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A DAY IN THE LIFE OF A NATURAL GAS UTILITY
Wisconsin Public Utilities InstituteEnergy Utility Basics
Friday, October 5, 2012
Kenneth W. Yagelski
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About UGI
UGI Corporation (NYSE: UGI), through its subsidiaries, distributes and markets energy products and related services around the world
UGI Utilities distributes natural gas and provides electric service to customers in eastern, northeastern and central Pennsylvania.
UGI Energy Services markets natural gas, propane and electricity to commercial and industrial customers in nine states in the northeast U.S.
UGI Energy Services owns a variety of assets that support the storage, transportation and delivery of natural gas and electric generation assets in Pennsylvania.
UGI was founded in 1882, bringing 130 years of trusted energy-related experience to millions of customers
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Disclaimer
Numeric values are provided for illustrative purposes only and may not represent actual data associated with any specific company.
Processes and strategies are presented for educational and discussion purposes only and are not necessarily intended for implementation in this form.
Numeric values, processes and strategies are subject to change and may not represent the past, current or future plans for any specific company.
Materials represent the opinion of the presenter and not necessarily those of UGI Corporation or UGI Energy Services.
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Keeping The Pipes Full
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What Every Natural Gas Utility Wants
Reliable natural gas service Investor confidence Earnings growth strategy Accounting compliance (Sarbanes – Oxley, Dodd –
Frank) Cost recovery and regulatory approval Regulatory compliance (local and federal) Revenue protection through price management Efficient operation of the process and system
Daily responsibility to deliver on these objectives,
but a process that requires long-term planning.
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Demand Forecasting
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Determining Design Day Demand
Assess a group of days with the highest firm demand. Establish the firm demand base-use and then adjust
for forecasted meter growth or decline, and any known demand changes.
Use linear regression analysis to determine the weather-use per Heating Degree Day (“HDD”)1 and verify accuracy through a back-cast analysis.
Apply actual weather data to base and weather factors. Typically based on historical data representing the coldest
“recent” weather experienced. Example: The last 10, 20, 30 or more years… it depends. Cold weather is relative, depending upon the LDC’s location. In
the Midwest it can be an average daily temperature of 15 degrees below zero, while in the Mid-Atlantic it can be an average of 5 degrees.1 – Used to estimate energy required for heating. One HDD occurs for each
degree the daily mean temperature is below 65 degrees Fahrenheit.
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Forecasting Other Periods
Design Week Develops an understanding of peak demand period duration
and shape. Helps establish on-system and off-system peak shaving
requirements.
Normal Weather Winter Represents the typical demand expected during a normally
cold winter. Helps determine the appropriate mix of capacity resources.
Most Severe Weather Winter Represents the maximum demand expected during extremely
cold winter. Helps to make certain that there are sufficient capacity
resources to meet obligation to meet firm demand requirements.
Least Severe Weather Winter Represents the minimum demand expected during extremely
warm winter. Requires a plan for complete utilization of seasonal storage
inventory.
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Capacity Resource Planning
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Load Duration Curve
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101
105
109
113
117
121
125
129
133
137
141
145
149
Days of Winter (November through March)
Dem
and
(1,0
00 D
ekat
herm
s)
Total Capacity Most Severe Normal Least Severe
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Capacity Resource Portfolio
Combination of transportation, storage and peak shaving services capable of meeting forecasted design day demand, while economically serving normal demand.
Services selected with purposeful consideration of: Long haul versus market area transportation. Production area versus market area storage. Storage and peak shaving service inventory capacity.
Requires careful analysis of all applicable costs associated with holding contracts for capacity resources.
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Pipeline Transportation
Image: Energy Information Administration
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Pipeline Transportation
Image: Rextag
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Pipeline Transportation
Image: Rextag
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Natural Gas Pipeline System
The United States natural gas transmission capacity is about 150 billion cubic feet (“BCF”) per day (with some redundancy in capacity) About 71 percent are interstate pipelines (217,000 miles) About 29 percent are intrastate pipelines (89,000 miles)
National peak daily demand is approximately 120 BCF per day
National daily production capability is about 66 BCF per day
Daily net import / export is about 5 BCF per day Where does the remaining 49 BCF per day come
from?
Source: Energy Information Administration and Interstate Natural Gas Association of America
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Natural Gas Storage
Depleted Reservoir (326)Salt Cavern (31)Aquifer (43)Interstate PipelineIntrastate Pipeline
Image: Modified from Energy Information Administration
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Natural Gas Storage
Storage maintains reliability of gas supplies during periods of high demand (both winter and summer).
Storage allows more effective use of pipeline transportation while supporting operational load balancing.
Storage provides opportunities for Local Distribution Companies, marketers and producers to leverage economic opportunities.
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Capacity Moderating Factors
Physical realities moderate ideal plans. Capacity and pressure limits for interstate pipeline
system and the LDC’s distribution system. Capacity contract limitations reflect physical
constraints and operating requirements. Relationship between hourly and daily volume limits. Applicable costs associated with holding contracts for
capacity resources. Total Annual Cost Per Daily Volume.
Places all services on a comparable basis.
Total Annual Cost Per Annual Volume. Places similar services on a comparable basis.
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Capacity Cost Examples
Transportation 10,000 dekatherms per day of Firm Transportation for 365 days
at $10.00 per dekatherm Annual Cost per Daily Volume: $120.00 per dekatherm
Seasonal Storage 10,000 dekatherms per day of Delivered Firm Storage for 60
days with storage cost of $3.00 per dekatherm and transportation cost of $5.00 per dekatherm
Annual Cost per Daily Volume: $96.00 per dekatherm
Peak Shaving 10,000 dekatherms per day of Delivered Peak Shaving for 5
days at $18.00 per dekatherm Annual Cost per Daily Volume: $90.00 per dekatherm
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Load Duration Curve
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101
105
109
113
117
121
125
129
133
137
141
145
149
Days of Winter (November through March)
Dem
and
(1,0
00 D
ekat
herm
s)
Transportation Storage Peak Shaving Most Severe Normal Least Severe
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Capacity Resource Portfolio
(Volumes in Dekatherms)
2012 - 2013 2015 - 2016 2020 - 2021
Design Day Demand Estimate 1,836,000 1,966,000 2,095,000 Firm Transportation 636,000 632,000 632,000 Capacity Releases 0 (10,000) 0 Storage 634,000 717,000 717,000 Peak Shaving 662,000 752,000 757,000 Total Capacity 1,932,000 2,091,000 2,106,000 Reserve Margin 5.2% 6.4% 0.0%
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Commodity Planning
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Commodity Purchase Plan
Utilize a mix of various contract terms and volumes to most accurately meet the dynamic requirements of customer demand.
Provide a variety of pricing mechanisms to help manage retail costs and to mitigate wholesale price volatility.
Hedged Price: Base volume (long-term), Various (Fixed, Capped, etc.)
Seasonal Base: Base volume (mid-term), Various (Negotiated, Index, etc.)
Monthly Base: Base volume (short-term), First-of-Month Index Swing: Daily (very short-term), Gas Daily Index Spot: Daily (very short-term), RFP Negotiated
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Commodity Price Hedging
Use a variety of hedging price mechanisms to help manage retail costs and to mitigate wholesale price volatility.
Fixed Price: Commodity is set at a price that is locked for the period of the contract with no premium.
Capped Price: Commodity has a maximum ceiling price, but no minimum floor price; at a cost charged as an explicit premium.
Banded Price: Commodity has a maximum ceiling price and a minimum floor price; at a cost reflected in the minimum price. Also known as a costless-collar.
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Commodity Planning Results
10%
32%
32%
23%2% 1%
Weighted Average Cost of Gas
$ 3.71 - Base$ 3.84 - Hedged$ 2.84 - Storage$ 4.00 - Daily Swing$13.00 - City-Gate De-livered$ 5.35 - Peak Shaving
$ 3.74 - Weighted Average
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Commodity Source Diversity
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Value of Commodity Source Diversity
Increases supply reliability by reducing reliance on any one production area and avoiding loss of supply from single contingency transportation disruptions.
Allows a mix of index pricing points to help manage retail costs and wholesale price volatility.
Helps to manage counterparty risk by allowing several different wholesale commodity marketers to meet a variety of hedged price, seasonal base, monthly base, swing and spot requirements.
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Commodity Source Diversity - Example
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Commodity Source Diversity - Example NiSource – Columbia Gulf
Transmission Hartsville Compressor Station
Direct hit from an F5 tornado on February 6, 2008
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The Gas Day
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Gas Supply Schedule
Prior to 9:00 a.m. (Central Time) Study the weather forecast for the next day (i.e. On Monday,
look at Tuesday, or on Friday, look at Saturday, Sunday and Monday).
Forecast natural gas demand for the next day with schedule of actions to take should the day’s plan be long (warmer) or short (colder).
Determine at which city gate locations and how much volume of supply will be needed.
Determine where supply will be sourced from (i.e. Flowing, storage, or peak shaving, and which provider).
Negotiate purchases of supply with specific receipt and delivery points.
Notify pipeline transportation and storage providers of the intent to use their services within your contract arrangements with specific details.
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Planned Versus Actual
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Planned Versus Actual
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Gas Control - SCADA
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Natural Gas Safety
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Natural Gas Safety
MaterialChemical Formula
SpecificGravity Air=1
Ignition TempDeg. F in Air
Lower Expl. Limit (% gas)
Upper Expl.Limit (% gas)
Methane CH4 .55 1193 5.3 15.0
Natural Gas Blend .65 950-1200 5.0 15.0
Ethane C2H6 1.04 993-1101 3.0 12.5
Propane C3H8 1.56 957-1090 2.2 9.5
Butane C4H10 2.01 912-1056 1.9 8.5
Hexane C6H14 3.0 437 1.1 7.5
Gasoline Blend 3-4.0 632 1.4 7.6
Acetone C3H6O 2.0 869 2.5 12.8
Benzene C6H6 2.8 928 1.2 7.8
Carbon Monoxide CO 1.0 1128 12.5 74.0
Hydrogen H2 .1 932 4.0 75.0
Hydrogen Sulfide H2S 1.2 500 4.0 44.0
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CFR Title 49 § 192.5 – Class Locations
(1) A Class 1 location is:
(i) An offshore area; or
(ii) Any class location unit that has 10 or fewer buildings intended for human occupancy.
(2) A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy.
(3) A Class 3 location is:
(i) Any class location unit that has 46 or more buildings intended for human occupancy; or
(ii) An area where the pipeline lies within 100 yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need not be consecutive.)
(4) A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent.
Source: Electronic Code of Federal Regulations
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CFR Title 49 § 192.706 – Leak Surveys
Leakage surveys of a transmission line must be conducted at intervals not exceeding 15 months, but at least once each calendar year. However, in the case of a transmission line which transports gas in conformity with §192.625 without an odor or odorant, leakage surveys using leak detector equipment must be conducted —
(a) In Class 3 locations, at intervals not exceeding 7 ½ months, but at least twice each calendar year; and
(b) In Class 4 locations, at intervals not exceeding 4 ½ months, but at least four times each calendar year.
Source: Electronic Code of Federal Regulations
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CFR Title 49 § 192.723 – Leak Surveys
(a) Each operator of a distribution system shall conduct periodic leakage surveys in accordance with this section.
(b) The type and scope of the leakage control program must be determined by the nature of the operations and the local conditions, but it must meet the following minimum requirements:
(1) A leakage survey with leak detector equipment must be conducted in business districts, including tests of the atmosphere in gas, electric, telephone, sewer, and water system manholes, at cracks in pavement and sidewalks, and at other locations providing an opportunity for finding gas leaks, at intervals not exceeding 15 months, but at least once each calendar year.
(2) A leakage survey with leak detector equipment must be conducted outside business districts as frequently as necessary, but at least once every 5 calendar years at intervals not exceeding 63 months. However, for cathodically unprotected distribution lines subject to §192.465(e) on which electrical surveys for corrosion are impractical, a leakage survey must be conducted at least once every 3 calendar years at intervals not exceeding 39 months.
Source: Electronic Code of Federal Regulations
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GPRTC Standards
Grade 1 Leak represents an existing or probable hazard to persons or property, and requires immediate repair or continuous action until the conditions are no longer hazardous.
1. Any leak which, in the judgment of operating personnel at the scene, is regarded as an immediate hazard.
2. Escaping gas that has ignited.
3. Any indication of gas which has migrated into or under a building, or into a tunnel.
4. Any reading at the outside wall of a building, or where gas would likely migrate to an out-side wall of a building.
5. Any reading of 80% LEL, or greater, in a confined space.
6. Any reading of 80% LEL, or greater in small substructures (other than gas associated sub structures) from which gas would likely migrate to the outside wall of a building.
7. Any leak that can be seen, heard, or felt, and which is in a location that may endanger the general public or property.
Source: Gas Piping Technology Committee: ANSI ASC Z380
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GPRTC Standards
Grade 2 Leak is recognized as being non-hazardous at the time of detection, but justifies scheduled repair based on probable future hazard.
A. Leaks Requiring Action Ahead of Ground Freezing or Other Adverse Changes in Venting Conditions. Any leak which, under frozen or other adverse soil conditions, would likely migrate to the outside wall of a building.
B. Leaks Requiring Action Within Six Months1. Any reading of 40% LEL, or greater, under a sidewalk in a wall-to-wall
paved area that does not qualify as a Grade 1 leak.
2. Any reading of 100% LEL, or greater, under a street in a wall-to-wall paved area that has significant gas migration and does not qualify as a Grade 1 leak.
3. Any reading less than 80% LEL in small substructures (other than gas associated substructures) from which gas would likely migrate creating a probable future hazard.
4. Any reading between 20% LEL and 80% LEL in a con-fined space.
5. Any reading on a pipeline operating at 30 percent SMYS, or greater, in a class 3 or 4 location, which does not qualify as a Grade 1 leak.
6. Any reading of 80% LEL, or greater, in gas associated sub-structures.
7. Any leak which, in the judgment of operating personnel at the scene, is of sufficient magnitude to justify scheduled repair.
Source: Gas Piping Technology Committee: ANSI ASC Z380
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GPRTC Standards
Grade 3 Leak is non-hazardous at the time of detection and can be reasonably expected to remain non-hazardous.
1. Any reading of less than 80% LEL in small gas associated substructures.
2. Any reading under a street in areas without wall-to-wall paving where it is unlikely the gas could migrate to the out-side wall of a building.
3. Any reading of less than 20% LEL in a confined space.
Source: Gas Piping Technology Committee: ANSI ASC Z380
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For more information please contact:
Ken YagelskiManager Midstream ServicesUGI Energy [email protected]
