0.0 0.0 0.0 0.0 3889.2Clay Bsn 988 29.0 0.0 1.6 0.0 0.0 0.0 1507.6 1209.6 438.8 0.0 245.5 144.2 3576.3Clay Bsn 997 45.1 43.3 28.9 61.4 0.0 0.0 1483.3 1112.5 135.9 0.0 5.2 0.0 2915.5Coalville 0.0 0.0 0.0 0.0 0.0 0.0 720.4 0.0 0.0 0.0 0.0 0.0 720.4Leroy 0.0 0.0 0.0 0.0 0.0 0.0 532.1 0.0 0.0 0.0 0.0 0.0 532.1
74.1 43.3 30.4 109.1 5.1 0.0 6690.7 4032.2 574.7 0.0 250.7 144.2 11954.4
Mdth : WellheadStorage Withdrawals Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 TotalSpot 0.0 0.0 0.0 0.0 90.1 4272.9 468.0 4923.9 6565.8 2913.6 2645.5 0.0 21879.7SpotKR_Opal 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1656.3 695.4 0.0 0.0 0.0 2351.7SpotKR_Gosh 0.0 0.0 0.0 0.0 93.2 0.0 1701.4 1701.4 1536.8 1701.4 0.0 0.0 6734.3SpotKR_Wecco 0.0 0.0 9.4 0.0 150.5 541.5 330.3 464.5 309.4 560.8 146.6 0.0 2512.9Spot‐2‐NPC 0.0 0.0 0.0 16.2 27.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 43.2Bfr‐contract 0.0 0.0 0.0 150.0 155.0 0.0 775.0 0.0 0.0 0.0 0.0 0.0 1080.0Purchase1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 17.3 0.0 0.0 0.0 17.3Purchase2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 40.0 0.0 0.0 0.0 40.0
0.0 0.0 9.4 166.2 515.8 4814.3 3274.7 8746.2 9164.6 5175.8 2792.0 0.0 34659.1
Mdth : ReservoirStorage Inject Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13 Jan‐14 Feb‐14 Mar‐14 Apr‐14 May‐14 TotalChalk Creek 0.0 0.0 0.0 98.2 222.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 321.0Clay Bsn 935 844.7 1052.0 976.6 654.3 28.3 0.0 0.0 0.0 0.0 0.0 0.0 296.3 3852.2Clay Bsn 988 687.5 661.6 599.9 539.4 489.9 0.0 0.0 0.0 0.0 0.0 245.5 740.6 3964.3Clay Bsn 997 684.9 663.8 605.6 537.9 209.8 0.0 0.0 0.0 0.0 0.0 5.2 740.6 3447.8Coalville 0.0 0.0 152.1 276.7 261.3 30.2 0.0 0.0 0.0 0.0 0.0 0.0 720.4Leroy 0.0 0.0 0.0 263.0 18.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 281.3Ryckman 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 209.6 361.2 570.7
2217.1 2377.4 2334.2 2369.5 1230.3 30.2 0.0 0.0 0.0 0.0 460.2 2138.6 13157.6
10-1
GENERAL IRP GUIDELINES/GOALS FOR GAS SUPPLY AND ENERGY EFFICIENCY RESOURCES
Questar Gas has compiled a list of general guidelines to help direct the daily decision-making processes of the Company with regard to gas supply and energy-efficiency resources. While some of these guidelines incorporate specific numeric targets from the SENDOUT modeling process this year, all are general and flexible in nature to accommodate the potential for variability in weather, markets and operating conditions. Many are similar to those of previous years and have evolved from years of operating experience. When substantial changes in operating and/or market conditions occur, the SENDOUT model is used to help reassess the appropriate mix of market resources. The guidelines for this year are as follows:
Approximately 80 million Dth of cost-of-service gas should be produced, recognizing
the uncertainties associated with demand, operating conditions, and gas well productivity.
Produce the categories of cost-of-service gas as determined this year in the modeling exercise as contained in Exhibits 9.83 and 9.84 also subject to demand, operating conditions, and gas well productivity.
Purchase a balanced portfolio of gas of approximately 35 million Dth.
Accommodate deviations from base case weather with purchased gas and the use of
existing storage, to the extent possible.
Continue to monitor and manage producer imbalances.
Override the SENDOUT model utilization profiles when producer imbalance considerations dictate.
Maintain flexibility in purchase decisions since actual conditions will vary from base
case conditions in the modeling simulation.
There is currently not a need for any additional price stabilization, but the Company should review this issue on an annual basis to determine whether such measures are appropriate in the future.
In Utah and Wyoming, continue to promote cost-effective energy efficiency
measures.