2015 Winter Forum
Milwaukee, Wisconsin
September 24, 2015
Tom Halpin
Vice President
Marketing
Berkshire Hathaway Energy
• 11.5 million customers
worldwide
• 21,000 employees worldwide
• $82.3 billion of assets
• $17.3 billion of revenue
• 32,600 miles of transmission
lines
• 16,400 miles of natural gas
pipeline
• More than 33,000 MW of
owned and contracted
generation capacity
• 33% of owned and
contracted generation
capacity is renewable or
noncarbon
2
Customer Commitment
Vision Statement
• To be the preferred provider of natural gas transportation and storage services based on our
integrity, operational excellence, financial strength and environmental responsibility
Mission Statement
• We are in business to serve our customers. Fairly. Efficiently. Reliably.
These statements mean that
• You will get what we promise on time
• We will share the purpose behind our actions
• We will commit to making it easy to do business with us
• We will negotiate and perform in good faith
• We will continue to invest in the pipeline in order to provide you highly reliable service and to
meet your future growth needs
3
Core Principles
Employee
Customer
Commitment
Regulatory
Integrity
Service
BALANCED OUTCOMES
Operational
Environmental
Respect
Financial
Strength
4
Excellence
Permanent Partners
The attitude of permanent partnership impacts our relationship
with our customers
•
Long after all of us in this room are retired, our companies will still be business partners
What does this mean?
•
Mutually beneficial relationships based on our
core principles, not quarter over quarter profits
•
Do necessary due-diligence, but maintain an
attitude of partnership
•
No surprises either way
•
Frank, candid discussions
•
Seek balanced outcomes
5
Northern’s Preferred Approach to Business Issues
•
Consistent with our Core Principles and our view of customers as Permanent Partners,
Northern’s preferred approach to business issues includes:
– A belief that business decisions are best handled through business discussion with
commercial counterparts
– Candid evaluation of the issue
– A desire for active engagement of the customer in the issue
– Solicitation of candid feedback in both directions
– Transparency – information, rationale, communication
•
This means:
– Out of respect for our customers, we try to get to a balanced outcome quickly and with
minimal iterations
– We prefer not to employ the used car salesman approach with lots of smoke and a wide
bid/offer
6
Mastio Results
Northern and Kern River ranked in the Top
2 of 41 pipelines.
Northern ranked first in the following
areas:
1. Value received for money paid
2. Flexibility of gas pooling and
aggregation services
3. Financial stability
4. Accuracy of gas metering systems
What must we do now to earn a “10”
later this year?
7
Customer Satisfaction Rankings
No issue is worth jeopardizing our credibility and the goodwill Northern and its customers have built
over the last several years
8
Addressing Future Capital Costs
•
By the end of 2015, Northern will have invested over $625 million in non-revenue generating
capital in excess of the depreciation expenses in rates since the last rate case in 2004
•
Northern has more than $1.6 billion of investment for maintenance capital and modernization in
the next 10 years
– This level of investment is necessary to maintain the high level of reliability that Northern
and its customers expect and deserve
•
Northern appreciates customers’ consideration of alternatives. Based on the feedback received,
Northern is preparing for rate cases in 2017 and 2018
•
Northern seeks to have an open dialogue with customers in preparation for the rate cases and is
willing to have discussions with individuals or groups of customers at any time
•
Northern is also seeking any specific service changes customers would like to see in a rate case
9
Rate Case Timeline
2017 and 2018 Rate Case Timeline
10
Gas/Electric Market Coordination Update
•
Recall from last year:
•
Proposals to start the gas day at 4 a.m., 6 a.m., 7 a.m., or leave it alone
•
Single Energy Day or East/West Energy Days
•
Three, four or 24 intraday cycles
11
Final Outcome – Reason Prevailed
On April 16, 2015, the Federal Energy Regulatory Commission issued a
final order concerning the Coordination of the Scheduling Processes of
Interstate Natural Gas Pipelines and Public Utilities. Highlights of the
final order are:
• No change to the start of the gas day, retaining the 9:00 a.m. Central
Clock Time (CCT) start time
• Adoption of the NAESB nomination schedules, which included
moving the nomination deadline for the timely cycle from 11:30 a.m.
to 1 p.m. CCT and the addition of another intraday cycle
• Multi-party transportation contracts
• Implementation deadline of April 1, 2016
• FERC Findings:
• Limited evidence that the 9:00 a.m. start time results in
natural gas-fired generators de-rating during the morning
ramp due to exhausting nominated natural gas transportation
• Not clear that Benefits>Costs
• It is a regional issue
• Potential employee safety risk
• Increased cost and lack of adequate resources available for
system changes
12
Meeting Market Expansion Needs
• Northern works with its customers to provide effective services and processes to meet firm service
needs
• Increased natural gas demand generally requires pipeline construction, which is subject to FERC
regulation and approval by appropriate government agencies
• FERC has granted blanket authority for projects up to the following levels
– Automatic Blanket – up to $11.4 million; may not be used for mainline expansions
– Prior-Notice Filing – more than $11.4 million up to $32.4 million; agency approvals can
range from 30 days to six months, while authorization generally occurs within 60-70 days
• Projects costing more than $32.4 million require Section 7 application – Six months prior to filing
the Section 7 application, a request to use FERC’s pre-filing process is filed. Authorization from
FERC may take six to eight months from the Section 7 application filing
• FERC should consider the following project approval improvements
– Expand scope of the blanket authorizations to include mainline facilities, MAOP increases
– Increase the cost-limit for blanket authorizations
– Identify measures to shorten review time for Section 7 applications
– Initiate consultation with agencies that typically will not formally consult on blanket projects
without FERC’s formal initiation
13
Northern Expansions Since 2007
Market since
2007
•
Northern has invested approximately $489
million, and added approximately 957,000
Dth/day of incremental capacity to meet
customer demand in its Market Area
•
Northern has invested approximately $80
million in its Field Area
956,622 Dth/Day
− Field Area supply interconnects have
been expanded resulting in
approximately 1.475 Bcf/day of
incremental capacity
$489 million
Storage since 2007
8,000,000 Dth/Day
− Northern has also expanded its Permian
area to provide approximately 510,000
Dth/day of incremental capacity
$52 million
•
Northern has invested approximately $52
million to expand its storage capacity by 8
Bcf/day
Field since 2007
1,985,000 Dth/Day
$80 million
14
Recently Completed Expansions
•
Permian Area Expansion I
– Open season held November 22, 2013 through January 9, 2014
– 158,000 Dth/day total incremental capacity
– In-service November 1, 2014
•
St. Cloud Branch Line Expansion
– Open season was held from January 14, 2014 through January 31, 2014
– 8,781 Dth/day
– In-service November 1, 2014
•
Mason City Branch Line Expansion
– Open season was held from January 29, 2014 through February 18, 2014
– 1,905 Dth/day
– In-service November 1, 2014
•
West Leg 2014 Expansion
– Open season was held from October 18, 2012 through November 7, 2012
– 88,430 Dth/day
– In-service November 1, 2014
15
West Leg 2014 Expansion
Facility Requirements:
•
Homer, Nebraska greenfield
compressor station (9,500-HP)
•
Fremont, Nebraska compressor
station (4,700-HP)
•
1.17-mile extension of 24-inch
line
•
5.51 miles of 20-inch greenfield
branch line
•
0.38-mile 20-inch tie-over line
•
Meter station
16
Market Update – West Leg 2014 Expansion
• The Homer compressor station was the last facility to be placed in-service November 26, 2014
• The two compressor stations were completed within 1% and 3% of the final project forecast
• Northern effectively managed a number of schedule delays – specifically a 1-month delay in the
FERC approval process and record rainfall that more than doubled historic averages
• In addition to providing 88,430 Dth/day of incremental capacity, this project will increase the
reliability and operational flexibility of Northern’s current system
17
West Leg 2014 Expansion − Facilities
18
Current Expansions
•
Zone EF 2014-2016 Expansion – Northern Lights
– Open season was held March 19, 2014 through May 1, 2014
– 64,813 Dth/day (Peak winter MDQ)
– Construction in progress
•
West Leg 2015/Zone ABC 2014-15 Expansions
– Open seasons were held between June 2, 2014 and August 8, 2014
– 65,100 Dth/day (Peak winter MDQ)
• West Leg: 31,550 Dth/day
• Zone ABC: 33,550 Dth/day
– Regulatory approval for West Leg 2015 project in May 2015
– Construction in progress
•
Willmar Branch Line Expansion
– Open season was held October 14, 2014 through October 21, 2014
– 1,856 Dth/day (Peak Winter MDQ)
– Construction in progress
19
Current Expansions (cont.)
•
Permian Area Expansion II
– Open season held September 4, 2014 through September 30, 2014
– 112,000 Dth/day
– Construction in progress
•
Permian Area Expansion IIA
– Open season held November 12, 2014 through December 12, 2014
– 30,000 Dth/day
– Construction in progress
•
Permian III Expansion
– Open season held January 26, 2015 through February 2, 2015
– 210,000 Dth/day
– Construction in progress
20
Zone EF Expansion 2014-2016
Capital Expenditure: $16.5 million
Facility Requirements
•
2014 Projects
–
Dooley’s #3 (new station)
–
Galesville TBS Mods
–
Montevideo TBS Mods
–
•
•
LaCrosse/Tomah Mods
• Plainview MN TBS Mods
• Coon Valley #2 TBS Mods
2015 Projects
–
Willmar 24-inch D-line Loop
–
Willmar 12-inch C-line Loop Extension
–
North Branch Header Mods
–
St Paul 1T TBS Upgrade
–
St Cloud TBS Mods
–
Forest Lake 1A TBS Mods
–
Stacy TBS Mods
–
Minneapolis 1R TBS Rebuild
–
Anoka TBS Upgrade
–
Blaine 1A TBS Mods
–
St Michael TBS Upgrade
–
St Bonifacius TBS Rebuild
–
Sartell TBS Regulator Mods
Associated Operation’s Projects
–
Marshall MN TBS Mods (2014)
–
Forest Lake TBS Mods (2015)
21
West Leg 2015 Expansion
Capital Expenditure: $17.8 million
Facility Requirements:
•
Willow Lake, South Dakota
greenfield compressor station
(1,590-HP)
•
Hazel, South Dakota interconnect
•
Paullina compressor station
modifications
•
TBS modifications:
–
–
–
–
–
–
–
Ida Grove
Baltic
Dell Rapids
Beresford
Elk Point
Vermillion
Rock Valley
22
West Leg 2015 Expansion - Facilities
23
Supply Additions to Northern’s Field Area
• Shale development is supportive of gas
demand due to low supply prices
• Northern continues to expand access to
additional unconventional supply from the
Granite Wash tight sands and Wolfberry
shale plays
• Incremental supplies of 1,775,000 Dth/day
are being attached from Granite Wash tight
sands and Wolfberry shale plays
24
Northern Supply Options
25
Winter 2014-2015: More Records, Less Mayhem
•
No Polar Vortex, no Parade of Clippers, no external chaos, just strong loads without all of the
fuss of early 2014
•
A smattering of statistics
– Three of the top five and six of the top ten market area peak loads occurred during Winter
2014/2015 despite it being significantly less cold than the year before
– Northern set new Market Area peak daily delivery records for the months of November,
December, February and March
– On January 7, 2015, Northern achieved its second highest peak Market Area delivery of
5.097 Bcf
– In February 2015, Northern set an all time average monthly throughput record averaging
4.083 Bcf/day
– First ever 4 Bcf delivery day in the month of November
November
December
January
February
March
Heating Season
10-11
3%
8%
5%
6%
9%
5%
11-12
12%
16%
16%
12%
47%
19%
Warmer than Normal
Colder than Normal
26
12-13
4%
6%
1%
6%
29%
4%
13-14
15%
21%
21%
33%
30%
24%
14-15
40%
8%
2%
29%
3%
9%
Winter Operations Review
Northern Natural Gas 2014-2015 Heating Season
Market Load
Actual System Temperature
6.000
Normal System Temperature
60
50
5.000
4.000
30
3.000
20
10
2.000
0
1.000
-10
0.000
-20
27
System Temperature (F)
Market Load (Bcf)
40
Misconceptions about Flow Limitations
•
SOLs and Critical Days are used to maintain system integrity and protect shippers by helping to
ensure the system is in balance (receipts equal deliveries)
•
SOLs and Critical Days do not in any way limit interruptible or alternate firm utilization
•
Allocations may occur that limit flows to delivery locations
HOWEVER,
•
Northern does not allocate primary firm receipt to primary firm delivery nominations except in a
force majeure or curtailment event
•
Capacity allocations can occur at a specific point or at a group level:
– Allocate specific receipt or delivery points – alternate firm and interruptible nominations,
along with primary firm nominations, are in excess of Northern’s physical capacity
• Only the shipper’s nomination type (primary, alternate or interruptible) at the point is
considered (e.g., during a receipts point allocation only the nominated receipts are
reviewed for priority without consideration to the downstream path or delivery point
associated with that nomination)
– Allocate group – nominated transportation activity exceeds the available physical pipeline
capacity entering or exiting a defined group of points
• Allocation groups have been created to minimize the impact of an allocation so that only
the smallest area is affected
28
Allocation History
•
In most cases, allocation impacts to deliveries in the Market Area are the result of mainline group
constraints (Oakland, Farmington North, for example) and not branch-line or delivery point
constraints.
– When mainline constraints occur, shippers can normally find alternate receipt points that are
not subject to the mainline group constraints to serve loads
ALLOCATION HISTORY
Mainline
Path
Delivery
Point
Zone Level
Delivery
Branch Line
Delivery
Summer 2010
62
0
0
0
Winter 2010-11
1
0
0
0
Summer 2011
0
0
0
0
Winter 2011-12
0
0
0
0
Summer 2012
0
0
0
0
Winter 2012-13
0
20
0
0
Summer 2013
0
1
0
0
Winter 2013-14
45
0
4
18
Summer 2014
0
0
0
0
Winter 2014-15
17
0
0
0
Season
- Delivery point allocations in Winter 2012-13 were primarily at Viking interconnects
- Branch-line delivery allocations in Winter 2013-14 all occurred on the St. Cloud branch line
- Table does not include points where interruptible flows are managed directly by the point operator
29
Royce Ramsay
Vice President
Operations
Gas Quality, Fuel Management and Project Updates
31
Btu Trends
32
Btu Trends (cont.)
•
Generally, heating content has increased due to higher ethane and propane content, not
because of an increase in heavier hydrocarbons
– Producers are finding it more profitable to sell the Btu’s in the gas stream than to strip
out the heavier hydrocarbons for sale to plastics and refinery operations
•
Because ethane (C2) and propane (C3) are lighter hydrocarbon molecules, the higher heating
content resulting from the increased presence of these components does not mean an
increased risk of hydrocarbon liquids problems
•
There may be some impact to delivery customers, typically with engines/compressors
– Typically, very few engines are derated
– Most equipment can be adjusted for the higher BTU gas and still maintain normal
operations
•
Gas control monitors generic high and high-high alarm values of 1075 and 1100 BTU/scf for
most of the system
33
Btu Trends (cont.)
•
Northern also uses specific limits on alarm set points for some receipts when the gas
composition and operating history warrant it
•
Northern monitors C6+ content (heavy hydrocarbons) and cricondentherm values
(hydrocarbon dewpoint) for possible liquids drop-out
•
Great Lakes receipts at Carlton, Minnesota have given Northern gas the last two winters that
contained heavier hydrocarbons, which did result in hydrocarbon condensates forming in
some farm taps and large pressure cut stations. It also caused process problems at the
Wrenshall LNG facility
•
Northern is continuously monitoring the gas quality from Great Lakes, modifying regulators,
adding heaters, and adding process equipment at Wrenshall to mitigate the impact of this gas
on the system
•
C6+ values below 0.10% or a cricondentherm hydrocarbon dewpoint (CHDP) below 0
degrees are considered dry with a low probability of condensate dropout
34
Btu Trends (cont.)
35
Btu Trends (cont.)
36
Btu Trends (cont.)
37
Fuel Management
•
Over the last ten years, Northern has implemented changes to its system that have resulted in
over 4 Bcf of fuel savings
•
This benefit accrues directly to the customer through the annual PRA filing resulting in lower
fuel rates for customers
Northern Natural Gas Historical Fuel Savings
Year
Annual Fuel Savings (Dth)
2005
184,084
2006
1,295,160
2007
705,719
2008
347,488
Sale of Gathering Assets
2009
421,324
2010
262,931
2011
158,855
2012
248,770
2013
229,266
2014
287,607
38
Methods to Achieve Fuel Savings
•
Maintaining strict compressor unit fuel efficiency
– Daily operational checks
– Unit analysis and condition monitoring
– Prompt maintenance if unit fuel efficiency declines
– Extensive annual unit maintenance
– Annual turbine inspections/maintenance
– Robust overhaul program
•
Seasonal and situational system optimization
– Utilizing Field Operating Guidelines
– System monitoring to make situational changes for fuel savings
• During outages
• During low flow conditions
• While optimizing high pressure interconnects
• For seasonal adjustments in customer pressure guarantees
– Idling facilities when not required
– Managing compressor unit start/stop
– Selecting the most efficient unit if a choice exists
– Minimizing unit/station recycling of gas
39
Methods to Achieve Fuel Savings (cont.)
•
Implementing Fuel Savings Projects
– Station automation
– Unit automation
– High pressure fuel injection systems
– Centrifugal compressor re-wheels
• Brownfield
• Seminole
• Ventura
• Owatonna
– Improving measurement facilities
40
In-Line-Inspection Tool Launch on the Palmyra to
Oakland B Pipeline
41
Receiving Marquette 20-Inch-Diameter Inspection Tool
42
In-line Inspection Tool
43
Caliper-MFL Tool
Sensors
Caliper arms
Odometer
Cup
Hardware
Magnets
44
In-line Inspection Tools
•
Caliper Tools – Multi sensor caliper with orientation representation will normally be used to
assess dents.
•
MFL – High-resolution Magnetic Flux Leakage tools will normally be used to conduct wall loss
assessments for external and internal corrosion. It is an accurate tool for determining size and
geometry of wall loss. A caliper tool will be run prior to or in conjunction with an MFL tool.
•
Crack Detection Tools – These tools will be used to assess manufacturing threats due to long
seam cracks, long seam selective corrosion or other longitudinally oriented defects.
– Rosen – Axial Flaw Detection (AFD)
– Baker-Hughes – Transverse Flaw Indicator (TFI)
•
Multi-axis MFL – These tools use MFL technology with sensor arrays arranged in more than
one plane with respect to the pipeline flow and are able to assess crack-like defects associated
with manufacturing and construction defects.
– TDW – Spiral MFL (SMFL)
– Baker-Hughes – Triaxial tool
•
EMAT – Electromagnetic Acoustic Transducer tools in a gas medium will be considered to
assess threats due to small crack-like defects including stress corrosion cracking and seam cracks.
45
In-line Inspection Processes
Nov/Dec:
Engineering
sends list of
projects with
due dates to
facility planning
Run cleaning tools
(foam pigs, gauge
plates)
Once “acceptance” of
the results is reached,
the vendor has 30 days
to prepare the
preliminary report on
the results
Feb/Mar:
Engineering
and
procurement
work with
vendors to
determine tool
availability
Dec/Jan:
Facility planning
works with gas
control, field
operations and
customer service
to determine
optimal timing
Mar-Dec:
Complete
in-line
inspections
Run in-line
inspection tool(s)
The vendor has up to
seven (7) days to
determine whether
the tool run was
successful or not
If not, Northern
may have to excavate
and repair the
restriction(s) before
the tool can be rerun
Northern reviews the
preliminary report for
three types of anomalies
and promptly
investigates any
identified conditions
Meanwhile, the
vendor completes the
final report, which is
due 60 days after
acceptance
Northern reviews the
additional details of the
final report and
remediates any
additional significant
anomalies
Based on the results of the final report,
Northern then picks the location(s) for
verification dig(s) to confirm the tool
results were accurate. Due within 180
days first assessment or 1 year for
reassessment
Northern establishes a
new reassessment date
and adds the project to
the forecast database
(UI Planner)
46
Mole Sieve Vessel Refurbishment Garner, Iowa
47
LNG Off-Load Facilities at Garner, Iowa
48
49
Vickie Wonder
Senior Director
Customer Service Operations
Customer Service Operations
•
Goal of customer service operations is to:
•
– Provide industry-leading service
– Respond diligently and promptly to customer needs and requests
– No surprises
Each customer is assigned a customer service representative
•
Each team supports and backs up each customer service representative on the team
•
Customer service operations assist customers with nomination, scheduling, confirmation and
billing issues
•
Nomination/Scheduling
•
– Review nomination reconciliation screen in TMS every cycle
– Review timely submission of EDI files
– Assisting new shippers in the nomination process
Confirmation
– Review operator confirmations before close of each cycle every day
– Review new nomination confirmations after the timely cycle each day
51
Customer Service Operations (cont.)
•
Billing
–
–
–
–
•
Invoices are 99.9% accurate (non-measurement)
Review measurement volumes before close and discuss any discrepancies with customers
Review invoices and discuss any discrepancies with customers before the end of the month
Assist customers with imbalance resolution elections
Customer Service Tools
– Reliable system applications (99.93% reliability year to date)
‒ Pop-up nomination communications
• Nomination advisories
• System advisories
– Communicate changing business conditions
•
Daily Highlights (emailed by 5 a.m., 7 days a week)
•
Critical and non-critical notices are posted on website and emailed to customers
requesting such emails
52
Customer Service Enhancements
•
•
•
•
April 2015 ‒ Customer Security Administrators
– Northern strives to maintain secure proprietary software applications and data. As part of
these efforts, Northern is partnering with customers to ensure the appropriate individuals
have access to company records maintained on Northern’s system applications.
• Request each customer to designate two individuals to act as security administrators
• Security administrators’ duties include granting, updating and deleting access to
Northern’s proprietary applications
June 2015 ‒ Interactive Operational Capacity Map implemented
September 2015 ‒ Notification Administration System implemented
– This system allows customers and other interested parties to sign up to receive, via email,
selected proprietary information, critical and non-critical notices and other customer
communications that are posted to Northern’s website. The application will provide
immediate notification of messages that may impact your business operations.
Throughput Management System (TMS) and Capacity Release System (CRS) application
enhancements
‒ In process − Improved system performance and reliability enhancements to be completed in
October
‒ In process − Modifications due to FERC Order 809 (Gas/Electric Coordination) to be
implemented evening of March 30, 2016, for Gas Day April 1, 2016
‒ In process − Modifications due to NAESB 3.0 Standards to be implemented evening of
March 30, 2016, for Gas Day April 1, 2016 (proposed)
53
Operationally Available Capacity Map
•
In June, Northern introduced an interactive pipeline map to geographically represent the
Operationally Available Capacity (OAC) for its Market and Field Areas
•
Northern expects possible uses of the information to include
− Point and group capacity availability
− Assessing risk associated with flows from alternate supply points to alternate markets
− Identifying available supply sources during periods of constraint in portions of
Northern’s system (e.g., Oakland Allocation Group)
54
Operationally Available Capacity Map − Group
Information found on the OAC page is identical to the information found on the map
55
Operationally Available Capacity Map − Point
56
Operationally Available Capacity Map − Location
•
At a Glance Page
o Thumbnails of both Market and Field Areas
o Link to the Operationally Available Capacity Map Overview
•
Capacity Tab
57
Notification Administration System
•
This system allows customers and other interested parties to sign up to receive, via email,
selected proprietary information, critical and non-critical notices and other customer
communications that are posted to Northern’s website
•
Enhancements
– Addition of emailing non-critical notices
– Ability to view and edit elections
58
Notification Administration System − Selection Screen
Non-Proprietary
Proprietary
59
Notification Administration System − Existing User Conversion
•
All existing customers currently receiving emails will be converted to the new application and
will continue to receive the same notices
•
If a customer wishes to change their elections they will need to logon through the appropriate site
(Authorized/Public) to manage their profile
– Authorized User (Northern issued User ID and Password)
– Public User (Email address)
•
If a user is currently receiving proprietary notices and wants to change their elections, but does
not have a Northern issued User ID, contact your customer service representative
60
Notification Administration System − Location
Access the Notification Administration System through Northern’s Support page
61
Recent Tariff Filing Applicable to Field Area
•
On September 2, 2015, Northern filed tariff revisions to Rate Schedule MPS to require the use of
transportation service agreements for transfers between pooling points and storage points instead of using
MPS agreements.
•
Northern’s proposal will have no impact on Northern’s pooling service. The proposed revisions do not
impact the ability of MPS customers to aggregate supplies at various pooling points.
•
Similar revisions accepted by Commission in 2006 and 2010
‒ Northern filed to remove Ventura storage from Ventura pool – Approved June 2006
‒ Northern filed to remove MID 17 Market Area storage from Market Area MID 17 Pool – Approved
August 2010
•
Primary drivers for Northern’s proposal to require transportation service agreements for transfers
between pooling points and storage points.
• Recent changes to shipper contracted entitlement in Northern’s Field Area
• Increased flows to markets spread across the Field Area
• More deliveries within the Field Area rather than simply deliveries from the Field Area to Demarc
•
The use of transportation service agreement for transfers between pooling points and storage points will
allow Northern to improve the tracking of transportation and storage volumes in a manner that more
closely matches the physical flow on the pipeline system.
•
This proposed change will allow Northern to better allocate capacity to the smallest affected area, thereby
limiting the impact of any potential allocation to the least number of shippers.
62
Recent Tariff Filing Applicable to Field Area (cont.)
63
Operational Decision Making
Northern is committed to calling SOL, SUL and Carlton resolution days only when necessary to ensure
system integrity and to minimize the impact to customers
Factors influencing SOL/SUL decisions :
Factors influencing Carlton resolution decisions:
– Load forecast
– Load forecast north of Farmington, Minnesota
– Temperature and wind forecasts
– Temperature and wind forecasts
– Shipper recent behavior – long/short
– Availability of operational capacity from the
Twin Cities north
– Storage deliverability
– LNG deliverability and inventory (SOL)
– Line pack levels
– Horsepower utilization and outages
– Timing
– Wrenshall LNG deliverability and inventory
– Baseload Carlton and Chisago receipts
– Horsepower utilization and outages
– Timing
64
SOL, SUL and Carlton – Northern’s Commitment
Northern’s goal is to balance between providing as much advance notice as possible to allow customers
to adjust their business during normal trading hours and using the latest available forecast to minimize
requirements
Weekday Guidelines
SOL, SUL:
Post information by 6 a.m. CST the day prior to the applicable gas day
Carlton Sourcing:
Post information by 9 a.m. CST two days prior to the applicable gas day
Weekend/Holiday Guidelines
SOL, SUL:
Maintain the posting information constant to minimize customer risk
regarding daily delivery variance charges (DDVCs)
Make every effort to maintain at least the allowable SMS percentages as
originally posted for the SOL days but may increase the availability of SMS if
system conditions allow
Carlton Sourcing:
Post all weekend requirements on Thursday afternoon (prior to weekend
trading)
Do not increase requirements during the weekend from those posted on Thursdays
If 100% requirement is posted, then reductions will not occur during the weekend
65
Allocations of Alternate Firm and IT
• Northern’s highest priority is to provide reliable primary firm transportation service for its shippers
• Northern does not allocate primary firm receipt to primary firm delivery nominations except in a
force majeure or curtailment event
• Northern is always reviewing the allocation process to determine if additional allocation groups are
needed in order to allocate the “smallest impacted area”
• Capacity allocations can occur at a specific point or at a group level
• Allocate specific receipt or delivery points – alternate firm and interruptible nominations, along
with primary firm nominations, are in excess of Northern’s physical capacity
‒ Only the shipper’s nomination type (primary, alternate or interruptible) at the point is
considered (e.g., during a receipt point allocation only the nominated receipts are reviewed
for priority without consideration to the downstream path or delivery point associated with
that nomination)
• Allocate group – nominated transportation activity exceeds the available physical pipeline capacity
entering or exiting a defined group of points
‒ Allocation groups have been created to minimize the impact of an allocation so that only the
smallest area is affected
• 31 Market Area allocation groups
• 26 Field Area allocation groups
66
Allocations of Alternate Firm and IT (cont.)
• Causes
– High utilization of alternate firm or interruptible points due to supply or market pricing
dynamics
– Planned service outages
– Force majeure event
• Communication Tools
– Non-critical notices are posted notifying shippers of potential allocation(s)
• Whenever possible, Northern will provide information of changing operational
conditions on the pipeline, with the exception of allocations that occur routinely or are
commonplace, such as at certain receipt point locations in the Market Area
– Operationally Available Capacity map and web page show capacity available at receipt and
delivery points, as well as for allocation groups, after each cycle
67
Allocation Modifications − Market Area
Effective November 1, 2015
•
Market Area Allocation Groups
– New groups
• Wakefield East (Group 1030)
• Marquette Area (Group 1031)
• Black River Falls BL (Group 1036)
• Ladysmith BL (Group 1037)
• Arcadia Line (Group 1039)
• Causes
– To allocate the smallest impacted area
– High utilization of alternate firm or interruptible points due to supply or market pricing
dynamics
68
Market Area Allocation Groups
Northern’s objective is to impact the least number of customers
Zone EF
Zone D
Zone ABC
69
New Market Area Allocation Groups
70
Market Area Group Allocation
•
Northern proactively develops allocation groups in order to protect the integrity of the pipeline
while impacting the smallest geographical area and number of shippers
•
Beginning on November 1, 2015, Northern will have 31 Market Area allocation groups
– 10 Central-mainline groups
– 8 Central-branch line groups
– 5 West Leg groups
– 5 East Leg groups
– 3 Market Area zone groups
•
Although unforeseen events may require Northern to allocate, the following slide indicates the
Market Area groups most likely to be allocated based on historical flows and current market
conditions
71
Potential of a Market Area Group Allocation Based
on Historical Flows and Current Market Conditions
Group #
832
812
811
750
835
583
581
775
1021
735
Central-Mainline
More
Likely
Beatrice North 1
Carlton North
Carlton South Receipt
Farmington North
North Branch
Oakland 1
Ogden North1
Palmyra East 1
Ventura North
Ventura South
Group #
West Leg
740
1019
809
751
866
Palmyra North
Paullina West
Welcome North
Welcome South Receipt
Worthington BL West
Zone #
Market Area Zones
Primary Cause
Alternate Receipts
Alternate Receipts
Alternate Receipts
Alternate Receipts
Alternate Receipts
Alternate Receipts
More
Likely
Primary Cause
Group #
1039
1036
1020
1037
1031
836
1030
1018
Group #
488
487
463
585
773
More
Likely
Primary Cause
454 Zone ABC
456 Zone D
453 Zone EF
1
Generally, Northern will allocate only one of these groups at a time
72
Central-Branch Line
More
Likely
Primary Cause
More
Likely
Primary Cause
Arcadia Line
Black River Falls BL
Carlton East
Ladysmith BL
Marquette Area
St. Cloud Branch Line
Wakefield East
Willmar Branch Line
East Leg
Belleville East
Earlville East
Galena East
Hubbard East
Waterloo East
Market Area Allocation Groups − More Likely to
Allocate
73
Allocation Modifications − Field Area
Effective November 1, 2015
•
Modified Field Area Allocation Groups
– Beaver C and Beaver System South (Group 177)
• Modified to only be a delivery allocation group
• Impacted area: Mainline deliveries to Field Area locations south of the Beaver,
Oklahoma, compressor station
– Beaver North (Group 1025)
• Created to mirror the Beaver C and Beaver System South Group
• Impacted area: Mainline deliveries to Field Area locations north of the Beaver,
Oklahoma, compressor station
– Brownfield South (Group 998)
• Modified to only be a delivery allocation group
• Impacted area: Mainline deliveries to Field Area locations south of the Brownfield,
Texas, compressor station
– Brownfield North (Group 1022)
• Created to mirror the Brownfield North Group
• Impacted area: Mainline deliveries to Field Area locations north of the Brownfield,
Texas, compressor station
74
Modified Field Area Allocation Group
75
Modified Field Area Allocation Group (cont.)
76
Allocation of Capacity Overview Page
From Northern’s homepage, click on the Support heading, then select the Allocation of Capacity tab
77
Contact Information
Customer Service and Business Development
Name
Miller, Kent
Gilbert, Steve
Halpin, Tom
Humann, Ben
Lavengood, Kirk
Wonder, Vickie
Title
Vice President, Customer Service &
Business Development
Director, Customer Service Administration
Vice President, Marketing
Director, Pricing and Storage
Vice President, Business Development
Sr. Director, Customer Service Operations
Phone
Email
(402) 398-7417
Kent.Miller@nngco.com
(402) 398-7176
(402) 398-7088
(402) 398-7299
(402) 398-7376
(402) 398-7725
Steve.Gilbert@nngco.com
Tom.Halpin@nngco.com
Ben.Humann@nngco.com
Kirk.Lavengood@nngco.com
Vickie.Wonder@nngco.com
Marketing
Name
Halpin, Tom
Title
Vice President, Marketing
Phone
(402) 398-7088
Email
Tom. Halpin@nngco.com
Eller, Craig
Lagerstrom, Karen
Nicks, Andi
Account Executive, Marketing
Account Executive, Marketing
Account Director, Marketing
(402) 398-7834
(402) 398-7508
(402) 398-7130
Craig.Eller@nngco.com
Karen.Lagerstrom@nngco.com
Andrea.Nicks@nngco.com
Oldenhuis, Frank
Rosman, Stacy
Account Director, Marketing
Account Director, Marketing
(402) 398-7486
(402) 398-7377
Frank.Oldenhuis@nngco.com
Stacy.Rosman@nngco.com
Rushton, Todd
Underwood, Mike
Account Executive, Marketing
Account Director, Marketing
(651) 456-1785
(651) 456-1780
Todd.Rushton@nngco.com
Mike.Underwood@nngco.com
78
Contact Information
Business Development
Name
Lavengood, Kirk
Barry, Mike
Bowers, Janet
Burleson, Bob
McCarran, Penny
Stage, Mike
Weller, Steve
Title
Vice President, Business Development
Account Director
Account Director
Account Director
Account Director
Sr. Director, Business Development
Account Director
Phone
(402) 398-7376
(402) 398-7105
(402) 398-7141
(713) 653-1808
(713) 653-1807
(713) 653-1804
(713) 653-1806
Email
Kirk.Lavengood@nngco.com
Mike.Barry@nngco.com
Janet.Bowers@nngco.com
Bob.Burleson@nngco.com
Penny.McCarran@nngco.com
Mike.Stage@nngco.com
Steve.Weller@nngco.com
Pricing and Storage
Name
Humann, Ben
Korbelik, Stephanie
Pritchard, John
Thomsen, Jason
Title
Director, Pricing and Storage
Account Director Storage
Account Executive
Sr. Account Manager
Phone
(402) 398-7299
(402) 398-7408
(402) 398-7383
(402) 398-7469
79
Email
Ben.Humann@nngco.com
Stephanie.Korbelik@nngco.com
John.Pritchard@nngco.com
Jason.Thomsen@nngco.com
Contact Information
Customer Service Administration
Name
Phone
Email
Gilbert, Steve
Kuehl, Toby
Weidner, James
Title
Director, Customer Service Administration
Web/Communications Manager
Manager, Contracts and Business Tech
(402) 398-7176
(402) 398-7577
(402) 398-7940
Steve.Gilbert@nngco.com
Toby.Kuehl@nngco.com
James.Weidner@nngco.com
Chamberlain, Connie
Kuehl, Cheryl
Lugo, Jolene
Wagner, Ladonna
Williams, Andy
Contract
Contract
Contract
Contract
Contract
(402) 398-7658
(402) 398-7970
(402) 398-7541
(402) 398-7639
(402) 398-7678
Connie.Chamberlain@nngco.com
Cheryl.Kuehl@nngco.com
Jolene.Lugo@nngco.com
Ladonna.Wagner@nngco.com
Andrew.Williams@nngco.com
Administration Representative
Administration Representative
Administration Representative
Administration Representative
Administration Representative
80
Contact Information
Customer Service Operations
Name
Wonder, Vickie
Bodnar, Mike
Cook, Greg
Hasenjager, Erik
Stein, Janie
Begley, Mark
Bowers, Matt
Click, Tony
Coe, Sue
Draeger, Karen
Greaney, Chris
Gregory, April
Holmes, Robert
Jensen, Jeff
Littlejohn, LaWanda
Milem, Keith
Perry, Chris
Porter, Sharon
Winckowski, Danielle
Zadow, Raetta
Zimmerman, Pam
Zimmerman, Sue
Title
Sr. Director, Customer Service Operations
Manager, Customer Service
Manager, Customer Service
Customer Service Advisor
Customer Service Coordinator
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
Customer Service Representative
81
Phone
(402) 398-7725
(402) 398-7544
(402) 398-7254
(402) 398-7873
(402) 398-7094
(402) 398-7709
(402) 398-7268
(402) 398-7133
(402) 398-7976
(402) 398-7493
(402) 398-7624
(402) 398-7300
(402) 398-7489
(402) 398-7050
(402) 398-7542
(402) 398-7629
(402) 398-7659
(402) 398-7787
(402) 398-7275
(402) 398-7816
(402) 398-7381
(402) 398-7179
Email
Vickie.Wonder@nngco.com
Michael.Bodnar@nngco.com
Greg.Cook@nngco.com
Erik.Hasenjager@nngco.com
Janie.Stein@nngco.com
Mark.Begley@nngco.com
Matthew.Bowers@nngco.com
Anthony.Click@nngco.com
Susan.Coe@nngco.com
Karen.Draeger@nngco.com
Chris.Greaney@nngco.com
April.Gregory@nngco.com
Robert.Holmes@nngco.com
Jeffrey.Jensen@nngco.com
Lawanda.Littlejohn@nngco.com
Keith.Milem@nngco.com
Christopher.Perry@nngco.com
Sharon.Porter@nngco.com
Danielle.Winckowski@nngco.com
Raetta.Zadow@nngco.com
Pam. Zimmerman@nngco.com
Susan.Zimmerman@nngco.com
Contact Information
Operations
Name
Ramsay, Royce
Floyd, Jodie
Evanoff, Julie
Randy, Janzen
Reinhardt, Rebecca
Title
Vice President, Operations
Director, Gas Control and Operations
Communication Center
Manager, Gas Control
Sr. Measurement Process Analyst
Sr. Facility Planner – Outage Coordination
82
Phone
(402) 398-7989
Email
Royce.Ramsay@nngco.com
(402) 398-7638
Jodie.Floyd@nngco.com
(402) 398-7982
(402) 398-7555
(402) 398-7862
Julie.Evanoff@nngco.com
Randy.Janzen@nngco.com
Rebecca.Reinhardt@nngco.com