Summer 2020 Customer Presentation - Northern Natural Gas
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Summer 2020 Customer Presentation
Topics
• Business Update
• Growing to Meet Market Demand
• System Enhancements
• Winter Recap
• Modernization Update
1
BHE Pipeline Group Post Closing
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
-Permanent Partners-
• Mutually beneficial relationships based on our core principles, not quarter over quarter profits
• Perform necessary due diligence, but maintain an attitude of partnership
• No surprises either way
• Frank, candid discussions
• Seek balanced outcomes
Why Six Core Principles and the focus on Permanent Partnerships? Sustainability
3
Customer Service
• Northern ranked first in the “Mega” and “Major”
pipeline categories for the 11th consecutive
year
• Northern ranked second among all interstate
pipelines in the 2019 Mastio & Company
annual survey, with Kern River Gas
Transmission, Northern’s pipeline affiliate,
placing first
• Northern scored highest in the following areas
1. Firm transportation is highly reliable
2. Scheduled gas volumes are accurate
3. Representatives are accessible
4. Accuracy of gas metering systems
5. Accurate operational information is
readily available
• What must we do now to earn a “10” later this
year?
− “10” = 1st place
− “9” = 4th place
− “8” = bottom quartile
− “7” = dead last
4
Regulatory Update
Rate Case Summary
• Background
– While managing through significant commercial issues and deploying enormous amounts of capital, Northern
had not had to change rates to recover these costs since 2004
• A tremendous accomplishment over 15 years, when rate base increased by over 120% ($1.6b) and
Northern invested $1.2 billion in maintenance capital in excess of its depreciation expense during that time
– Northern knew in 2018 that we could support a rate increase in 2019, but made a management decision to
leave rates stable for another year
• FERC Initiated Section 5
– FERC issued an order in January 2019 requiring a Section 5 rate review as a result of Northern’s Form 501-G
docket
– FERC based this review on an erroneous return calculation of 17.3% while Northern’s return on equity for 2018
was actually 13.5%, which is in the range of reasonable ROEs
– Northern’s efforts to correct the mistake, terminate the Section 5 action and keep rates flat until 2021 were
rejected
• As a result, Northern was forced to take a defensive strategy and file for a Section 4 rate increase on July 1, 2019
– While the FERC eventually conceded the error in its analysis, FERC chose to proceed with both the Section 5
and Section 4 proceedings simultaneously, ultimately resulting in a settlement with a 28.5% rate increase
beginning January 1, 2020, one year earlier than necessary
5
Rate Case Settlement Details
Service Rates
New
Rates
6
Rate Case Settlement Details
Service Rates Continued
• Onshore transmission depreciation rate increased from 1.5% to 2.30%
– Changes to depreciation rates result in a $51.3 million increase in annual cost of service based on the
year end 2019 plant balance
• Rolled-in rate treatment is agreed upon for all 7(c) projects completed through December 31, 2019, including
the Northern Lights projects and West Leg project confirming that the projects benefit the system
• Market-based storage service rolled into FDD rates
• Transportation commodity rates designed using the straight-fixed variable rate design
– Single rate eliminates the previous minimum and maximum rates
• Mileage based firm commodity rates will be retained for Field Area transportation and will be stated as $0.0078
per 100 miles
Other Tariff Changes
• Under-Recovery Retainage (URR) is implemented as a PRA mechanism for the annual cycle of under-
recovery in the Redfield and Lyons storage fields
– URR Percentage will be applied to FDD injection quantities
– Following implementation of URR, cumulative balance of URR customer supplied gas will be recorded in
annual filings and will be offset first by any annual over-recovery until such balance is netted to zero
– Pre-URR under-recovered cumulative balance will be resolved by over-recoveries only when customer
supplied URR balance has been resolved to zero
• Minor Technical Conference Items
• All other proposed changes were withdrawn or moved to the tariff working group
7
Rate Case Settlement Details
Other Settlement Items
• Moratorium through June 30, 2022 subject to certain conditions
• Tariff Working Group
– Carlton Flow Order
• Customer initiated to explore possible alternatives to current flow order
– Daily system management
• Identified by Northern to address current operational risks to market deliveries and system reliability by ensuring shippers have
the proper incentives to provide the supply needed to meet their markets
• Large SMS and tolerance levels
• Scheduling penalties inadequate based on supply price volatility
Future Considerations
• Given the significant modernization spending that will be required over the next several years, a rate case in
2022 is likely
– Is it any wonder Northern prefers to conduct business on a commercial rather than regulatory basis?
8
2019 Market Area Expansions: Completed
• Northern Lights 2019
– 138,000 Dth/day (Peak winter MDQ)
– In service: November 1, 2019
– Capital: $200 million
– Details on the next slide
• West Leg 2019 Expansion
– 12,000 Dth/day (Peak winter MDQ)
– In service: November 1, 2019
– Capital: $14 million
– Looping of three existing branch lines, minor modifications of two existing compressor stations,
branch line tie-over, modifications to six TBS’s, and abandonment of 8 miles of existing pipe
• Marquette, Michigan Branch Line Expansion
– 25,000 Dth/day (Peak winter MDQ)
– In service: November 2019
– Capital: $31 million
– New mainline compression, new TBS’s, existing branch line modifications
9Northern Lights 2019
• 138,000 Dth/day (Peak winter MDQ)
• In service: November 1, 2019
• Capital: $200 million
• Facilities
‒ Owatonna 2 Compressor
‒ Faribault 3 Compressor
‒ Carver Compressor (Willmar Branchline)
‒ Willmar Branch Line Loop
• 3.1-mile, 24-inch-diameter loop
‒ Alexandria Branch Line Extension
• 4.3-mile, 8-inch-diameter extension
‒ New Prague Branch Line Loop
• 1.6-mile, 6-inch-diameter loop
‒ Rockford-to-Buffalo Lateral
• 10.0-mile, 24-inch-diameter
greenfield lateral
‒ Modifications to 25 existing TBS’s in
Minnesota
‒ Modifications to three existing regulators in
Minnesota
102020 Market Area Expansions: Under Construction
• New Lisbon Branch Line Expansion for 2020
– 15,180 Dth/day (Peak winter MDQ)
– In service: November 1, 2020
– Capital: $31.3m
– Looping of one existing branch line, new branch line regulator, upgrade of existing branch
line compression, one new measurement station, and modifications to 13 existing
measurement stations
• LaCrosse/Tomah Branch Line Expansion for 2020
– 9,845 Dth/day (Peak winter MDQ)
– In service: November 1, 2020
– Capital: $14.2m
– Looping of one existing branch line, modifications to four existing measurement stations
and extension of existing mainline to be constructed at a later date prior to November 1,
2023
112020 New Lisbon Branch Line Expansion
• 15,180 Dth/day (Peak winter MDQ)
• In service: November 1, 2020
• Capital: $31.3m
• Facilities
‒ Looping of one segment of New
Lisbon
‒ Existing branch line compression
upgrade
‒ New branch line regulation
‒ Modifications to 13 existing TBS’s in
Wisconsin
122020 LaCrosse/Tomah Branch Line Expansion
• 9,845 Dth/day (Peak winter MDQ)
• In service: November 1, 2020
• Capital: $14.2m
• Facilities
‒ Looping of the Tomah branch line
‒ Modifications to 4 existing TBS’s in
Wisconsin
‒ One new TBS in Wisconsin
‒ Looping of existing mainline in
Minnesota
• Delayed until 2023; project
will utilize interim mainline
capacity until then
13Upcoming and Potential Market Area Expansions
• Northern Lights 2021
– See next slide
• West Leg Expansion
– Based on customer interest
– Open season closed June 26, 2020
– Northern is currently working with customers to determine final project size and scope
14Northern Lights 2021
• 45,693 Dth/day (Peak winter MDQ)
• In service: November 1, 2021
• Capital: $78.2m
• Facilities
‒ New mainline compressor near Hinckley,
Minnesota
‒ Looping of one existing mainline near Carlton,
Minnesota
‒ Existing mainline compression upgrades at
Farmington and Hugo compressor stations
‒ Existing branch line compression upgrade at
Pierz compressor station
‒ Looping of the Willmar branch line
‒ Upgrade of one existing branch line regulator
near Elk River, Minnesota
‒ Modifications to 26 existing TBS’s in
Minnesota
15Field Area Expansions
• Recently In-Service:
– 2018 Expansion
• 200,000 Dth/day
• In service: May 1, 2018
• $28.0m
– Gulf Coast Express Pipeline Spraberry Interconnect
• 332,000 Dth/day, receipt to Northern
• In service: August, 2018
• $0.3m
– Gulf Coast Express Pipeline Waha Interconnect
• 100,000 Dth/day, delivery from Northern
• In service: December, 2019
• $1.3m
– Agua Blanca Pipeline Interconnect
• 250,000 Dth/day, bi-directional location
• In service: September, 2019
• $1.6m
16Field Area Expansions
• Recently In-Service (continued):
– Trans-Pecos Lateral Expansion and Interconnect
• 500,000 Dth/d lateral capacity
• 250,000 Dth/d interconnect capacity, bi-directional location
• In service: December, 2019
• Approximately $7.0m
• Under Construction:
– Permian Highway Pipeline, Waha Interconnect
• 100,000 Dth/day, delivery to Permian Highway
• In service: forecasted as late 2020 to early 2021
• Approximately $1.7m
17Permian Area Development
• The tightening of spreads has had a negative impact on the
value of Northern’s transportation services compared to
2019
• Multiple Permian area pipeline projects in various stages of
development have softened demand for additional expansion
of Northern’s system and have negatively impacted the value
of Northern’s transportation services
• Gulf Coast Express Pipeline, a 430 mile, 2.0 Bcf/day
pipeline, came online in late 2019
• The Permian Highway Pipeline Project, a 430 mile,
2.0 Bcf/day pipeline, is expected to come online in
late 2020 or early 2021
• The Whistler Pipeline Project, a 475 mile, 2.0 Bcf/day
pipeline, is expected to come online in late 2021
• Remaining pipelines on the map are in various stages
of development
• The collapse of crude oil prices has caused significant
reductions in capital budgets of producer companies in the
Permian basin, resulting in a reduction in the anticipated
growth of associated natural gas
• This balancing of supply with takeaway capacity has had a
tremendous impact on the Permian forward prices and in
turn has caused a tightening of the Permian to Demarc
spread
• A positive aspect of the new Waha take-away pipelines is
that they will provide new markets for Northern shippers;
Northern has multiple interconnection projects in progress
that will enhance its services at Waha
18Scheduling System Update
• The Throughput Management System (TMS) is used to nominate, confirm and schedule transportation and
storage
• TMS Nomination Rewrite Project:
– Start Date: February 2016
– Completion date: December 2019
– Customer Rollout: August 2020
– Cost: Approximately $16 million
• Basic functionality is similar to the previous version with the following enhancements
– Web-based application; no longer need to use Citrix software to access TMS
– Ability to view cuts as they occur during the scheduling process for all seven nomination cycles
– Screens offer more dynamic grid features (e.g., column filtering, drag and drop grouping)
– Better visibility of EDI transactions, including detail and status
• Northern has provided several training options for a successful transition, including:
– WebEx training sessions
– TMS Testing Environment
– Training videos
– User Manual
19Capacity Release System Update
• Recent enhancements to Northern’s Capacity Release System implemented May 12, 2020 include:
– For capacity release bids, a customer may elect to accept available points assigned by Northern for any
quantity at any delivery points identified within the offer, instead of having to select each point and
related quantities
– For capacity release offers and associated recalls/reputs, the receipt and delivery point volumes will
appear for each eligible point on the initial Point Quantities screen to help customers determine which
quantities to release. Previously, totals were displayed after the points had been selected
– For recallable releases, the releasing shipper’s contract number has been added to the Recall Notice
email
20Winter 2019-2020 Review
• After two colder than normal winters in which nine of ten months were significantly colder than
normal, last winter returned to more normal temperatures
• Northern recorded its third highest Market Area delivery day this past winter
– On February 13, 2020, the Market Area delivery was 5.37 Bcf
– This was also the monthly record for February
• Despite normal temperatures, 39 days of the 2019-2020 heating season had Market Area deliveries
over 4.0 Bcf
– While significantly less than the 50 recorded the previous winter, this was still four more 4.0+
Bcf days than in the winter of 2017-2018
• Market Area deliveries for the 2019-2020 heating season averaged 3.62 Bcf compared to 3.70 Bcf
for 2018-2019, representing a 2.2% decrease.
• Not surprisingly, there were only 26 Carlton days and 17 SOL days, less than half of what we had in
2018-2019 heating season
System Weighted Temp vs Normal
14-15 15-16 16-17 17-18 18-19 19-20
November 40% 14% 24% 8% 31% 20%
December 8% 17% 8% 8% 8% 5%
January 2% 1% 7% 14% 8% 6%
February 29% 3% 16% 14% 25% 4%
March 3% 19% 7% 12% 22% 7%
Heating Season 9% 10% 6% 9% 13% 0%
21Asset Modernization Update
• Northern is continuing with its long-term plan to retire and replace facilities based on age and
dated technology in order to manage risk and continue to provide unparalleled reliability and
resiliency
– $393.1 million has been spent to date
• Remaining estimated cost for this work is $1.4 billion
– $214.7 million in modernization to be spent in 2020
– $501.1 million in total maintenance capital in 2020
• Projects include
– Pipeline Assessment
– Compression Replacement
– LNG equipment replacement
– Underground storage integrity
– Vintage pipeline replacement
22Pipeline Assessment
Northern Natural Gas is executing projects to increase the portion of the system that is in-line
inspection capable.
End of year percentages for pipelines 16-inch-diameter or greater
• 2018 – 41% (actual)
• 2019 – 47% (actual)
• 2020 – 53%
• 2030 – 97%
23Compression Modernization
Northern Natural Gas is executing projects to replace vintage compression units throughout the
system. It is prioritizing unit replacements based on vintage, criticality to pipeline operations,
historical reliability and outlook for future maintainability.
Completed and Planned Projects
• 2016 Beatrice Solar Mars 100 (Unit 28) replaces LM1500 (Unit 27)
• 2019 Mullinville Solar Mars 100 (Unit 27) replaces LM1500 (Unit 26)
• 2020 Bushton Solar Mars 100 (Unit 33) replaces LM1500 (Unit 32, the last LM1500 on the system)
• 2021 Ogden Solar Centaur 40s (Units 19 & 20) replace Cooper Bessemer Type 26 (Units 9-12, last horizontal engines)
• 2022 Paullina Replace Units 1-5, Ingersoll Rand KVG engines
• 2023 Garner Solar Taurus replaces existing motor driven refrigeration compressor
• 2024 Spraberry Replace Units 8-10, Ingersoll Rand KVG engines
• 2025 Brownfield Solar Mars 100 replaces GE Frame 3
24Compression Modernization
Mullinville Old LM 1500 Mullinville New Solar Mars 100
• Parts no longer supported • Modular design
• Failure results in extended outage • Repair completion within days
25LNG Equipment Modernization
Northern Natural Gas is executing projects to replace LNG equipment that is reaching the end of its
useful life at Wrenshall, Minnesota, and Garner, IA, LNG plants.
Major Projects 2021-2029
• Garner MCC Power Distribution
• Garner Cold Box Replacement
• Garner LNG Refrigeration Compressor/Motor Replacement
• Wrenshall Vaporizer Replacements
26Underground Storage Integrity
Northern Natural Gas is installing new observation and withdrawal wells to ensure reservoir integrity
at its underground natural gas storage fields. The company is also executing projects to assess
storage facility equipment integrity and address concerns. This is a requirement of the American
Petroleum Institute’s Recommended Practice 1171, Functional Integrity of Natural Gas Storage in
Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs, which is incorporated by reference in the
Interim Final Rule effective in 2018.
Major Projects 2021-2029
• Observation well installations
• Production well replacements
• Gathering line assessments
27Vintage Pipeline Replacement
Northern Natural Gas is executing projects to replace mechanically coupled and acetylene-welded
mainlines and branch lines exceeding 12-inch-diameter, and installing new facilities to replace the
associated capacity.
28Pandemic Response
Northern is requiring pandemic protocols and preventative plans from all third-party contractors and
subcontractors working during the pandemic.
The plans include:
• Preventive measures for virus transmission
– Improved social distancing (additional work trailers)
– Personal hygiene
– Symptom screening (daily temperature screening)
– Increased disinfecting practices
• Plans to work around lodging or road/travel restrictions
• Return-to-service plans to if construction activities are interrupted
29Emissions Reductions
• BHE Pipeline Group is part of Our Nation’s
Energy Future (ONE Future)
– Emissions target for 2025 of less than
1.0% of throughput from natural gas
production through distribution
– Average methane emissions in the
transmission and storage sector is
currently at 0.26%
– BHE Pipeline Group 2019 results:
0.04%
– BHE Pipeline Group’s transmission
pipelines have significantly reduced
and avoided releases of methane, thus
reducing greenhouse gas emissions,
enhancing pipeline integrity, making
operations safer, and reducing costs
for customers through reductions in
lost gas
– Practical methods used
• Stopple/Bypass to maintain
service and eliminate emissions
• Flare rather than vent
• Reduce line pressure prior to
flaring
• Recompress LNG boil-off
30Questions?
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