20230109INT to Staff Attachment - Response to No. 28_2018-Annual-Report,-10-K-2019-Proxy.pdf

MDU Resources Group, Inc.1
MDU Resources Group, Inc.2
Forward-looking statements: This Annual Report contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are all statements other than statements of historic fact, including without limitation those statements that are identified by the words anticipates, estimates, expects, intends, plans, predicts and similar expressions. Forward-looking statements should be read with, and are subject to, the cautionary statements and important factors included in “Part I, Forward-Looking Statements” and “Item 1A — Risk Factors” of the company’s “2018 Form 10-K.”
Years ended December 31, 2018 2017
(In millions, where applicable)
Operating revenues $ 4,531.6 $4,443.4
Operating income $ 401.7 $ 424.1
Earnings on common stock from continuing operations $ 269.4 $ 284.2
Earnings on common stock, including discontinued operations $ 272.3 $ 280.4
Earnings per common share from continuing operations $ 1.38 $ 1.45
Earnings per common share, including discontinued operations $ 1.39 $ 1.43
Dividends declared per common share $ .795 $ .775
Weighted average common shares outstanding — diluted 196.1 195.7
Total assets $ 6,988 $ 6,335
Total equity $ 2,567 $ 2,429
Total debt $ 2,109 $ 1,715
Capitalization ratios:
Total equity 54.9% 58.6%
Total debt 45.1 41.4
100% 100%
Price/earnings from continuing operations ratio (12 months ended) 17.3x 18.5x
Book value per common share $ 13.09 $ 12.44
Market value as a percent of book value 182.1% 216.1%
11,797 10,140
Highlights
MDU Resources Group, Inc.3
Regulated Energy Delivery
Electric and Natural Gas Utilities
MDU Resources Group’s utility companies serve approximately 1.1 million customers. Cascade Natural Gas Corporation distributes natural gas in Oregon and Washington. Great Plains Natural Gas Co. distributes natural gas in western Minnesota and southeastern North Dakota. Intermountain Gas Company distributes natural gas in southern Idaho. Montana-Dakota Utilities Co. generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. These operations also supply related value-added services.
Note: The revenues and earnings noted on this page exclude discontinued operations, the Other category and intercompany eliminations.
Regulated Energy Delivery
Pipeline and Energy Services
WBI Energy provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems, primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides cathodic protection and other energy-related services.
2018 Key Statistics
Revenues (millions) $128.9
Earnings (millions) $28.5
Pipeline (MMdk) Transportation 351.5 Gathering 14.9
SD
MT
ID
WY
OR
ND MN
WA
Electric and natural gas utility areas
Electric generating stations
States of operations
SD
MT
WY
ND MN
Company storage fields
Midstream assets
States of operations
Pipeline systems
Interconnecting pipelines
NE
SD
MT
ID
HI
WY
UT
CA
OR
WA ND MN
IA
TX
AK States of operation
Market areas
NE
SD
MT
ID
HI
WY
COUTNV
CA
OR
WA
AZ NM
ND MN
IA
MO
AR
LA
TN
MS
NC
VAWVKY
IN OH PA NJ
ME
AL GA
FL
SC
IL
MIWI
KS
OK
TX
AK Construction services offices
Authorized states of operations for construction services
2018 Key Statistics
Revenues (millions) Electric $335.1 Natural gas $823.2
Earnings (millions) Electric $47.0 Natural gas $37.7
Electric retail sales (million kWh) 3,354.4
Natural gas distribution (MMdk) Sales 112.6 Transportation 149.5
2018 Key Statistics
Revenues (millions) $1,925.9
Earnings (millions) $92.6
Construction materials sales (thousands)
Aggregates (tons) 29,795
Asphalt (tons) 6,838
Ready-mix concrete (cubic yards) 3,518
Construction materials aggregate
reserves (billion tons) 1.0
2018 Key Statistics
Revenues (millions) $1,371.5
Earnings (millions) $64.3
Construction Materials and Services
Construction Materials and Contracting
Knife River Corporation mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mix concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services.
Construction Materials and Services
Construction Services
MDU Construction Services Group provides inside and outside specialty contracting services, including constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization. It also provides utility excavation and inside electrical and mechanical services, and manufactures and distributes transmission line construction equipment and supplies.
Our Businesses
MDU Resources Group, Inc.4
Our operations performed very
well in 2018, successfully
executing on growth projects
and managing costs while meeting
customers’ needs. We are pleased with
our strong results, which continue to
reflect the advantage of our two-pillar
strategy of growing our regulated energy
delivery businesses through organic
projects while growing our construction
materials and services market share
through strong customer relationships
and acquisitions.
Earnings in 2018 from continuing
operations were $269.4 million, or $1.38
per share, compared to 2017 earnings
from continuing operations of $284.2
million, or $1.45 per share. Including
discontinued operations, MDU Resources
reported 2018 earnings of $272.3 million,
or $1.39 per share, compared to $280.4
million, or $1.43 cents per share, in 2017.
The company recorded a benefit in 2017
of $39.5 million, or 20 cents per share,
attributable to the federal Tax Cuts and
Jobs Act. Absent the benefit from tax
reform, our earnings from continuing
operations were up 13 cents per share
year over year, or approximately 10
percent.
Our employees remain dedicated to
Building a Strong America,® providing
essential products and services to the
American people. We provide the natural
gas and electricity that power business,
industry and our daily lives. We connect
homes, factories, offices and stores with
the pipes and wires that bring them to
life. We build the transportation network
of roads, highways and airports that
keeps our economy moving. The heart of
our American economy is infrastructure,
and infrastructure is our business.
We expect 2019 to be another strong year,
starting off with a record backlog of
projects at both our construction
businesses, significant growth projects at
our natural gas pipeline company and
planned capital infrastructure
investments at our utility operations. We
expect to invest $579 million in capital
projects this year, with $2.6 billion in
planned investments over the next five
years. We are confident our company will
continue to provide the long-term returns
you expect.
Construction services
breaks records
The construction services business had
outstanding results in 2018, with record
revenues, earnings and backlog. Earnings
were $64.3 million, which is 21 percent
higher than earnings of $53.3 million in
2017. This is even more impressive when
you consider that 2017 results included a
$4.3 million benefit from tax reform. We
had record year-end backlog of $939
million, up 33 percent compared to $708
million in 2017.
We saw higher workloads and margins in
2018 in our outside specialty electrical
contracting work, particularly power line
and substation projects and recovery
work for utilities that were impacted by
weather events and natural disasters. We
also continued in 2018 to see strong
demand for sales and rentals of the utility
construction equipment we manufacture.
We have a high volume of inside specialty
electrical and mechanical contracting
work in our backlog, particularly for
customers in the high-tech,
manufacturing and hospitality industries.
Our strong execution on these types of
projects often gives us the opportunity
for repeat business from customers who
value our top-quality design and build
services.
We are the 11th largest specialty
contractor in the U.S., according to
Engineering News Record’s “2018 Top
600 Specialty Contractors” list, and we
have more than 5,500 skilled employees
working across 43 states for this business.
We are exploring acquisition
opportunities to further grow our market
share in construction services.
Construction materials
has record backlog
Our construction materials business
earned $92.6 million in 2018, compared
to $123.4 million in 2017. Earnings in
2017 included a $41.9 million benefit from
federal tax reform. Like our construction
services business, our construction
materials business ended the year with
record backlog. At December 31, backlog
was $706 million, a 45 percent increase
from the same time in 2017.
The geographic diversity of our operations
continues to be a benefit, as we saw strong
construction demand in some markets
but weaker demand in others, including
impacts from the recession in Alaska,
above-average precipitation in Texas and
weather in the Midwest. Our operations
in California are located near the area
impacted by a devastating 2018 fire.
While our facilities were spared, some of
our employees lost everything and we
continue assisting those impacted while
working with the communities on
restoration efforts.
We acquired four construction materials
operations in 2018. In April, we acquired
Teevin & Fischer Quarry LLC, a leading
aggregate producer serving customers in
the area of Clatsop County, Oregon. In
June, we acquired Tri-City Paving Inc., a
general contractor and aggregate, asphalt
and ready-mix concrete supplier
headquartered in Little Falls, Minnesota.
In July, we added Molalla Redi-Mix and
Rock Products Inc., a ready-mix concrete
producer in Molalla, Oregon, near
Portland. In October, we acquired
Sweetman Const. Co., a premier provider
of aggregates, asphalt and ready-mix
concrete in the Sioux Falls, South Dakota,
market. We expect to continue our
acquisition strategy this year.
We have strong momentum going into
2019 with our record backlog of projects,
and we continue to see strong bidding
opportunities in markets with robust
economies. With state and federal officials
Report to Stockholders
MDU Resources Group, Inc.5
focused on the growing need for
infrastructure repairs and replacements
across our country, we are well-positioned
with our more than 1 billion tons of
aggregate reserves to take on additional
work.
Pipeline transports
record volume
Our pipeline and midstream business
earned $28.5 million in 2018, compared to
$20.5 million in 2017. Results in 2018
included a $4.2 million tax benefit related
to a final accounting order by the Federal
Energy Regulatory Commission, and
results in 2017 included a $200,000
decrease related to federal tax reform.
Our pipeline business in 2018 transported
a record volume of natural gas for the
second year in a row, approximately 12
percent more than in 2017. This is partly
due to continuing to expand our pipeline
system through organic growth projects.
We completed in September our Line
Section 27 expansion in northwestern
North Dakota and in November our
Valley Expansion Project in eastern North
Dakota and far western Minnesota. These
projects increased our system capacity by
more than 240 million cubic feet per day,
bringing total capacity to more than 1.8
billion cubic feet per day.
We continue to see great need for natural
gas pipeline capacity in the Bakken region
as our customers face increasing flaring
restrictions while growing their natural
gas production to record volumes,
generally month over month. We will
begin construction this spring on two
additional expansion projects. The
Demicks Lake project will be constructed
in McKenzie County, North Dakota, and
will add approximately 175 million cubic
feet per day of capacity. Line Section 22 is
an expansion project near Billings,
Montana, adding approximately 22.5
million cubic feet per day of capacity. We
expect both projects to be complete late
this year.
We also recently announced the North
Bakken Expansion Project, which as
planned is a 67-mile, 20-inch pipeline that
will start at our existing compressor
station near Tioga, North Dakota, and end
at a new interconnection point with
Northern Border Pipeline in McKenzie
County. The project is designed to provide
200 million cubic feet per day of
additional natural gas capacity, but it can
be expanded to provide up to 375 million
cubic feet per day depending on customer
demand. Pending regulatory and
environmental approvals, we anticipate
constructing this project in 2021.
We are planning additional future projects
to help our customers capture and deliver
to market more Bakken natural gas, of
which at year-end approximately 20
percent was being flared, and we look
forward to telling you more about these
projects as they come to fruition.
We have a rate case pending before the
FERC, which our pipeline business filed
on October 31 in accordance with a
settlement agreement reached in 2014 with
customers and the FERC. The FERC has
set a procedural schedule for the case and
proposed rates will take effect May 1, 2019,
subject to refund and the outcome of a
hearing established in the case.
Utility customer base
continues to grow
Our electric and natural gas utility
business earned $84.7 million, compared
to $81.6 million in 2017. The 2017 results
include a decrease of $6.4 million from
federal tax reform. Our utility operations
filed rate adjustments in every jurisdiction
to return to customers the benefits of
lower federal income taxes. We have
implemented rates that provide
$25 million in annual reductions to our
customers.
Our utility customer base continued to
grow in 2018, up approximately 1.8
percent. We expect to see our 1.1 million
customer base continue to increase at a
rate of 1 to 2 percent each year. Electric
sales volumes in 2018 increased 1.4
percent while natural gas sales were
virtually unchanged from 2017.
We finalized in the fourth quarter our
purchase of an expansion of the Thunder
Spirit Wind farm in southwest North
Dakota for $84 million. The expansion
brought the total production capacity at
that wind farm to approximately 155
megawatts. Including our other wind farm
locations, our electric generation portfolio
is now approximately 27 percent
renewables.
In late 2018, we extended natural gas
service to a manufacturing facility at
Gwinner, North Dakota. As a result of this
system expansion, we recently announced
that we also will be extending natural gas
service to residential and business
David L. Goodin
President and Chief Executive Officer
Harry J. Pearce
Chair of the Board
MDU Resources Group, Inc.6
structure and already has resulted in
greater flexibility in financing options.
After 22 years serving as a director on
MDU Resources’ board, nearly 14 of them
as chair, Harry Pearce will not seek
re-election at this year’s Annual Meeting.
William McCracken also will not stand
for re-election, and Bart Holaday ended
his term with the board in May 2018. Each
of these directors reached the mandatory
retirement age, per our company bylaws.
We want to assure you that we have solid
succession plans in place to fill key
positions on the board. We added two
directors, Edward Ryan and David Sparby,
in the past year and have a third new
director candidate standing for election at
our Annual Meeting in May. This will help
ensure a smooth transition of leadership.
These new directors bring substantial
governance, merger-and-acquisition,
financial, regulated utility and
cybersecurity experience to the board, as
well as other important expertise.
The board remains committed to paying a
competitive dividend to shareholders and
will continue to focus on providing you
with the long-term returns you expect
from MDU Resources.
We, with all MDU Resources’
hardworking employees, look forward to
continuing to provide the essential energy
and construction products and services
that are Building a Strong America.®
Thank you for your continued investment
in our company.
Harry J. Pearce
Chair of the Board
David L. Goodin
President and Chief Executive Officer
February 22, 2019
customers in Gwinner and the nearby
town of Milnor, North Dakota.
On February 5, 2019, the Big Stone-South-
to-Ellendale 345-kilovolt transmission
line, which we constructed with a partner,
was put into service. We invested
approximately $130 million in this
Midcontinent Independent System
Operator-approved project, which runs
from Big Stone City, South Dakota, to
Ellendale, North Dakota.
We announced February 19, 2019, that we
plan to construct a new simple-cycle
electric generation facility and retire our
smaller, solely owned coal-fired electric
generation facilities. Our integrated
resource planning process indicates that
operating these aging coal-fired plants,
which were built in 1954 and 1958, is no
longer the least-cost option for electricity
for our customers. We anticipate closing
our Lewis & Clark Station at Sidney,
Montana, with a capacity of 44 MW,
around the end of 2020, and our Heskett 1
and 2 plants at Mandan, North Dakota,
with combined capacity of 100 MW,
around the end of 2021. Upon regulatory
approval, we expect to build an 88-MW
natural gas-fired peaking unit at our
existing Heskett Plant site in Mandan.
We continue to invest in upgrading and
expanding our electric and natural gas
utility systems to safely and reliably meet
customer demand, and we continue to
pursue cost recovery of these investments
through regulatory relief. We expect our
rate base in the next five years to continue
growing 5 percent annually on a
compound basis.
Sustainability
a strong focus
While we have been publishing a
sustainability report since 2008, our Board
of Directors is sharpening its focus on
sustainability-related efforts within the
corporation. We are adapting our
environmental, social and governance
reporting to follow the standards outlined
by the federal Sustainability Accounting
Standards Board or other industry
organizations for each of our companies’
industries. We expect it will take some
time to fully incorporate this effort across
our businesses, but we are committed to
providing additional ESG information to
our shareholders.
Related to ensuring our operations are
sustainable, we constantly evaluate and
mitigate potential risks. We have
emphasized cybersecurity measures in the
past several years to protect our internal
systems, proprietary data and customer
information from nefarious actors who
might seek to harm our company. We are
confident our cybersecurity efforts are
some of the best in the industry, and this
has been confirmed by third-party
experts. However, we know we can never
rest on our laurels because hackers are
always knocking at our virtual door.
Beyond cybersecurity, we also evaluate
and mitigate risks related to the physical
security of our assets. A good portion of
our business facilities are considered
“critical infrastructure” by federal and
state agencies because these facilities
provide customers with critical services,
such as electricity and natural gas, and
means of transportation. We work to
ensure these assets are protected from
potential physical breaches and damage,
and we have in place emergency response
plans to recover from any such disasters.
We completed at the start of 2019 a
holding company reorganization that
further delineates the separation between
our corporation and our utility
companies. Montana-Dakota Utilities Co.
and Great Plains Natural Gas Co. were
originally structured as divisions of MDU
Resources, per requirements of the Public
Utility Holding Company Act of 1935. The
Energy Policy Act of 2005 repealed the
PUHCA and allowed us to restructure
these companies as subsidiaries —
Montana-Dakota Utilities is now a
subsidiary of MDU Resources and Great
Plains Natural Gas is a division of
Montana-Dakota Utilities.
The reorganization clarifies our corporate
MDU Resources Group, Inc.7
Numbers indicate age and years of service ( ) on the MDU Resources Board of
Directors as of December 31, 2018.
Audit Committee
Dennis W. Johnson, ChairMark A. HellersteinEdward A. Ryan
David M. SparbyJohn K. Wilson
Compensation Committee
Thomas Everist, ChairKaren B. FaggWilliam E. McCrackenPatricia L. Moss
Nominating and Governance CommitteeKaren B. Fagg, ChairDennis W. JohnsonWilliam E. McCrackenPatricia L. MossEdward A. Ryan
Harry J. Pearce
76 (22)
Detroit, Michigan
Chair of MDU Resources Board of Directors
Retired, formerly chair of Hughes Electronics Corp., a subsidiary of
General Motors Corp., and former vice chair and director of GM; on the board of several
organizations.
Expertise: Multinational business management, leadership, finance, engineering and law.
David L. Goodin
57 (6)
Bismarck, North Dakota
President and Chief Executive Officer of MDU Resources
Formerly president and chief executive officer of Cascade
Natural Gas Corporation, Great
Plains Natural Gas Co., Intermountain Gas Company and Montana-Dakota Utilities Co.
Thomas Everist
69 (24)
Sioux Falls, South Dakota
President and chair of The Everist Co., formerly a construction materials company; a director of several corporations.
Expertise: Business management, construction and sand, gravel and aggregate production.
Karen B. Fagg
65 (14)
Billings, Montana
Retired, formerly vice president of DOWL HKM and formerly chair, chief executive officer and majority owner of HKM Engineering Inc.; on the board of several organizations.
Expertise: Engineering,
construction and business management.
Mark A. Hellerstein
66 (6)
Denver, Colorado
Retired, formerly chair, president and chief executive officer of St. Mary Land & Exploration Co.; a former director of Transocean Inc.
Expertise: Energy industry, business management, accounting and finance.
Patricia L. Moss
65 (16)
Bend, Oregon
Formerly vice chair, president
and chief executive officer of Cascade Bancorp and Bank of the Cascades; a director of First Interstate BancSystem Inc.
Expertise: Finance, banking,
business development and human resources.
William E. McCracken
76 (6)
Warren, New Jersey
Retired, formerly chair and chief executive officer of CA
Technologies; previously held
executive positions with IBM Corp.; on the board of several organizations; a former director of IKON Office Solutions Inc.
Expertise: Multinational business management, corporate governance, technology and cybersecurity.
David M. Sparby
64 (1)
Minneapolis, Minnesota
Formerly senior vice president
and group president, Revenue at Xcel Energy Inc. and president and chief executive officer of Northern States Power-Minnesota.
Expertise: Public utilities, business management, finance and law.
John K. Wilson
64 (16)
Omaha, Nebraska
Formerly president of Durham Resources LLC, a privately held financial management company, and formerly a director of a mutual fund; on the board of several organizations.
Expertise: Public utilities, accounting and finance.
Edward A. Ryan
65 (1)
Washington, D.C.
Formerly executive vice
president and general counsel of Marriott International.
Expertise: Leadership, corporate governance and law.
Dennis W. Johnson
69 (18)
Dickinson, North Dakota
Vice Chair of MDU Resources Board of Directors
Chair, president and chief
executive officer of TMI Corp., an architectural woodwork manufacturer; former president of the Dickinson City Commission; a former director of Federal Reserve Bank of Minneapolis.
Expertise: Business management, engineering and finance.
Board of Directors
Director ChangesA. Bart Holaday did not stand for re-election in 2018. His term as a director concluded May 8, 2018.
David M. Sparby was appointed to the Board of Directors on August 16, 2018.
Edward A. Ryan was appointed to the Board of Directors on November 15, 2018.
MDU Resources Group, Inc.8
Numbers indicate age and years of service ( ) as of December 31, 2018.
Other Corporate and Senior Company OfficersStephanie A. Barth, 46 (23)Vice President, Chief Accounting Officer and Controller of MDU Resources
David L. Goodin
57 (36)
President and Chief Executive Officer of MDU Resources
Serves on the company’s Board of Directors and as chair of the board of all major subsidiary companies; formerly president and chief executive officer of
Cascade Natural Gas
Corporation, Great Plains Natural Gas Co., Intermountain Gas Company and Montana-Dakota Utilities Co.
Trevor J. Hastings
45 (23)
President and Chief Executive Officer of WBI Holdings, Inc.
Formerly vice president of business development and operations support of Knife River Corporation.
Anne M. Jones
55 (37)
Vice President of Human Resources of MDU Resources
Formerly vice president of human resources, customer service and safety of Cascade
Natural Gas Corporation, Great Plains Natural Gas Co., Intermountain Gas Company and Montana-Dakota Utilities Co.
David C. Barney
63 (33)
President and Chief Executive Officer of Knife River Corporation
Formerly held executive and management positions with Knife River.
Nicole A. Kivisto
45 (24)
President and Chief Executive Officer of Cascade Natural Gas Corporation, Intermountain Gas Company and Montana-Dakota Utilities Co.
Formerly vice president of operations of Great Plains
Natural Gas Co. and
Montana-Dakota Utilities.
Daniel S. Kuntz
65 (15)
Vice President, General Counsel and Secretary of MDU Resources
Serves as general counsel and secretary of all major subsidiary companies; formerly associate general counsel and assistant secretary of MDU Resources.
Jason L. Vollmer
41 (14)
Vice President, Chief Financial Officer and Treasurer of MDU Resources
Formerly vice president, chief accounting officer and treasurer of MDU Resources.
Jeffrey S. Thiede
56 (15)
President and Chief Executive Officer of MDU Construction Services Group, Inc.
Formerly held executive and management positions with MDU Construction Services Group.
Peggy A. Link
52 (14)
Vice President and Chief Information Officer of MDU Resources
Formerly assistant vice president of technology and cybersecurity officer of MDU Resources.
Corporate Management
MDU Resources Group, Inc.9
Comparison of One-Year Total Stockholder Return
(as of December 31, 2018)
Comparison of Five-Year Total Stockholder Return (in dollars)
$100 invested December 31, 2013, in MDU Resources was worth $90.96 at year-end 2018.
2013 2014 2015 2016 2017 2018
MDU Resources Group, Inc. $100.00 $78.82 $63.86 $103.48 $99.53 $90.96
S&P 500 Index 100.00 113.69 115.26 129.05 157.22 150.33
New Peer Group 100.00 117.17 129.51 174.67 194.61 176.51
Old Peer Group 100.00 114.03 119.67 162.14 179.12 161.71
Comparison of 10-Year Total Stockholder Return (in dollars)
$100 invested December 31, 2008, in MDU Resources was worth $149.65 at year-end 2018.
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
MDU Resources Group, Inc. $100.00 $112.89 $100.09 $109.25 $111.51 $164.53 $129.67 $105.06 $170.25 $163.76 $149.65
S&P 500 Index 100.00 126.46 145.51 148.59 172.37 228.19 259.43 263.02 294.48 358.77 343.04
New Peer Group 100.00 100.04 107.41 115.00 132.56 161.51 189.24 209.17 282.10 314.31 285.08
Old Peer Group 100.00 104.86 112.65 116.17 131.75 161.29 183.93 193.01 261.52 288.91 260.83
0
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New Peer Group
S&P 500 Index
MDU Resources Group, Inc.
20132012201120102009
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$250
S&P 500 Index New Peer GroupMDU Resources
’18’17’16’15’14’13
Old Peer Group
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100
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300 Old Peer Group
New Peer Group
S&P 500
MDU Resources
20142013201220112010200920082007200620052004
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’18’17’16’15’14’13’12’11’10’09’08
New Peer Group Old Peer GroupS&P 500 IndexMDU Resources
Old PeerS&P 500MDU New Peer
Stockholder Return Comparison
An explanation of the peer group is provided on the following page.
MDU Resources Group, Inc.10
Data is indexed to December 31, 2017, for
the one-year total stockholder return
comparison, December 31, 2013, for the
five-year total stockholder return
comparison and December 31, 2008, for the
10-year total stockholder return comparison
for MDU Resources, the S&P 500 and the
peer groups. Total stockholder return is
calculated using the December 31 price for
each year. It is assumed that all dividends
are reinvested in stock at the frequency
paid, and the returns of each component
peer issuer of the group are weighted
according to the issuer’s stock market
capitalization at the beginning of the
period.
Effective January 1, 2018, a new peer group
was established. This change was made to
better reflect the makeup of the company
relative to each business segment’s size and
nature of business. The charts show
stockholder return performance for both
the old and new peer groups.
The new peer group issuers are ALLETE,
Inc., Alliant Energy Corporation, Atmos
Energy Corporation, Black Hills
Corporation, EMCOR Group, Inc., Granite
Construction Incorporated, IDACORP, Inc.,
Martin Marietta Materials, Inc., MasTec,
Inc., MYR Group Inc., Northwest Natural
Holding Company (formerly Northwest
Natural Gas Company), NorthWestern
Corporation, Otter Tail Corporation,
Portland General Electric Company, Spire
Inc., Southwest Gas Holding, Inc., Summit
Materials, Inc., U.S. Concrete, Inc., Vectren
Corporation and Vulcan Materials
Company.
The old peer group issuers were ALLETE,
Inc., Alliant Energy Corporation, Atmos
Energy Corporation, Avista Corporation,
Black Hills Corporation, EMCOR Group,
Inc., Granite Construction Incorporated,
IDACORP, Inc., IES Holdings, Inc., Martin
Marietta Materials, Inc., MYR Group Inc.,
National Fuel Gas Company, Northwest
Natural Gas Company, NorthWestern
Corporation, Quanta Services, Inc., Sterling
Construction Company, Inc., U.S. Concrete,
Inc., Vectren Corporation and Vulcan
Materials Company.
Stockholder Return Comparison
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________ to ______________
Commission file number 1-03480
MDU RESOURCES GROUP, INC.
(Exact name of registrant as specified in its charter)
Delaware 30-1133956
(State or other jurisdiction ofincorporation or organization)(I.R.S. Employer Identification No.)
1200 West Century Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
[phone]
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock, par value $1.00 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes ý No o.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to
Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was
required to submit such files). Yes ý No o.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and
"emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer ý Accelerated filer o
Non-accelerated filer o Smaller reporting company o
Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with
any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý.
State the aggregate market value of the voting common stock held by nonaffiliates of the registrant as of June 29, 2018: $5,621,805,532.
Indicate the number of shares outstanding of the registrant's common stock, as of February 14, 2019: 196,092,274 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Relevant portions of the registrant's 2019 Proxy Statement, to be filed no later than 120 days from December 31, 2018, are incorporated by
reference in Part III, Items 10, 11, 12, 13 and 14 of this Report.
Part I
Forward-Looking Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6
Items 1 and 2 Business and Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6
General. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6
Electric. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8
Natural Gas Distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12
Pipeline and Midstream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14
Construction Materials and Contracting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15
Construction Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18
Item 1A Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20
Item 1B Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .28
Item 3 Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .28
Item 4 Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .28
Part II
Item 5 Market for the Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . .29
Item 6 Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30
Item 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32
Item 7A Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . .53
Item 8 Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55
Item 9 Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .114
Item 9A Controls and Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .114
Item 9B Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .114
Part III
Item 10 Directors, Executive Officers and Corporate Governance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .115
Item 11 Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .115
Item 12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .115
Item 13 Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . .115
Item 14 Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .115
Part IV
Item 15 Exhibits, Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .116
Item 16 Form 10-K Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .120
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .124
Contents
2 MDU Resources Group, Inc. Form 10-K
The following abbreviations and acronyms used in this Form 10-K are defined below:
Abbreviation or Acronym
AFUDC Allowance for funds used during construction
Army Corps U.S. Army Corps of Engineers
ASC FASB Accounting Standards Codification
ASU FASB Accounting Standards Update
Audit Committee Audit Committee of the board of directors of the Company
Bcf Billion cubic feet
Big Stone Station 475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent
ownership)
Brazilian Transmission Lines Company's former investment in companies owning three electric transmission lines in Brazil
BSSE 345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota
Btu British thermal unit
Calumet Calumet Specialty Products Partners, L.P.
Cascade Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
Centennial Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial's Consolidated EBITDA Centennial's consolidated net income from continuing operations plus the related interest
expense, taxes, depreciation, depletion, amortization of intangibles and any non-cash charge
relating to asset impairment for the preceding 12-month period
Centennial Resources Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
CERCLA Comprehensive Environmental Response, Compensation and Liability Act
Clean Air Act Federal Clean Air Act
Clean Water Act Federal Clean Water Act
Company MDU Resources Group, Inc. (formerly known as MDUR Newco), which, as the context requires,
refers to the previous MDU Resources Group, Inc. prior to January 1, 2019, and the new holding
company of the same name after January 1, 2019
Coyote Creek Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station 427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
CyROC Cyber Risk Oversight Committee
Dakota Prairie Refinery 20,000-barrel-per-day diesel topping plant built by Dakota Prairie Refining in southwestern
North Dakota
Dakota Prairie Refining Dakota Prairie Refining, LLC, a limited liability company previously owned by WBI Energy and
Calumet (previously included in the Company's refining segment)
D.C. Circuit Court United States Court of Appeals for the District of Columbia Circuit
dk Decatherm
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act
EBITDA Earnings before interest, taxes, depreciation, depletion and amortization
EIN Employer Identification Number
EPA United States Environmental Protection Agency
ERISA Employee Retirement Income Security Act of 1974
ESA Endangered Species Act
Exchange Act Securities Exchange Act of 1934, as amended
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Fidelity Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings
(previously referred to as the Company's exploration and production segment)
FIP Funding improvement plan
GAAP Accounting principles generally accepted in the United States of America
GHG Greenhouse gas
Great Plains Great Plains Natural Gas Co., a public utility division of the Company prior to the closing of the
Holding Company Reorganization and a public utility division of Montana-Dakota as of January 1,
2019
GVTC Generation Verification Test Capacity
Definitions
MDU Resources Group, Inc. Form 10-K 3
Holding Company Reorganization The internal holding company reorganization completed on January 1, 2019, pursuant to the
agreement and plan of merger, dated as of December 31, 2018, by and among Montana-Dakota,
the Company and MDUR Newco Sub, which resulted in the Company becoming a holding
company and owning all of the outstanding capital stock of Montana-Dakota.
IBEW International Brotherhood of Electrical Workers
ICWU International Chemical Workers Union
Intermountain Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
IPUC Idaho Public Utilities Commission
Item 8 Financial Statements and Supplementary Data
Knife River Knife River Corporation, a direct wholly owned subsidiary of Centennial
Knife River - Northwest Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River
K-Plan Company's 401(k) Retirement Plan
kW Kilowatts
kWh Kilowatt-hour
LWG Lower Willamette Group
MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations
Mdk Thousand dk
MDU Construction Services MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial
MDU Energy Capital MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
MDUR Newco MDUR Newco, Inc., a public holding company created by implementing the Holding Company
Reorganization, now known as the Company
MDUR Newco Sub MDUR Newco Sub, Inc., a direct, wholly owned subsidiary of MDUR Newco, which was merged
with and into Montana–Dakota in the Holding Company Reorganization
MEPP Multiemployer pension plan
MISO Midcontinent Independent System Operator, Inc.
MMBtu Million Btu
MMcf Million cubic feet
MMdk Million dk
MNPUC Minnesota Public Utilities Commission
Montana-Dakota Montana-Dakota Utilities Co. (formerly known as MDU Resources Group, Inc.), a public utility
division of the Company prior to the closing of the Holding Company Reorganization and a direct
wholly owned subsidiary of MDU Energy Capital as of January 1, 2019
Montana DEQ Montana Department of Environmental Quality
MPPAA Multiemployer Pension Plan Amendments Act of 1980
MTPSC Montana Public Service Commission
MW Megawatt
NDPSC North Dakota Public Service Commission
NERC North American Electric Reliability Corporation
NGL Natural gas liquids
Non-GAAP Not in accordance with GAAP
Oil Includes crude oil and condensate
OPUC Oregon Public Utility Commission
Oregon DEQ Oregon State Department of Environmental Quality
PCBs Polychlorinated biphenyls
Pronghorn Natural gas processing plant located near Belfield, North Dakota (WBI Energy Midstream's
50 percent ownership interests were sold effective January 1, 2017)
Proxy Statement Company's 2019 Proxy Statement to be filed no later than April 30, 2019
PRP Potentially Responsible Party
RCRA Resource Conservation and Recovery Act
ROD Record of Decision
RP Rehabilitation plan
SDPUC South Dakota Public Utilities Commission
SEC United States Securities and Exchange Commission
Definitions
4 MDU Resources Group, Inc. Form 10-K
Securities Act Securities Act of 1933, as amended
Securities Act Industry Guide 7 Description of Property by Issuers Engaged or to be Engaged in Significant Mining Operations
Sheridan System A separate electric system owned by Montana-Dakota
SSIP System Safety and Integrity Program
Stock Purchase Plan Company's Dividend Reinvestment and Direct Stock Purchase Plan which was terminated
effective December 5, 2016
TCJA Tax Cuts and Jobs Act
Tesoro Tesoro Refining & Marketing Company LLC
Thurston County Superior Court State of Washington Thurston County Superior Court
UA United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of
the United States and Canada
United States Supreme Court Supreme Court of the United States
VIE Variable interest entity
Washington DOE Washington State Department of Ecology
WBI Energy WBI Energy, Inc., a direct wholly owned subsidiary of WBI Holdings
WBI Energy Midstream WBI Energy Midstream, LLC, an indirect wholly owned subsidiary of WBI Holdings
WBI Energy Transmission WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Holdings WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
WUTC Washington Utilities and Transportation Commission
Wygen III 100-MW coal-fired electric generating facility near Gillette, Wyoming (25 percent ownership)
WYPSC Wyoming Public Service Commission
ZRCs Zonal resource credits - a MW of demand equivalent assigned to generators by MISO for meeting
system reliability requirements
Definitions
MDU Resources Group, Inc. Form 10-K 5
Part I
6 MDU Resources Group, Inc. Form 10-K
Forward-Looking Statements
This Form 10-K contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements
are all statements other than statements of historical fact, including without limitation those statements that are identified by the words
"anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions, and include statements concerning plans,
objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further
assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or
otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - MD&A - Business
Segment Financial and Operating Data.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those
expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a
reasonable basis, including without limitation, management's examination of historical operating trends, data contained in the Company's
records and other data available from third parties. Nonetheless, the Company's expectations, beliefs or projections may not be achieved or
accomplished.
Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company
undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date
on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not
possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to
which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking
statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified
by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.
Items 1 and 2. Business and Properties
General
The Company is a regulated energy delivery and construction materials and services business. Montana-Dakota was incorporated under the
laws of the state of Delaware in 1924. The Company was incorporated under the laws of the state of Delaware in 2018. Its principal
executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone [phone].
On November 21, 2017, the Company announced that its board of directors had directed senior management to explore reorganization to a
holding company structure. The purpose of the reorganization was to make the public utility divisions into a subsidiary of the holding
company, just as the other operating companies are wholly owned subsidiaries. On November 15, 2018, the board of directors approved the
Holding Company Reorganization and authorized senior management to take the necessary and appropriate actions to effectuate the Holding
Company Reorganization. On January 2, 2019, the Company announced the completion of the Holding Company Reorganization, which
resulted in Montana-Dakota and Great Plains becoming a subsidiary of the Company. The merger was conducted pursuant to Section 251(g)
of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the
stockholders of the constituent corporation. Immediately after consummation of the Holding Company Reorganization, the Company had, on
a consolidated basis, the same assets, businesses and operations as Montana-Dakota had immediately prior to the consummation of the
Holding Company Reorganization. As a result of the Holding Company Reorganization, the Company became the successor issuer to
Montana-Dakota pursuant to Rule 12g-3(a) of the Exchange Act, and as a result, the Company's common stock was deemed registered
under Section 12(b) of the Exchange Act.
The Company operates with a two-platform business model. Its regulated energy delivery platform and its construction materials and
services platform are each comprised of different operating segments. Some of these segments experience seasonality related to the
industries in which they operate. The two-platform approach helps balance this seasonality and the risk associated with each type of
industry. Through its regulated energy delivery platform, the Company provides electric and natural gas services to customers, generates,
transmits and distributes electricity, and provides natural gas transportation, storage and gathering services. These businesses are regulated
by state public service commissions and/or the FERC. The construction materials and services platform provides construction services to a
variety of industries, including commercial, industrial and governmental, and provides construction materials through aggregate mining and
marketing of related products, such as ready-mixed concrete and asphalt.
The Company is organized into five reportable business segments. These business segments include: electric, natural gas distribution,
pipeline and midstream, construction materials and contracting, and construction services. The Company's business segments are
determined based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences
in products, services and regulation. The internal reporting of these segments is defined based on the reporting and review process used by
the Company's chief executive officer.
The Company, through its wholly owned subsidiary, MDU Energy Capital, owns Montana-Dakota, Cascade and Intermountain. Montana-
Dakota, Cascade and Intermountain are the natural gas distribution segment. Montana-Dakota also comprises the electric segment.
The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings, Knife River, MDU Construction Services, Centennial
Resources and Centennial Capital. WBI Holdings is the pipeline and midstream segment, Knife River is the construction materials and
contracting segment, MDU Construction Services is the construction services segment, and Centennial Resources and Centennial Capital are
both reflected in the Other category.
For more information on the Company's business segments, see Item 8 - Note 15.
As of December 31, 2018, the Company had 11,797 employees with 218 employed at MDU Resources Group, Inc., 1,004 at Montana-
Dakota, 338 at Cascade, 242 at Intermountain, 317 at WBI Holdings, 3,967 at Knife River and 5,711 at MDU Construction Services. The
number of employees at certain Company operations fluctuates during the year depending upon the number and size of construction
projects. The Company considers its relations with employees to be satisfactory.
The following information regarding the number of employees represented by labor contracts is as of December 31, 2018.
At Montana-Dakota and WBI Energy Transmission, 349 and 70 employees, respectively, are represented by the IBEW. Labor contracts with
such employees are in effect through April 30, 2021, and March 31, 2022, respectively.
At Cascade, 197 employees are represented by the ICWU. The labor contract with the field operations group is effective through March 31,
2021.
At Intermountain, 130 employees are represented by the UA. Labor contracts with such employees are in effect through September 30,
2019.
Knife River operates under 43 labor contracts that represent 673 of its construction materials and contracting employees. Knife River is in
negotiations on five of its labor contracts.
MDU Construction Services has 126 labor contracts representing the majority of its employees. MDU Construction Services is not currently
in negotiations on any of its labor contracts.
The majority of the labor contracts contain provisions that prohibit work stoppages or strikes and provide for binding arbitration dispute
resolution in the event of an extended disagreement.
The Company's principal properties, which are of varying ages and are of different construction types, are generally in good condition, are
well maintained and are generally suitable and adequate for the purposes for which they are used.
The financial results and data applicable to each of the Company's business segments, as well as their financing requirements, are set forth
in Item 7 - MD&A and Item 8 - Note 15 and Supplementary Financial Information.
The operations of the Company and certain of its subsidiaries are subject to federal, state and local laws and regulations providing for air,
water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local
authorities; federal health and safety regulations; and state hazard communication standards. The Company believes that it is in substantial
compliance with these regulations, except as to what may be ultimately determined with regard to items discussed in Environmental matters
in Item 8 - Note 19. There are no pending CERCLA actions for any of the Company's properties, other than the Portland, Oregon, Harbor
Superfund Site and the Bremerton Gasworks Superfund Site.
The Company produces GHG emissions primarily from its fossil fuel electric generating facilities, as well as from natural gas pipeline and
storage systems, and operations of equipment and fleet vehicles. GHG emissions also result from customer use of natural gas for heating
and other uses. As interest in reductions in GHG emissions has grown, the Company has developed renewable generation with lower or no
GHG emissions. Governmental legislative and regulatory initiatives regarding environmental and energy policy are continuously evolving and
could negatively impact the Company's operations and financial results. Until legislation and regulation are finalized, the impact of these
measures cannot be accurately predicted. The Company will continue to monitor legislative and regulatory activity related to environmental
and energy policy initiatives. Disclosure regarding specific environmental matters applicable to each of the Company's businesses is set
Part I
MDU Resources Group, Inc. Form 10-K 7
forth under each business description later. In addition, for a discussion of the Company's risks related to environmental laws and
regulations, see Item 1A - Risk Factors.
The Company uses technology in substantially all aspects of its business operations and requires uninterrupted operation of information
technology systems and network infrastructure. These systems may be vulnerable to failures or unauthorized access. The Company has
policies, procedures and processes in place designed to strengthen and protect these systems, which includes the Company’s enterprise
information technology and operation technology groups continually evaluating new tools and techniques that can be implemented to reduce
the risk of a cyber breach.
The Company created CyROC to oversee the Company’s approach to cybersecurity. CyROC is responsible for supplying management at all
levels and the Audit Committee with analyses, appraisals, recommendations and pertinent information concerning cyber defense of the
Company’s electronic information and information technology systems. CyROC provides a quarterly cybersecurity report to the Audit
Committee. For a discussion of the Company's risks related to cybersecurity, see Item 1A - Risk Factors.
This annual report on Form 10-K, the Company's quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge through the Company's
Web site as soon as reasonably practicable after the Company has electronically filed such reports with, or furnished such reports to, the
SEC. The Company's Web site address is www.mdu.com. The information available on the Company's Web site is not part of this annual
report on Form 10-K.
Part I
8 MDU Resources Group, Inc. Form 10-K
Electric
General Montana-Dakota provides electric service at retail, serving 143,022 residential, commercial, industrial and municipal customers in
184 communities and adjacent rural areas in Montana, North Dakota, South Dakota and Wyoming as of December 31, 2018. For more
information on the retail customer classes served, see the table below. The principal properties owned by Montana-Dakota for use in its
electric operations include interests in 16 electric generating units at 11 facilities and two small portable diesel generators, as further
described under System Supply, System Demand and Competition, approximately 3,200 and 4,900 miles of transmission and distribution
lines, respectively, and 75 transmission and 297 distribution substations. Montana-Dakota has obtained and holds, or is in the process of
renewing, valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such
franchises are required. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises. At December 31,
2018, Montana-Dakota's net electric plant investment was $1.5 billion and rate base was $1.2 billion.
The retail customers served and respective revenues by class for the electric business were as follows:
2018 2017 2016
CustomersServed Revenues CustomersServed Revenues CustomersServed Revenues
(Dollars in thousands)
Residential 118,426 $126,173 118,379 $121,171 118,483 $117,014
Commercial 22,756 141,961 22,764 140,856 22,693 135,390
Industrial 236 36,081 242 34,417 244 31,913
Other 1,604 7,882 1,516 8,275 1,528 7,580
143,022 $312,097 142,901 $304,719 142,948 $291,897
Other electric revenues for Montana-Dakota were $23.0 million, $38.1 million and $30.4 million for the years ended December 31, 2018,
2017 and 2016, respectively.
The percentage of electric retail revenues by jurisdiction was as follows:
2018 2017 2016
North Dakota 66%66%68%
Montana 20%20%19%
Wyoming 9%9%8%
South Dakota 5%5%5%
Retail electric rates, service, accounting and certain security issuances are subject to regulation by the MTPSC, NDPSC, SDPUC and
WYPSC. The interstate transmission and wholesale electric power operations of Montana-Dakota also are subject to regulation by the FERC
under provisions of the Federal Power Act, as are interconnections with other utilities and power generators, the issuance of certain
securities, accounting and other matters.
Through MISO, Montana-Dakota has access to wholesale energy, ancillary services and capacity markets for its interconnected system.
MISO is a regional transmission organization responsible for operational control of the transmission systems of its members. MISO provides
security center operations, tariff administration and operates day-ahead and real-time energy markets, ancillary services and capacity
markets. As a member of MISO, Montana-Dakota's generation is sold into the MISO energy market and its energy needs are purchased from
that market.
System Supply, System Demand and Competition Through an interconnected electric system, Montana-Dakota serves markets in portions of
western North Dakota, eastern Montana and northern South Dakota. The interconnected system consists of 15 electric generating units at
10 facilities and two small portable diesel generators, which have an aggregate nameplate rating attributable to Montana-Dakota's interest of
750,318 kW and total net ZRCs of 532.3 in 2018. ZRCs are a MW of demand equivalent measure and are allocated to individual
generators to meet planning reserve margin requirements within MISO. For 2018, Montana-Dakota's total ZRCs, including its firm purchase
power contracts, were 574.5. Montana-Dakota's planning reserve margin requirement within MISO was 537.2 for 2018. The maximum
electric peak demand experienced to date attributable to Montana-Dakota's sales to retail customers on the interconnected system was
611,542 kW in August 2015. Montana-Dakota's latest forecast for its interconnected system indicates that its annual peak will continue to
occur during the summer and the sales growth rate through 2023 will approximate two percent annually. Montana-Dakota's interconnected
system electric generating capability includes five steam-turbine generating units at four facilities using coal for fuel, four combustion
turbine units at three facilities, three wind electric generating facilities, two reciprocating internal combustion engines at one facility, a heat
recovery electric generating facility and two small portable diesel generators.
In June 2016, Montana-Dakota and a partner began construction on the BSSE project within the footprint of MISO. Montana-Dakota began
bringing the project on-line on February 5, 2019. On October 31, 2018, the Company finalized the purchase and placed into service the
Thunder Spirit Wind farm expansion in southwest North Dakota, which includes 16 turbines. With the addition of the expansion, the total
Thunder Spirit Wind farm generation capacity is approximately 155 MW. The original 107.5-MW wind farm includes 43 turbines; it was
purchased by Montana-Dakota in December 2015. For more information on these projects, see Item 7 - MD&A - Electric and Natural Gas
Distribution.
Additional energy is purchased as needed, or in lieu of generation if more economical, from the MISO market, and in 2018, Montana-
Dakota purchased approximately 22 percent of its net kWh needs for its interconnected system through the MISO market.
Approximately 21 percent of the electricity delivered to customers from Montana-Dakota's owned generation in 2018 was from renewable
resources. Although Montana-Dakota's generation resource capacity has increased to serve the needs of customers, the carbon dioxide
emission intensity of the electric generation resource fleet has been reduced by approximately 24 percent since 2003 and is expected to
continue to decline.
Through the Sheridan System, Montana-Dakota serves Sheridan, Wyoming, and neighboring communities. The maximum peak demand
experienced to date attributable to Montana-Dakota sales to retail customers on that system was approximately 63,686 kW in July 2018.
Montana-Dakota has a power supply contract with Black Hills Power, Inc. to purchase up to 49,000 kW of capacity annually through
December 31, 2023. Wygen III serves a portion of the needs of its Sheridan-area customers.
Part I
MDU Resources Group, Inc. Form 10-K 9
The following table sets forth details applicable to the Company's electric generating stations:
Generating Station Type NameplateRating (kW)2018 ZRCs (a)
2018 NetGeneration (kWhin thousands)
Interconnected System:
North Dakota:
Coyote (b)Steam 103,647 80.8 765,233
Heskett Steam 86,000 87.4 504,357
Heskett Combustion Turbine 89,038 61.6 3,981
Glen Ullin Heat Recovery 7,500 4.8 44,940
Cedar Hills Wind 19,500 4.4 49,933
Diesel Units Oil 3,650 3.6 6
Thunder Spirit Wind 155,500 21.1 407,947
South Dakota:
Big Stone (b)Steam 94,111 103.8 521,187
Montana:
Lewis & Clark Steam 44,000 50.3 235,882
Lewis & Clark Reciprocating Internal Combustion Engine 18,700 16.7 8,497
Glendive Combustion Turbine 75,522 70.6 2,734
Miles City Combustion Turbine 23,150 21.6 273
Diamond Willow Wind 30,000 5.6 86,103
750,318 532.3 2,631,073
Sheridan System:
Wyoming:
Wygen III (b)Steam 28,000 N/A 209,280
778,318 532.3 2,840,353
(a)Interconnected system only. MISO requires generators to obtain their summer capability through the GVTC. The GVTC is thenconverted to ZRCs by applying each generator's forced outage factor against its GVTC. Wind generator's ZRCs are calculated basedon a wind capacity study performed annually by MISO. ZRCs are used to meet supply obligations within MISO.(b)Reflects Montana-Dakota's ownership interest.
Virtually all of the current fuel requirements of the Heskett and Lewis & Clark stations are met with coal supplied by subsidiaries of
Westmoreland Coal Company under contracts that expire in December 2021 and December 2020, respectively. The Heskett and Lewis &
Clark coal supply agreements provide for the purchase of coal necessary to supply the coal requirements of these stations at contracted
pricing. Montana-Dakota estimates the Heskett and Lewis & Clark coal requirement to be in the range of 425,000 to 460,000 tons and
250,000 to 350,000 tons per contract year, respectively.
The owners of Coyote Station, including Montana-Dakota, have a contract with Coyote Creek for coal supply to the Coyote Station that
expires December 2040. Montana-Dakota estimates the Coyote Station coal supply agreement to be approximately 2.5 million tons per
contract year. For more information, see Item 8 - Note 19.
The owners of Big Stone Station, including Montana-Dakota, have a coal supply agreement with Peabody COALSALES, LLC to meet all of
the Big Stone Station's fuel requirements for 2019 and 2020, with the exception of 250,000 tons in 2019, which was previously
committed to be purchased from Contura Coal Sales, LLC, all at contracted pricing.
Montana-Dakota has a coal supply agreement with Wyodak Resources Development Corp., to supply the coal requirements of Wygen III at
contracted pricing through June 1, 2060. Montana-Dakota estimates the maximum annual coal consumption of the facility to be
585,000 tons.
The average cost of coal purchased, including freight, at Montana-Dakota's electric generating stations (including the Big Stone, Coyote and
Wygen III stations) was as follows:
Years ended December 31,2018 2017 2016
Average cost of coal per MMBtu $2.00 $2.07 $1.89
Average cost of coal per ton $29.08 $30.04 $27.45
Part I
10 MDU Resources Group, Inc. Form 10-K
Montana-Dakota expects that it has secured adequate capacity available through existing baseload generating stations, renewable
generation, turbine peaking stations, demand reduction programs and firm contracts to meet the peak customer demand requirements of its
customers through 2028. Future capacity that is needed to replace contracts, generation retirements and meet system growth requirements
is expected to be met by constructing new generation resources, or acquiring additional capacity through power purchase contracts or the
MISO capacity auction.
Montana-Dakota has major interconnections with its neighboring utilities and considers these interconnections adequate for coordinated
planning, emergency assistance, exchange of capacity and energy and power supply reliability.
Montana-Dakota is subject to competition in varying degrees, in certain areas, from rural electric cooperatives, on-site generators, co-
generators and municipally owned systems. In addition, competition in varying degrees exists between electricity and alternative forms of
energy such as natural gas.
Regulatory Matters and Revenues Subject to Refund In North Dakota, Montana-Dakota's results of operations reflect monthly increases or
decreases in electric fuel and purchased power costs (including demand charges) and Montana-Dakota is deferring those electric fuel and
purchased power costs that are greater or less than amounts presently being recovered through its existing rate schedules. In Montana, a
monthly Fuel and Purchased Power Tracking Adjustment mechanism allows Montana-Dakota's results of operations to reflect 90 percent of
the increases or decreases in electric fuel and purchased power costs (including demand charges) and Montana-Dakota is deferring
90 percent of costs that are greater or less than amounts presently being recovered through its existing rate schedules. A fuel adjustment
clause contained in South Dakota's jurisdictional electric rate schedules allows Montana-Dakota's results of operations to reflect monthly
increases or decreases in electric fuel and purchased power costs. In Wyoming, an annual Electric Power Supply Cost Adjustment
mechanism allows Montana-Dakota's results of operations to reflect increases or decreases in purchased power costs (including demand
charges) related to power supply and Montana-Dakota is deferring costs that are greater or less than amounts presently being recovered
through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments
which are filed annually. Montana-Dakota's results of operations reflect 95 percent of the increases or decreases from the base purchased
power costs and in addition also reflects 85 percent of the increases or decreases from the base coal price, which is also recovered through
the Electric Power Supply Cost Adjustment. For more information on regulatory assets and liabilities, see Item 8 - Note 6.
For the Thunder Spirit Wind project, Montana-Dakota implemented a renewable resource cost adjustment rider, and all of Montana-Dakota's
wind resources pertaining to North Dakota electric operations were placed in this rider upon a final order of the most recent North Dakota
electric general rate case. Montana-Dakota also has in place in North Dakota a transmission tracker to recover transmission costs associated
with MISO and the Southwest Power Pool, regional transmission organizations serving parts of Montana-Dakota's system, along with certain
of the transmission investments not recovered through retail rates. The tracking mechanism has an annual true-up.
In South Dakota, Montana-Dakota recovers the South Dakota investment in the Thunder Spirit Wind project through an Infrastructure Rider
tracking mechanism that is subject to an annual true-up. Montana-Dakota also has in place in South Dakota a transmission tracker to
recover transmission costs associated with MISO and the Southwest Power Pool, regional transmission organizations serving parts of
Montana-Dakota's system, along with certain of the transmission investments not recovered through retail rates. This tracking mechanism
also has an annual true-up.
In Montana, Montana-Dakota recovers in rates through a tracking mechanism the increases associated with its allocated share of Montana
state and local taxes assessed to electric operations on an after tax basis.
For more information on regulatory matters, see Item 8 - Note 18.
Environmental Matters Montana-Dakota's electric operations are subject to federal, state and local laws and regulations providing for air,
water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local
authorities; federal health and safety regulations; and state hazard communication standards. Montana-Dakota believes it is in substantial
compliance with these regulations.
Montana-Dakota's electric generating facilities have Title V Operating Permits, under the Clean Air Act, issued by the states in which they
operate. Each of these permits has a five-year life. Near the expiration of these permits, renewal applications are submitted. Permits
continue in force beyond the expiration date, provided the application for renewal is submitted by the required date, usually six months prior
to expiration. The Title V Operating Permit renewal application for Coyote Station was submitted timely to the North Dakota Department of
Health in September 2017, with the permit expected to be issued in 2019. Wygen III is allowed to operate under the facility's construction
permit until the Title V Operating Permit is issued by the Wyoming Department of Environmental Quality. The Title V Operating Permit
application for Wygen III was submitted timely in January 2011, with the permit expected to be issued in 2019.
Part I
MDU Resources Group, Inc. Form 10-K 11
State water discharge permits issued under the requirements of the Clean Water Act are maintained for power production facilities on the
Yellowstone and Missouri rivers. These permits also have five-year lives. Montana-Dakota renews these permits as necessary prior to
expiration. Other permits held by these facilities may include an initial siting permit, which is typically a one-time, preconstruction permit
issued by the state; state permits to dispose of combustion by-products; state authorizations to withdraw water for operations; and Army
Corps permits to construct water intake structures. Montana-Dakota's Army Corps permits grant one-time permission to construct and do not
require renewal. Other permit terms vary and the permits are renewed as necessary.
Montana-Dakota's electric operations are very small-quantity generators of hazardous waste and subject only to minimum regulation under
the RCRA. Montana-Dakota routinely handles PCBs from its electric operations in accordance with federal requirements. PCB storage areas
are registered with the EPA as required.
Montana-Dakota incurred $9.2 million of environmental capital expenditures in 2018, mainly for coal ash management projects at Lewis &
Clark Station, Big Stone Station and Coyote Station. Environmental capital expenditures are estimated to be $6.8 million, $2.7 million and
$1.8 million in 2019, 2020 and 2021, respectively, for various environmental projects, including coal ash management at power plants.
Montana-Dakota's capital and operational expenditures could also be affected by future air emission regulations, including a future GHG
regulation that may replace the Clean Power Plan rule published by the EPA in October 2015. The Clean Power Plan requires existing fossil
fuel-fired electric generating facilities to reduce carbon dioxide emissions. For more information, see Item 1A - Risk Factors.
Part I
12 MDU Resources Group, Inc. Form 10-K
Natural Gas Distribution
General The Company's natural gas distribution operations consist of Montana-Dakota, Cascade and Intermountain, which sell natural gas at
retail, serving 957,727 residential, commercial and industrial customers in 339 communities and adjacent rural areas across eight states as
of December 31, 2018, and provide natural gas transportation services to certain customers on the Company's systems. For more
information on the retail customer classes served, see the table below. These services are provided through distribution systems aggregating
approximately 19,400 miles. The natural gas distribution operations have obtained and hold, or are in the process of renewing, valid and
existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are
required. These operations intend to protect their service areas and seek renewal of all expiring franchises. At December 31, 2018, the
natural gas distribution operations' net natural gas distribution plant investment was $1.7 billion and rate base was $1.1 billion.
The retail customers served and respective revenues by class for the natural gas distribution operations were as follows:
2018 2017 2016
CustomersServed Revenues CustomersServed Revenues CustomersServed Revenues
(Dollars in thousands)
Residential 850,595 $464,697 833,255 $477,699 818,163 $429,828
Commercial 106,297 279,566 104,795 283,899 103,438 253,333
Industrial 835 24,555 817 24,030 807 23,337
957,727 $768,818 938,867 $785,628 922,408 $706,498
Transportation and other revenues for the natural gas distribution operations were $54.4 million, $62.8 million and $59.6 million for the
years ended December 31, 2018, 2017 and 2016, respectively.
The percentage of the natural gas distribution operations' retail sales revenues by jurisdiction was as follows:
2018 2017 2016
Idaho 30%33%34%
Washington 26%26%26%
North Dakota 15%13%13%
Montana 9%9%8%
Oregon 8%8%8%
South Dakota 7%6%6%
Minnesota 3%3%3%
Wyoming 2%2%2%
The natural gas distribution operations are subject to regulation by the IPUC, MNPUC, MTPSC, NDPSC, OPUC, SDPUC, WUTC and WYPSC
regarding retail rates, service, accounting and certain security issuances.
System Supply, System Demand and Competition The natural gas distribution operations serve retail natural gas markets, consisting
principally of residential and firm commercial space and water heating users, in portions of Idaho; western Minnesota; eastern Montana;
North Dakota; central and eastern Oregon; western and north-central South Dakota; western, southeastern and south-central Washington;
and northern Wyoming. These markets are highly seasonal and sales volumes depend largely on the weather, the effects of which are
mitigated in certain jurisdictions by a weather normalization mechanism discussed in Regulatory Matters. In addition to the residential and
commercial sales, the utilities transport natural gas for larger commercial and industrial customers who purchase their own supply of natural
gas.
Competition in varying degrees exists between natural gas and other fuels and forms of energy. The natural gas distribution operations have
established various natural gas transportation service rates for their distribution businesses to retain interruptible commercial and industrial
loads. These services have enhanced the natural gas distribution operations' competitive posture with alternative fuels, although certain
customers have bypassed the distribution systems by directly accessing transmission pipelines within close proximity. These bypasses did
not have a material effect on results of operations.
The natural gas distribution operations and various distribution transportation customers obtain their system requirements directly from
producers, processors and marketers. The Company's purchased natural gas is supplied by a portfolio of contracts specifying market-based
pricing and is transported under transportation agreements with WBI Energy Transmission, Northern Border Pipeline Company, Northwest
Pipeline LLC, South Dakota Intrastate Pipeline, TransCanada Corporation, Northern Natural Gas, Gas Transmission Northwest LLC,
Northwestern Energy, Viking Gas Transmission Company, Westcoast Energy Inc., Ruby Pipeline LLC, Foothills Pipe Lines Ltd. and NOVA Gas
Transmission Ltd. The natural gas distribution operations have contracts for storage services to provide gas supply during the winter heating
season and to meet peak day demand with various storage providers, including WBI Energy Transmission, Dominion Energy Questar
Pipeline, LLC, Northwest Pipeline LLC and Northern Natural Gas. In addition, certain of the operations have entered into natural gas supply
management agreements with various parties. Demand for natural gas, which is a widely traded commodity, has historically been sensitive
to seasonal heating and industrial load requirements as well as changes in market price. The natural gas distribution operations believe that,
based on current and projected domestic and regional supplies of natural gas and the pipeline transmission network currently available
through their suppliers and pipeline service providers, supplies are adequate to meet their system natural gas requirements for the next
decade.
Regulatory Matters The natural gas distribution operations' retail natural gas rate schedules contain clauses permitting adjustments in rates
based upon changes in natural gas commodity, transportation and storage costs. Current tariffs allow for recovery or refunds of under- or
over-recovered gas costs through rate adjustments which are filed annually.
Montana-Dakota's North Dakota and South Dakota natural gas tariffs contain weather normalization mechanisms applicable to certain firm
customers that adjust the distribution delivery charge revenues to reflect weather fluctuations during the November 1 through May 1 billing
periods.
In Montana, Montana-Dakota recovers in rates through a tracking mechanism the increases associated with Montana state and local taxes
assessed to natural gas operations on an after tax basis.
In Minnesota and Washington, Great Plains and Cascade recover in rates through a cost recovery tracking mechanism, qualifying capital
investments related to the safety and integrity of its pipeline system.
On December 28, 2015, the OPUC approved an extension of Cascade's decoupling mechanism until January 1, 2020, with an agreement
that Cascade would initiate a review of the mechanism by September 30, 2019. Cascade also has an earnings sharing mechanism with
respect to its Oregon jurisdictional operations as required by the OPUC.
On July 7, 2016, the WUTC approved a full decoupling mechanism where Cascade is allowed recovery of an average revenue per customer
regardless of actual consumption. The mechanism also includes an earnings sharing component if Cascade earns beyond its authorized
return. The decoupling mechanism will be reviewed by Cascade following the end of 2019.
On December 22, 2016, the MNPUC approved a request by Great Plains to implement a full revenue decoupling mechanism pilot project
for three years. The decoupling mechanism will reflect the period January 1 through December 31. Great Plains intends to seek
continuation of the decoupling mechanism effective upon expiration of the pilot project.
For more information on regulatory matters, see Item 8 - Note 18.
Part I
MDU Resources Group, Inc. Form 10-K 13
Environmental Matters The natural gas distribution operations are subject to federal, state and local environmental, facility-siting, zoning
and planning laws and regulations. The Company believes its natural gas distribution operations are in substantial compliance with those
regulations.
The Company's natural gas distribution operations are very small-quantity generators of hazardous waste, and subject only to minimum
regulation under the RCRA. Washington state rule defines Cascade as a small-quantity generator, but regulation under the rule is similar to
RCRA. Certain locations of the natural gas distribution operations routinely handle PCBs from their natural gas operations in accordance
with federal requirements. PCB storage areas are registered with the EPA as required. Capital and operational expenditures for natural gas
distribution operations could be affected in a variety of ways by potential new GHG legislation or regulation. In particular, such legislation or
regulation would likely increase capital expenditures for energy efficiency and conservation programs and operational costs associated with
GHG emissions compliance. Natural gas distribution operations expect to recover the operational and capital expenditures for GHG
regulatory compliance in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations.
The natural gas distribution operations did not incur any material environmental expenditures in 2018. Except as to what may be ultimately
determined with regard to the issues described in the following paragraph, the natural gas distribution operations do not expect to incur any
material capital expenditures related to environmental compliance with current laws and regulations through 2021.
Montana-Dakota has ties to six historic manufactured gas plants as a successor corporation or through direct ownership of the plant.
Montana-Dakota is investigating one of these former manufactured gas plant sites and providing input on another site investigation
conducted by a third party. To the extent not covered by insurance, Montana-Dakota may seek recovery in its natural gas rates charged to
customers for certain investigation and remediation costs incurred for these sites. Cascade has ties to nine historic manufactured gas plants
as a successor corporation or through direct ownership of the plant. Cascade is involved in the investigation and remediation of three of
these manufactured gas plants in Washington and Oregon. See Item 8 - Note 19 for a further discussion of these three manufactured gas
plants. To the extent not covered by insurance, Cascade will seek recovery of investigation and remediation costs through its natural gas
rates charged to customers.
Part I
14 MDU Resources Group, Inc. Form 10-K
Pipeline and Midstream
General WBI Energy owns and operates both regulated and nonregulated businesses. The regulated business of this segment, WBI Energy
Transmission, owns and operates approximately 4,000 miles of natural gas transmission, gathering and storage lines in Minnesota, Montana,
North Dakota, South Dakota and Wyoming. WBI Energy Transmission's underground storage fields in Montana and Wyoming provide storage
services to local distribution companies, industrial customers, natural gas marketers and others, and serve to enhance system reliability. Its
system is strategically located near five natural gas producing basins, making natural gas supplies available to its transportation and storage
customers. The system has 14 interconnecting points with other pipeline facilities allowing for the receipt and/or delivery of natural gas to
and from other regions of the country and from Canada. Under the Natural Gas Act, as amended, WBI Energy Transmission is subject to the
jurisdiction of the FERC regarding certificate, rate, service and accounting matters, and at December 31, 2018, its net plant investment
was $458.1 million.
The nonregulated business of this segment owns and operates gathering facilities in Montana and Wyoming. In total, facilities include
approximately 800 miles of operated field gathering lines, some of which interconnect with WBI Energy's regulated pipeline system. The
nonregulated business provides natural gas gathering services and a variety of other energy-related services, including cathodic protection
and energy efficiency product sales and installation services to large end-users.
A majority of its pipeline and midstream business is transacted in the northern Great Plains and Rocky Mountain regions of the United
States.
System Supply, System Demand and Competition Natural gas supplies emanate from traditional and nontraditional production activities in
the region from both on-system and off-system supply sources. New incremental supply from nontraditional sources have developed, such as
the Bakken area in Montana and North Dakota, which has helped offset declines in traditional regional supply sources and supports WBI
Energy Transmission's transportation and storage services. In addition, off-system supply sources are available through the Company's
interconnections with other pipeline systems. WBI Energy Transmission continues to look for opportunities to increase transportation,
gathering and storage services through system expansion and/or other pipeline interconnections or enhancements that could provide
substantial future benefits.
WBI Energy Transmission's underground natural gas storage facilities have a certificated storage capacity of approximately 353 Bcf,
including 193 Bcf of working gas capacity, 85 Bcf of cushion gas and 75 Bcf of native gas. These storage facilities enable customers to
purchase natural gas throughout the year and meet winter peak requirements.
WBI Energy Transmission competes with several pipelines for its customers' transportation, storage and gathering business and at times may
discount rates in an effort to retain market share. However, the strategic location of its system near five natural gas producing basins and
the availability of underground storage and gathering services, along with interconnections with other pipelines, serve to enhance its
competitive position.
Although certain of WBI Energy Transmission's firm customers, including its largest firm customer Montana-Dakota, serve relatively secure
residential, commercial and industrial end-users, they generally all have some price-sensitive end-users that could switch to alternate fuels.
WBI Energy Transmission transports substantially all of Montana-Dakota's natural gas, primarily utilizing firm transportation agreements,
which for 2018 represented 32 percent of WBI Energy Transmission's subscribed firm transportation contract demand. The majority of the
firm transportation agreements with Montana-Dakota expire in June 2022. In addition, Montana-Dakota has contracts with WBI Energy
Transmission to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements expiring in July 2035.
The nonregulated business competes for existing customers in the fields in which it operates. Its focus on customer service and the variety
of services it offers serve to enhance its competitive position.
Environmental Matters The pipeline and midstream operations are generally subject to federal, state and local environmental, facility-siting,
zoning and planning laws and regulations. The Company believes it is in substantial compliance with those regulations.
Ongoing operations are subject to the Clean Air Act, the Clean Water Act, the RCRA and other state and federal regulations. Administration
of many provisions of these laws has been delegated to the states where WBI Energy and its subsidiaries operate. Permit terms vary and all
permits carry operational compliance conditions. Some permits require annual renewal, some have terms ranging from one to five years and
others have no expiration date. Permits are renewed and modified, as necessary, based on defined permit expiration dates, operational
demand and/or regulatory changes.
Detailed environmental assessments and/or environmental impact statements as required by the National Environmental Policy Act are
included in the FERC's environmental review process for both the construction and abandonment of WBI Energy Transmission's natural gas
transmission pipelines, compressor stations and storage facilities.
The pipeline and midstream operations did not incur any material environmental expenditures in 2018 and do not expect to incur any
material capital expenditures related to environmental compliance with current laws and regulations through 2021.
Part I
MDU Resources Group, Inc. Form 10-K 15
Construction Materials and Contracting
General Knife River operates construction materials and contracting businesses headquartered in Alaska, California, Hawaii, Idaho, Iowa,
Minnesota, Montana, North Dakota, Oregon, South Dakota, Texas, Washington and Wyoming. These operations mine, process and sell
construction aggregates (crushed stone, sand and gravel); produce and sell asphalt mix; and supply ready-mixed concrete. These products
are used in most types of construction, performed by Knife River and other companies, including roads, freeways and bridges, as well as
homes, schools, shopping centers, office buildings and industrial parks. Knife River focuses on vertical integration of its contracting services
with its construction materials to support the aggregate based product lines including aggregate placement, asphalt and concrete paving,
and site development and grading. Although not common to all locations, other products include the sale of cement, liquid asphalt for
various commercial and roadway applications, various finished concrete products and other building materials and related contracting
services.
During 2018, Knife River acquired construction materials and contracting businesses with operations in Oregon, Minnesota and South
Dakota. For more information on acquisitions, see Item 8 - Note 3.
Knife River's backlog was approximately $706 million, $486 million and $538 million at December 31, 2018, 2017 and 2016,
respectively. The increase in backlog at December 31, 2018, compared to backlog at December 31, 2017, was primarily attributable to
higher backlog of federal and state agency work, as well as higher backlog of private construction projects. Backlog increases with awards of
new contracts and decreases as work is performed on existing contracts. Knife River expects to complete a significant amount of the backlog
at December 31, 2018, during the next 12 months.
Knife River's backlog is comprised of the anticipated revenues from the uncompleted portion of services to be performed under job-specific
contracts. A project is included in backlog when a contract is awarded and agreement on contract terms has been reached. However,
backlog does not contain contracts for time and material projects that a fixed amount cannot be determined. Backlog is comprised of: (a)
original contract amounts, (b) change orders for which customers have approved and (c) claim amounts that have been made against
customers for which are determined to have a legal basis under existing contractual arrangements and as to which recovery is considered to
be probable. Such claim amounts were immaterial for all periods presented. Backlog may be subject to delay, default or cancellation at the
election of the customers. Historically, cancellations have not had a materially adverse effect on backlog. Due to the nature of its
contractual arrangements, in many instances Knife River's customers are not committed to the specific volumes of services to be purchased
under a contract, but rather Knife River is committed to perform these services if and to the extent requested by the customer. Therefore,
there can be no assurance as to the customers' requirements during a particular period or that such estimates, or backlog estimates in
general, at any point in time are predictive of future revenues.
Competition Knife River's construction materials products and contracting services are marketed under highly competitive conditions. Price
is the principal competitive force to which these products and services are subject, with service, quality, delivery time and proximity to the
customer also being significant factors. Knife River focuses on markets located near aggregate sites to reduce transportation costs which
allows Knife River to remain competitive with the pricing of aggregate products. The number and size of competitors varies in each of Knife
River's principal market areas and product lines.
The demand for construction materials products and contracting services is significantly influenced by the cyclical nature of the
construction industry in general. In addition, construction materials and contracting services activity in certain locations may be seasonal in
nature due to the effects of weather. The key economic factors affecting product demand are changes in the level of local, state and federal
governmental spending on roads and infrastructure projects, general economic conditions within the market area that influence both the
commercial and residential sectors, and prevailing interest rates.
Knife River's customers are a diverse group which includes federal, state and municipal government agencies, commercial and residential
developers, and private parties. The mix of sales by customer will vary each year depending on the work available. Knife River is not
dependent on any single customer or group of customers for sales of its products and services, the loss of which would have a material
adverse effect on its construction materials businesses.
Reserve Information Aggregate reserve estimates are calculated based on the best available data. This data is collected from drill holes and
other subsurface investigations, as well as investigations of surface features such as mine high walls and other exposures of the aggregate
reserves. Mine plans, production history and geologic data also are utilized to estimate reserve quantities.
Estimates are based on analyses of the data described above by experienced internal mining engineers, operating personnel and geologists.
Property setbacks and other regulatory restrictions and limitations are identified to determine the total area available for mining. Data
described previously are used to calculate the thickness of aggregate materials to be recovered. Topography associated with alluvial sand
and gravel deposits is typically flat and volumes of these materials are calculated by applying the thickness of the resource over the areas
available for mining. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 1.5 tons per cubic yard in the
ground is used for sand and gravel deposits.
Topography associated with the hard rock reserves is typically much more diverse. Therefore, using available data, a final topography map is
created and computer software is utilized to compute the volumes between the existing and final topographies. Volumes are then converted
to tons by using an appropriate conversion factor. Typically, 2 tons per cubic yard in the ground is used for hard rock quarries.
Estimated reserves are probable reserves as defined in Securities Act Industry Guide 7. Remaining reserves are based on estimates of
volumes that can be economically extracted and sold to meet current market and product applications. The reserve estimates include only
salable tonnage and thus exclude waste materials that are generated in the crushing and processing phases of the operation. Approximately
938 million tons of the 1.0 billion tons of aggregate reserves are permitted reserves. The remaining reserves are on properties that are
expected to be permitted for mining under current regulatory requirements. The data used to calculate the remaining reserves may require
revisions in the future to account for changes in customer requirements and unknown geological occurrences. The years remaining were
calculated by dividing remaining reserves by the three-year average sales, including estimated sales from acquired reserves prior to
acquisition, from 2016 through 2018. Actual useful lives of these reserves will be subject to, among other things, fluctuations in customer
demand, customer specifications, geological conditions and changes in mining plans.
Part I
16 MDU Resources Group, Inc. Form 10-K
The following table sets forth details applicable to the Company's aggregate reserves under ownership or lease as of December 31, 2018,
and sales for the years ended December 31, 2018, 2017 and 2016:
Number of Sites(Crushed Stone)Number of Sites(Sand & Gravel)Tons Sold (000's)EstimatedReserves(000's tons)LeaseExpiration
ReserveLife(years)Production Area owned leased owned leased 2018 2017 2016
Anchorage, AK ——1 —725 1,425 1,343 13,823 N/A 12
Hawaii —5 ——1,734 1,614 1,901 49,159 2023-2064 28
Northern CA ——9 1 1,798 1,785 1,604 42,720 2028 25
Southern CA —2 ——356 55 224 91,211 2035 Over 100
Portland, OR 2 4 5 3 5,402 4,694 4,044 212,822 2028-2057 45
Eugene, OR 3 4 5 —743 633 662 153,301 2021-2049 Over 100
Central OR/WA/ID —1 6 2 2,362 2,160 1,685 85,396 2020-2087 41
Southwest OR 5 5 10 6 2,395 2,367 2,689 108,998 2021-2053 44
Central MT ——3 1 1,081 1,065 1,135 15,238 2023 14
Northwest MT ——9 1 1,965 1,745 1,514 63,182 2020 36
Wyoming ——1 2 626 613 742 9,466 2019-2020 14
Central MN 1 1 43 7 2,890 2,773 2,831 65,225 2019-2028 18 *
Northern MN 2 —14 2 369 270 537 21,062 2020-2021 54
ND/SD 1 —3 24 1,506 1,100 1,643 74,214 2019-2031 17 *
Texas 1 2 1 —1,094 1,192 1,243 8,614 2022-2029 7
Sales from other sources 4,749 4,722 3,783
29,795 28,213 27,580 1,014,431
*Includes estimate of three-year average sales for acquired reserves.
The 1.0 billion tons of estimated aggregate reserves at December 31, 2018, are comprised of 518 million tons that are owned and
496 million tons that are leased. Approximately 48 percent of the tons under lease have lease expiration dates of 20 years or more. The
weighted average years remaining on all leases containing estimated probable aggregate reserves is approximately 23 years, including
options for renewal that are at Knife River's discretion. Based on a three-year average of sales from 2016 through 2018 of leased reserves,
the average time necessary to produce remaining aggregate reserves from such leases is approximately 44 years. Some sites have leases that
expire prior to the exhaustion of the estimated reserves. The estimated reserve life assumes, based on Knife River's experience, that leases
will be renewed to allow sufficient time to fully recover these reserves.
The changes in Knife River's aggregate reserves for the years ended December 31 were as follows:
2018 2017 2016
(000's of tons)
Aggregate reserves:
Beginning of year 965,036 989,084 1,022,513
Acquisitions (a)81,004 2,726 24,993
Sales volumes (b)(25,046)(23,491)(23,797)
Other (c)(6,563)(3,283)(34,625)
End of year 1,014,431 965,036 989,084
(a)Includes reserves from acquisitions of businesses.(b)Excludes sales from other sources.
(c)Includes property sales, revisions of previous estimates and expiring leases.
Environmental Matters Knife River's construction materials and contracting operations are subject to regulation customary for such
operations, including federal, state and local environmental compliance and reclamation regulations. Except as to the issues described later,
Knife River believes it is in substantial compliance with these regulations. Individual permits applicable to Knife River's various operations
are managed largely by local operations, particularly as they relate to application, modification, renewal, compliance and reporting
procedures.
Knife River's asphalt and ready-mixed concrete manufacturing plants and aggregate processing plants are subject to the Clean Air Act and
the Clean Water Act requirements for controlling air emissions and water discharges. Some mining and construction activities also are
subject to these laws. In most of the states where Knife River operates, these regulatory programs have been delegated to state and local
Part I
MDU Resources Group, Inc. Form 10-K 17
regulatory authorities. Knife River's facilities also are subject to the RCRA as it applies to the management of hazardous wastes and
underground storage tank systems. These programs also have generally been delegated to the state and local authorities in the states where
Knife River operates. Knife River's facilities must comply with requirements for managing wastes and underground storage tank systems.
Some Knife River activities are directly regulated by federal agencies. For example, certain in-water mining operations are subject to
provisions of the Clean Water Act that are administered by the Army Corps. Knife River has several such operations, including gravel bar
skimming and dredging operations, and Knife River has the associated permits as required. The expiration dates of these permits vary, with
five years generally being the longest term.
Knife River's operations are also occasionally subject to the ESA. For example, land use regulations often require environmental studies,
including wildlife studies, before a permit may be granted for a new or expanded mining facility or an asphalt or concrete plant. If
endangered species or their habitats are identified, ESA requirements for protection, mitigation or avoidance apply. Endangered species
protection requirements are usually included as part of land use permit conditions. Typical conditions include avoidance, setbacks,
restrictions on operations during certain times of the breeding or rearing season, and construction or purchase of mitigation habitat. Knife
River's operations also are subject to state and federal cultural resources protection laws when new areas are disturbed for mining operations
or processing plants. Land use permit applications generally require that areas proposed for mining or other surface disturbances be
surveyed for cultural resources. If any are identified, they must be protected or managed in accordance with regulatory agency requirements.
The most comprehensive environmental permit requirements are usually associated with new mining operations, although requirements vary
widely from state to state and even within states. In some areas, land use regulations and associated permitting requirements are minimal.
However, some states and local jurisdictions have very demanding requirements for permitting new mines. Environmental impact reports are
sometimes required before a mining permit application can be considered for approval. These reports can take up to several years to
complete. The report can include projected impacts of the proposed project on air and water quality, wildlife, noise levels, traffic, scenic
vistas and other environmental factors. The reports generally include suggested actions to mitigate the projected adverse impacts.
Provisions for public hearings and public comments are usually included in land use permit application review procedures in the counties
where Knife River operates. After taking into account environmental, mine plan and reclamation information provided by the permittee as
well as comments from the public and other regulatory agencies, the local authority approves or denies the permit application. Denial is
rare, but land use permits often include conditions that must be addressed by the permittee. Conditions may include property line setbacks,
reclamation requirements, environmental monitoring and reporting, operating hour restrictions, financial guarantees for reclamation, and
other requirements intended to protect the environment or address concerns submitted by the public or other regulatory agencies.
Knife River has been successful in obtaining mining and other land use permit approvals so sufficient permitted reserves are available to
support its operations. For mining operations, this often requires considerable advanced planning to ensure sufficient time is available to
complete the permitting process before the newly permitted aggregate reserve is needed to support Knife River's operations.
Knife River's Gascoyne surface coal mine last produced coal in 1995 but continues to be subject to reclamation requirements of the
Surface Mining Control and Reclamation Act, as well as the North Dakota Surface Mining Act. Portions of the Gascoyne Mine remain under
reclamation bond until the 10-year revegetation liability period has expired. A portion of the original permit has been released from bond
and additional areas are currently in the process of having the bond released. Knife River's intention is to request bond release as soon as it
is deemed possible.
Knife River did not incur any material environmental expenditures in 2018 and, except as to what may be ultimately determined with regard
to the issues described in the following paragraph, Knife River does not expect to incur any material expenditures related to environmental
compliance with current laws and regulations through 2021.
In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a commercial property site,
acquired by Knife River - Northwest in 1999, and part of the Portland, Oregon, Harbor Superfund Site. For more information, see Item 8 -
Note 19.
Mine Safety The Dodd-Frank Act requires disclosure of certain mine safety information. For more information, see Item 4 - Mine Safety
Disclosures.
Part I
18 MDU Resources Group, Inc. Form 10-K
Construction Services
General MDU Construction Services provides inside and outside specialty contracting services. Its outside services include design,
construction and maintenance of overhead and underground electrical distribution and transmission lines, substations, external lighting,
traffic signalization, and gas pipelines, as well as utility excavation and the manufacture and distribution of transmission line construction
equipment. Its inside services include design, construction and maintenance of electrical and communication wiring and infrastructure, fire
suppression systems, and mechanical piping and services. This segment also constructs and maintains renewable energy projects. These
specialty contracting services are provided to utilities and large manufacturing, commercial, industrial, institutional and government
customers.
Construction and maintenance crews are active year round. However, activity in certain locations may be seasonal in nature due to the
effects of weather.
MDU Construction Services operates a fleet of owned and leased trucks and trailers, support vehicles and specialty construction equipment,
such as backhoes, excavators, trenchers, generators, boring machines and cranes. In addition, as of December 31, 2018, MDU Construction
Services owned or leased facilities in 18 states. This space is used for offices, equipment yards, manufacturing, warehousing, storage and
vehicle shops.
MDU Construction Services’ backlog at December 31 was as follows:
2018 2017 2016
(In millions)
Inside specialty contracting $814 $625 $435
Outside specialty contracting 125 83 40
$939 $708 $475
The increase in backlog at December 31, 2018, compared to backlog at December 31, 2017, was primarily attributable to an increase in
projects from all revenue streams based on customer demand. Backlog increases with awards of new contracts and decreases as work is
performed on existing contracts. MDU Construction Services expects to complete a significant amount of the backlog at December 31,
2018, during the next 12 months.
MDU Construction Services’ backlog is comprised of the anticipated revenues from the uncompleted portion of services to be performed
under job-specific contracts. A project is included in backlog when a contract is awarded and agreement on contract terms has been
reached. However, backlog does not contain contracts for time and material projects that a fixed amount cannot be determined. Backlog is
comprised of: (a) original contract amounts, (b) change orders for which customers have approved, (c) pending change orders expected to
receive confirmation in the ordinary course of business and (d) claim amounts that have been made against customers for which are
determined to have a legal basis under existing contractual arrangements and as to which recovery is considered to be probable. Such claim
amounts were immaterial for all periods presented. Backlog may be subject to delay, default or cancellation at the election of the
customers. Historically, cancellations have not had a material adverse effect on backlog. Due to the nature of its contractual arrangements,
in many instances MDU Construction Services' customers are not committed to the specific volumes of services to be purchased under a
contract, but rather MDU Construction Services is committed to perform these services if and to the extent requested by the customer.
Therefore, there can be no assurance as to the customers' requirements during a particular period or that such estimates, or backlog
estimates in general, at any point in time are predictive of future revenues.
MDU Construction Services works with the National Electrical Contractors Association, the IBEW and other trade associations on hiring and
recruiting a qualified workforce.
Competition MDU Construction Services operates in a highly competitive business environment. Most of MDU Construction Services' work is
obtained on the basis of competitive bids or by negotiation of either cost-plus or fixed-price contracts. The workforce and equipment are
highly mobile, providing greater flexibility in the size and location of MDU Construction Services' market area. Competition is based
primarily on price and reputation for quality, safety and reliability. The size and location of the services provided, as well as the state of the
economy, will be factors in the number of competitors that MDU Construction Services will encounter on any particular project. MDU
Construction Services believes that the diversification of the services it provides, the markets it serves throughout the United States and the
management of its workforce will enable it to effectively operate in this competitive environment.
Utilities and independent contractors represent the largest customer base for this segment. Accordingly, utility and subcontract work
accounts for a significant portion of the work performed by MDU Construction Services and the amount of construction contracts is
dependent to a certain extent on the level and timing of maintenance and construction programs undertaken by customers. MDU
Construction Services relies on repeat customers and strives to maintain successful long-term relationships with these customers.
Environmental Matters MDU Construction Services' operations are subject to regulation customary for the industry, including federal, state
and local environmental compliance. MDU Construction Services believes it is in substantial compliance with these regulations.
Part I
MDU Resources Group, Inc. Form 10-K 19
The nature of MDU Construction Services' operations is such that few, if any, environmental permits are required. Operational convenience
supports the use of petroleum storage tanks in several locations, which are permitted under state programs authorized by the EPA. MDU
Construction Services has no ongoing remediation related to releases from petroleum storage tanks. MDU Construction Services' operations
are conditionally exempt small-quantity waste generators, subject to minimal regulation under the RCRA. Federal permits for specific
construction and maintenance jobs that may require these permits are typically obtained by the hiring entity, and not by MDU Construction
Services.
MDU Construction Services did not incur any material environmental expenditures in 2018 and does not expect to incur any material capital
expenditures related to environmental compliance with current laws and regulations through 2021.
Part I
20 MDU Resources Group, Inc. Form 10-K
Item 1A. Risk Factors
The Company's business and financial results are subject to a number of risks and uncertainties, including those set forth below and in
other documents that it files with the SEC. The factors and the other matters discussed herein are important factors that could cause actual
results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this
document. If any of the risks described below actually occur, the Company's business, prospects, financial condition or financial results
could be materially harmed.
Economic Risks
The Company is subject to government regulations that may delay and/or have a negative impact on its business and its results of operations and
cash flows. Statutory and regulatory requirements also may limit another party's ability to acquire the Company or impose conditions on an
acquisition of or by the Company.
The Company's electric and natural gas transmission and distribution businesses are subject to comprehensive regulation by federal, state
and local regulatory agencies with respect to, among other things, allowed rates of return and recovery of investment and cost, financing,
rate structures, customer service, health care coverage and cost, income taxes, property and other taxes, franchises; recovery of purchased
power and purchased natural gas costs; construction and siting of generation and transmission facilities. These governmental regulations
significantly influence the Company's operating environment and may affect its ability to recover costs from its customers. The Company is
unable to predict the impact on operating results from future regulatory activities of any of these agencies. Changes in regulations or the
imposition of additional regulations could have an adverse impact on the Company's results of operations and cash flows.
There can be no assurance that applicable regulatory commissions will determine that the Company's electric and natural gas transmission
and distribution businesses' costs have been prudent, which could result in disallowance of costs. Also, the regulatory process for approving
rates for these businesses may not allow us full recovery of the costs of providing services or a return on the Company's invested capital.
Changes in regulatory requirements or operating conditions may require early retirement of certain assets. While regulation typically provides
relief for these types of retirements, there is no assurance that regulators will allow full recovery of all remaining costs, which could leave
stranded asset costs. Rising fuel costs could increase the risk that the utility businesses will not be able to fully recover those fuel costs
from customers.
Approval from a number of federal and state regulatory agencies would need to be obtained by any potential acquirer of the Company, as
well as for acquisitions by the Company. The approval process could be lengthy and the outcome uncertain, which may deter potential
acquirers from approaching the Company or impact the Company's ability to pursue acquisitions.
Economic volatility affects the Company's operations, as well as the demand for its products and services.
Unfavorable economic conditions can negatively affect the level of public and private expenditures on projects and the timing of these
projects which, in turn, can negatively affect the demand for the Company's products and services, primarily at the Company's construction
businesses. The level of demand for construction products and services could be adversely impacted by the economic conditions in the
industries the Company serves, as well as in the general economy. State and federal budget issues affect the funding available for
infrastructure spending.
Economic conditions and population growth affect the electric and natural gas distribution businesses' growth in service territory, customer
base and usage demand. Economic volatility in the markets served, along with economic conditions such as increased unemployment which
could impact the ability of our customers to make payments, could adversely affect the Company's results of operations, cash flows and
asset values. Further, any material decreases in customers' energy demand, for economic or other reasons, could have a material adverse
impact on the Company's earnings and results of operations.
The Company's operations involve risks that may result from catastrophic events.
The Company's operations, particularly those related to natural gas and electric transmission and distribution, include a variety of inherent
hazards and operating risks, such as product leaks, explosions, mechanical failures, vandalism, fires, acts of terrorism and acts of war,
which could result in loss of human life; personal injury; property damage; environmental pollution; impairment of operations; and
substantial financial losses. The Company maintains insurance against some, but not all, of these risks and losses. A significant incident
could also increase regulatory scrutiny and result in penalties and higher amounts of capital expenditures and operational costs. Losses not
fully covered by insurance could have a material effect on the Company’s financial position, results of operations and cash flows.
A disruption of the regional electric transmission grid or interstate natural gas infrastructure could negatively impact our business and
reputation. Because the Company's electric and natural gas utility and pipeline systems are part of larger interconnecting systems, a
disruption could result in a significant decrease in revenues and system repair costs which could have a material impact on the Company's
financial position, results of operations and cash flows.
The Company is subject to capital market and interest rate risks.
The Company's operations, particularly its electric and natural gas transmission and distribution businesses, require significant capital
investment. Consequently, the Company relies on financing sources and capital markets as sources of liquidity for capital requirements not
satisfied by its cash flows from operations. If the Company is not able to access capital at competitive rates, the ability to implement its
business plans, make capital expenditures or pursue acquisitions that the Company would otherwise rely on for future growth may be
adversely affected. Market disruptions may increase the cost of borrowing or adversely affect the Company's ability to access one or more
financial markets. Such disruptions could include:
•A significant economic downturn.
•The financial distress of unrelated industry leaders in the same line of business.
•Deterioration in capital market conditions.
•Turmoil in the financial services industry.
•Volatility in commodity prices.
•Terrorist attacks.
•Cyberattacks.
The issuance of a substantial amount of the Company's common stock, whether issued in connection with an acquisition or otherwise, or the
perception that such an issuance could occur, could have a dilutive effect on shareholders and/or may adversely affect the market price of
the Company's common stock. Higher interest rates on borrowings could also have an adverse effect on the Company's operating results.
Financial market changes could impact the Company’s pension and postretirement benefit plans and obligations.
The Company has pension and postretirement defined benefit plans for some of its employees and former employees. Assumptions regarding
future costs, returns on investments, interest rates, and other actuarial assumptions have a significant impact on the funding requirements
relating to these plans. Changes in economic indicators, such as consumer spending, inflation data, interest rate changes, political
developments and threats of terrorism, among other things, can create volatility in the financial markets. Deteriorating financial market
conditions could change these estimates and assumptions and negatively affect the value of assets held in the Company's pension and other
postretirement benefit plans and may increase the amount and accelerate the timing of required funding contributions for those plans.
Significant changes in energy prices could negatively affect the Company's businesses.
Fluctuations in oil, NGL and natural gas production and prices; fluctuations in commodity price basis differentials; supplies of domestic and
foreign oil, NGL and natural gas; political and economic conditions in oil-producing countries; actions of the Organization of Petroleum
Exporting Countries; and other external factors impact the development of natural gas supplies and the expansion and operation of natural
gas pipeline systems. Prolonged depressed prices for oil, NGL and natural gas could negatively affect the growth, results of operations, cash
flows and asset values of the Company's pipeline and midstream business.
If oil and natural gas prices increase significantly, customer demand for utility, pipeline and midstream, and construction materials could
decline, which could have a material impact on the Company's results of operations and cash flows. While the Company has fuel clause
recovery mechanisms for its utility operations in most of the states in which it operates, higher utility fuel costs could significantly impact
results of operations if such costs are not recovered. Delays in the collection of utility fuel cost recoveries, as compared to expenditures for
fuel purchases, could have a negative impact on the Company's cash flows. High oil prices also affect the cost and demand for asphalt
products and related contracting services. Low commodity prices could have a positive impact on sales but could negatively impact oil and
natural gas production activities and subsequently the Company's pipeline and construction revenues in energy producing states in which
the Company operates.
Part I
MDU Resources Group, Inc. Form 10-K 21
Reductions in the Company's credit ratings could increase financing costs.
There is no assurance that the Company's current credit ratings, or those of its subsidiaries, will remain in effect or that a rating will not be
lowered or withdrawn by a rating agency. Events affecting the Company's financial results may impact its cash flows and credit metrics,
potentially resulting in a change in the Company's credit ratings. The Company's credit ratings may also change as a result of the differing
methodologies or changes in the methodologies used by the rating agencies. A downgrade in credit ratings could lead to higher borrowing
costs.
Increasing costs associated with health care plans may adversely affect the Company's results of operations.
The Company's self-insured costs of health care benefits for eligible employees continues to increase. Increasing quantities of large
individual health care claims and an overall increase in total health care claims could have an adverse impact on operating results, financial
position and liquidity. Legislation related to health care could also change the Company's benefit program and costs.
The Company is exposed to risk of loss resulting from the nonpayment and/or nonperformance by the Company's customers and counterparties.
If the Company's customers or counterparties experience financial difficulties, the Company could experience difficulty in collecting
receivables. Nonpayment and/or nonperformance by the Company's customers and counterparties, particularly customers and counterparties
of the Company’s construction materials and contracting and construction services businesses for large construction projects, could have a
negative impact on the Company's results of operations and cash flows. The Company could also have indirect credit risk from participating
in energy markets such as MISO in which credit losses are socialized to all participants.
Changes in tax law may negatively affect the Company's business.
The TCJA significantly reformed the Internal Revenue Code of 1986, as amended. The TCJA, among other things, includes reductions to
United States federal tax rates, repeals the domestic production deduction, disallows regulated utility property for immediate expensing, and
modifies or repeals many other business deductions and credits. Any future guidance, regulation and interpretations to the Internal Revenue
Code could have an adverse impact on the Company.
Other changes to federal and state tax laws have the ability to benefit or adversely affect the Company's earnings and customer costs.
Significant changes to corporate tax rates could result in the impairment of deferred tax assets that are established based on existing law at
the time of deferral. Changes to the value of various tax credits could change the economics of resources and the resource selection for the
electric generation business. Regulation incorporates changes in tax law into the rate-setting process for the regulated energy delivery
businesses and therefore could create timing delays before the impact of changes are realized.
The Company's operations could be negatively impacted by import tariffs and/or other government mandates.
The Company operates in or provides services to capital intensive industries in which federal trade policies could significantly impact the
availability and cost of materials. Imposed and proposed tariffs could significantly increase the prices and delivery lead times on raw
materials and finished products that are critical to the Company and its customers, such as aluminum and steel. Prolonged lead times on
the delivery of raw materials and further tariff increases on raw materials and finished products could have a material adverse effect on the
Company's business, financial condition and results of operations.
Operational Risks
Significant portions of the Company’s natural gas pipelines and power generation and transmission facilities are aging. The aging infrastructure may
require significant additional maintenance or replacement that could adversely affect the Company’s results of operations.
The Company’s energy delivery infrastructure is aging, which increases certain risks, including breakdown or failure of equipment, pipeline
leaks and fires developing from power lines. Aging infrastructure is more prone to failure which increases maintenance costs, unplanned
outages and the need to replace facilities. Even if properly maintained, reliability may ultimately deteriorate and negatively affect the
Company’s ability to serve its customers which could result in increased costs associated with regulatory oversight. The costs associated
with maintaining the aging infrastructure and capital expenditures for new or replacement infrastructure could cause rate volatility and/or
regulatory lag in some jurisdictions. If, at the end of its life, the investment costs of a facility have not been fully recovered the Company
may be adversely affected if commissions do not allow such costs to be recovered in rates. Such impacts of an aging infrastructure could
have a material adverse effect on the Company’s results of operations and cash flows.
Additionally, hazards from aging infrastructure could result in serious injury, loss of human life, significant damage to property,
environmental impacts, and impairment of operations, which in turn could lead to substantial losses. The location of distribution mains and
storage facilities near populated areas, including residential areas, business centers, industrial sites, and other public gathering places,
could increase the level of damages resulting from these risks. A major domestic incident involving natural gas systems could lead to
additional capital expenditures, increased regulation, and fines and penalties on natural gas utilities. The occurrence of any of these events
could adversely affect the Company’s results of operations, financial position, and cash flows.
Part I
22 MDU Resources Group, Inc. Form 10-K
The Company's utility and pipeline operations are subject to planning risks.
Most electric and natural gas utility investments, including natural gas pipeline investments, are made with the intent of being used for
decades. In particular, electric transmission and generation resources are planned well in advance of when they are placed into service
based upon resource plans using assumptions over the planning horizon; including sales growth, commodity prices, equipment and
construction costs, regulatory treatment, available technology and public policy. Public policy changes and technology advancements related
to areas such as energy efficient appliances and buildings, renewable and distributive electric generation and storage, carbon dioxide
emissions, electric vehicle penetration, and natural gas availability and cost may significantly impact the planning assumptions. Changes in
critical planning assumptions may result in excess generation, transmission and distribution resources creating increased per customer costs
and downward pressure on load growth. These changes could also result in a stranded investment if the Company is unable to fully recover
the costs of its investments.
The regulatory approval, permitting, construction, startup and/or operation of pipelines and power generation and transmission facilities may involve
unanticipated events, delays and unrecoverable costs.
The construction, startup and operation of pipelines and power generation and transmission facilities involve many risks, which may include
delays; breakdown or failure of equipment; inability to obtain required governmental permits and approvals; inability to obtain or renew
easements; public opposition; inability to complete financing; inability to negotiate acceptable equipment acquisition, construction, fuel
supply, off-take, transmission, transportation or other material agreements; changes in markets and market prices for power; cost increases
and overruns; the risk of performance below expected levels of output or efficiency; and the inability to obtain full cost recovery in regulated
rates. Such unanticipated events could negatively impact the Company's business, its results of operations and cash flows.
Additionally, operating or other costs required to comply with current pipeline safety regulations and potential new regulations under various
agencies could be significant. The regulations require verification of pipeline infrastructure records by pipeline owners and operators to
confirm the maximum allowable operating pressure of certain lines. Increased emphasis on pipeline safety and increased regulatory scrutiny
may result in penalties and higher costs of operations. If these costs are not fully recoverable from customers, they could have a material
adverse effect on the Company’s results of operations and cash flows.
The backlogs at the Company's construction materials and contracting and construction services businesses may not accurately represent future
revenue.
Backlog consists of the uncompleted portion of services to be performed under job-specific contracts. Contracts are subject to delay, default
or cancellation, and the contracts in the Company's backlog are subject to changes in the scope of services to be provided, as well as
adjustments to the costs relating to the applicable contracts. Backlog may also be affected by project delays or cancellations resulting from
weather conditions, external market factors and economic factors beyond the Company's control. Accordingly, there is no assurance that
backlog will be realized. The timing of contract awards, duration of large new contracts and the mix of services can significantly affect
backlog. Backlog at any given point in time may not accurately represent the revenue or net income that is realized in any period, and the
backlog as of the end of the year may not be indicative of the revenue and net income expected to be earned in the following year and
should not be relied upon as a stand-alone indicator of future revenues or net income.
Environmental and Regulatory Risks
The Company's operations could be adversely impacted by climate change.
Severe weather events, such as tornadoes, rain, ice and snow storms and high and low temperature extremes, do occur in regions in which
the Company operates and maintains infrastructure. However, climate change could possibly change the frequency and severity of these
weather events. Climate change may create physical and financial risks to the Company. Such risks could have an adverse effect on the
Company's financial condition, results of operations and cash flows.
Utility customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and
cooling represent the largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could
increase or decrease. Increased energy use by its utility customers due to weather may require the Company to invest in additional
generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather may result in
decreased revenues. Extreme weather conditions, such as uncommonly long periods of high or low ambient temperature, in general require
more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions
outside of the Company's service territory could also have an impact on revenues. The Company buys and sells electricity that might be
generated outside its service territory, depending upon system needs and market opportunities. Extreme temperatures may create high
energy demand and raise electricity prices, which could increase the cost of energy provided to customers.
Severe weather events may damage or disrupt the Company's electric and natural gas transmission and distribution facilities, which could
increase costs to repair facilities and restore service to customers. The cost of providing service could increase to the extent the frequency of
Part I
MDU Resources Group, Inc. Form 10-K 23
severe weather events increases because of climate change or otherwise. The Company may not recover all costs related to mitigating these
physical risks.
Severe weather may result in disruptions to the pipeline and midstream business's natural gas supply and transportation systems, potentially
increasing the cost of gas and the ability to procure gas to meet customer demand. These changes could result in increased maintenance
and capital costs, disruption of service, regulatory actions and lower customer satisfaction.
Increases in severe weather conditions or extreme temperature may cause infrastructure construction projects to be delayed or canceled and
limit resources available for such projects resulting in decreased revenue or increased project costs at the construction materials and
contracting and construction services businesses. In addition, drought conditions could restrict the availability of water supplies, inhibiting
the ability of the construction businesses to conduct operations.
Climate change may impact a region’s economic health, which could impact revenues at all of the Company's businesses. The Company's
financial performance is tied to the health of the regional economies served. The Company provides natural gas and electric utility service,
as well as construction materials and services, for some states and communities that are economically affected by the agriculture industry.
Increases in severe weather events or significant changes in temperature and precipitation patterns could adversely affect the agriculture
industry and, correspondingly, the economies of the states and communities affected by that industry.
The Company may also be subject to litigation related to climate change. Costs of such litigation could be significant, and an adverse
outcome could require substantial capital expenditures, changes in operations and possible payment of penalties or damages which could
affect the Company's results of operations and cash flows if the costs are not recoverable in rates.
The price of energy also has an impact on the economic health of communities. The cost of additional regulatory requirements to combat
climate change, such as regulation of carbon dioxide emissions under the Clean Air Act, or other environmental regulation could impact the
availability of goods and prices charged by suppliers, which would normally be borne by consumers through higher prices for energy and
purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect
the Company's ability to access capital markets or cause less than ideal terms and conditions.
The Company's operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans,
or expose the Company to environmental liabilities.
The Company is subject to environmental laws and regulations affecting many aspects of its operations, including air and water quality,
waste management and other environmental considerations. These laws and regulations can increase capital, operating and other costs;
cause delays as a result of litigation and administrative proceedings; and create compliance, remediation, containment, monitoring and
reporting obligations, particularly relating to electric generation and natural gas gathering, transmission and storage operations.
Environmental laws and regulations can also require the Company to install pollution control equipment at its facilities, clean up spills and
other contamination and correct environmental hazards, including payment of all or part of the cost to remediate sites where the Company's
past activities, or the activities of other parties, caused environmental contamination. These laws and regulations generally require the
Company to obtain and comply with a variety of environmental licenses, permits, inspections and other approvals and may cause the
Company to shut down existing facilities due to difficulties in assuring compliance or where the cost of compliance makes operation of the
facilities no longer economical. Although the Company strives to comply with all applicable environmental laws and regulations, public and
private entities and private individuals may interpret the Company's legal or regulatory requirements differently and seek injunctive relief or
other remedies against the Company. The Company cannot predict the outcome, financial or operational, of any such litigation or
administrative proceedings.
Existing environmental laws and regulations may be revised and new laws and regulations seeking to protect the environment may be
adopted or become applicable to the Company. These laws and regulations could require the Company to limit the use or output of certain
facilities; restrict the use of certain fuels; retire and replace certain facilities; install pollution controls; remediate environmental impacts;
remove or reduce environmental hazards; or forego or limit the development of resources. Revised or new laws and regulations that increase
compliance costs or restrict operations, particularly if costs are not fully recoverable from customers, could have a material adverse effect on
the Company's results of operations and cash flows.
On April 17, 2015, the EPA published a rule, under the RCRA, for coal combustion residuals that regulates coal ash as a solid waste and
not a hazardous waste. Some of the Company's coal fired electric generating facilities are subject to this rule. Company facilities where
there are ash impoundments and landfills are conducting ground water evaluations and may need to implement projects to meet rule
requirements.
On August 15, 2014, the EPA published a rule under Section 316(b) of the Clean Water Act, establishing requirements for water intake
structures at existing steam electric generating facilities. The purpose of the rule is to reduce impingement and entrainment of fish and
Part I
24 MDU Resources Group, Inc. Form 10-K
other aquatic organisms at cooling water intake structures. The majority of the Company's electric generating facilities are either not subject
to the rule or have completed studies that project compliance expenditures are not material. The Lewis & Clark Station will complete a study
that will be submitted to the Montana DEQ by July 31, 2019, to be used in determining any required controls. It is unknown at this time
what controls may be required at this facility or if compliance costs will be material. The installation schedule for any required controls
would be established with the permitting agency after the study is completed.
Initiatives to reduce GHG emissions could adversely impact the Company's operations.
Concern that GHG emissions are contributing to global climate change has led to international, federal and state legislative and regulatory
proposals to reduce or mitigate the effects of GHG emissions. The Company’s primary GHG emission is carbon dioxide from fossil fuels
combustion at Montana-Dakota's electric generating facilities, particularly its coal-fired facilities. Approximately 46 percent of Montana-
Dakota's owned generating capacity and approximately 79 percent of the electricity it generated in 2018 was from coal-fired facilities.
On October 23, 2015, the EPA published the Clean Power Plan rule that requires existing fossil fuel-fired electric generating facilities to
reduce carbon dioxide emissions. On February 9, 2016, however, the United States Supreme Court granted an application for a stay of the
Clean Power Plan pending disposition of the applicants' petition for review in the D.C. Circuit Court and disposition of the applicants'
petition for a writ of certiorari if such a writ is sought. The EPA filed a motion with the D.C. Circuit Court on March 28, 2017, requesting
the Clean Power Plan's case be held in abeyance, which was granted. The D.C. Circuit Court has continued to issue orders holding the case
in abeyance and requiring the EPA to file ongoing status reports. In parallel, the EPA published a proposal on October 16, 2017, to repeal
the Clean Power Plan in its entirety and published the proposed Affordable Clean Energy rulemaking to revise the Clean Power Plan. The
proposed revised rule would require states to conduct a review of heat rate improvement projects that could be implemented at each
individual coal-fired electric generating facility and determine, using a multi-factor analysis, which projects a facility would need to
implement. The state would establish a standard of performance for carbon dioxide emissions for each facility based on the heat rate
improvement projects required to be implemented. Compliance costs will become clearer as the EPA completes new rulemaking.
On January 14, 2015, the federal government announced a goal to reduce methane emissions from the oil and natural gas industry by 40 to
45 percent below 2012 levels by 2025. On June 3, 2016, the EPA published a rule updating new-source performance standards for the oil
and natural gas industry. The rule builds on 2012 requirements to reduce volatile organic compound emissions from oil and natural gas
sources by establishing requirements to reduce methane emissions from previously regulated sources, as well as adding volatile organic
compound and methane requirements for sources previously not covered by the rule. WBI Energy is currently complying with the rules
impacting new and modified sources. In addition, on March 10, 2016, the EPA announced plans to reduce emissions from the oil and
natural gas industry by moving to regulate emissions from existing sources. On November 10, 2016, the EPA issued an Information
Collection Request to oil and gas facility operators, including WBI Energy, to begin the process of existing source rule development. On
March 7, 2017, the EPA published notice of withdrawal of the Information Collection Request.
On September 15, 2016, the Washington DOE issued a Clean Air Rule that requires carbon dioxide emission reductions from various
industries in the state, including emissions from the combustion of natural gas supplied to end-use customers by natural gas distribution
companies, such as Cascade. In 2017, the rule requires Cascade to hold carbon dioxide emissions to a baseline, equal to the average
emissions in 2012 to 2016. Beginning in 2018, annual carbon dioxide emissions are reduced by an additional 1.7 percent of the baseline
from the previous year's emissions. Compliance for natural gas suppliers is to be achieved through purchasing emissions credits from
projects located within the state of Washington and, to a limited and declining extent, out-of-state allowances. Purchasing emissions credits
and allowances will increase operating costs for Cascade. If Cascade is not able to receive timely and full recovery of compliance costs from
its customers, such costs could adversely impact the results of its operations. On September 27, 2016 and September 30, 2016, Cascade
and three other natural gas distribution utility companies jointly filed complaints in the United States District Court for the Eastern District
of Washington and the Thurston County Superior Court, respectively, asking the courts to deem the rule invalid. The companies asserted
that the Washington DOE undertook this rulemaking without the requisite statutory authority. On December 15, 2017, the Thurston County
Superior Court vacated the Clean Air Rule and Washington DOE suspended the rule’s compliance obligations on December 21, 2017. On
May 16, 2018, Washington DOE appealed the lower court ruling to the Supreme Court for the State of Washington and oral argument is
scheduled for March 19, 2019. Litigation in the United States District Court for the Eastern District of Washington continues to be held in
abeyance.
Treaties, legislation or regulations to reduce GHG emissions in response to climate change may be adopted that affect the Company's utility
operations by requiring additional energy conservation efforts or renewable energy sources, limiting emissions, imposing carbon taxes or
other compliance costs; as well as other mandates that could significantly increase capital expenditures and operating costs or reduce
demand for the Company's utility services. If the Company’s utility operations do not receive timely and full recovery of GHG emission
compliance costs from customers, then such costs could adversely impact the results of its operations and cash flows. Significant
reductions in demand for the Company's utility services as a result of increased costs or emissions limitations could also adversely impact
the results of its operations and cash flows.
Part I
MDU Resources Group, Inc. Form 10-K 25
The Company monitors, analyzes and reports GHG emissions from its other operations as required by applicable laws and regulations. The
Company will continue to monitor GHG regulations and their potential impact on operations.
Due to the uncertain availability of technologies to control GHG emissions and the unknown obligations that potential GHG emission
legislation or regulations may create, the Company cannot determine the potential financial impact on its operations.
Other Risks
The Company's various businesses are seasonal and subject to weather conditions that can adversely affect the Company's operations, revenues and
cash flows.
The Company's results of operations can be affected by changes in the weather. Weather conditions influence the demand for electricity and
natural gas and affect the price of energy commodities. Utility operations have historically generated lower revenues when weather
conditions are cooler than normal in the summer and warmer than normal in the winter particularly in jurisdictions that do not have
decoupling mechanisms in place. Where decoupling mechanism are in place, there is no assurance the Company will continue to receive
such regulatory protection from adverse weather in future rates.
Adverse weather conditions, such as heavy or sustained rainfall or snowfall, storms, wind, and colder weather may affect the demand for
products and the ability to perform services at the construction businesses and affect ongoing operation and maintenance and construction
activities for the electric and natural gas transmission and distribution businesses. In addition, severe weather can be destructive, causing
outages, and/or property damage, which could require additional remediation costs. The Company could also be impacted by drought
conditions, which may restrict the availability of water supplies and inhibit the ability of the construction businesses to conduct operations.
As a result, unusually mild winters or summers or adverse weather conditions could negatively affect the Company's results of operations,
financial position and cash flows.
Competition exists in all of the Company's businesses.
The Company's businesses are subject to competition. Construction services' competition is based primarily on price and reputation for
quality, safety and reliability. Construction materials products are marketed under highly competitive conditions and are subject to
competitive forces such as price, service, delivery time and proximity to the customer. The electric utility and natural gas industries also
experience competitive pressures as a result of consumer demands, technological advances and other factors. The pipeline and midstream
business competes with several pipelines for access to natural gas supplies and for gathering, transportation and storage business. New
acquisition opportunities are subject to competitive bidding environments which impacts prices the Company must pay to successfully
acquire new properties to grow its business. Competition could negatively affect the Company's results of operations, financial position and
cash flows.
The Company's operations may be negatively affected if it is unable to obtain, develop and retain key personnel and skilled labor forces.
The Company must attract, develop and retain executive officers and other professional, technical and skilled labor forces with the skills and
experience necessary to successfully manage, operate and grow the Company's businesses. Competition for these employees is high, and in
some cases competition for these employees is on a regional or national basis. A shortage in the supply of skilled personnel creates
competitive hiring markets and increased labor expenses, decreased productivity and potentially lost business opportunities. Additionally, if
the Company is unable to hire employees with the requisite skills, the Company may be forced to incur significant training expenses. As a
result, the Company's ability to maintain productivity, relationships with customers, competitive costs, and quality services is limited by the
ability to employ the necessary skilled personnel and could negatively affect the Company's results of operations, financial position and cash
flows.
The Company's construction materials and contracting and construction services businesses may be exposed to warranty claims.
The Company, particularly its construction businesses, may provide warranties guaranteeing the work performed against defects in
workmanship and material. If warranty claims occur, they may require the Company to re-perform the services or to repair or replace the
warranted item, at a cost to the Company and could also result in other damages if the Company is not able to adequately satisfy warranty
obligations. In addition, the Company may be required under contractual arrangements with customers to warrant any defects or failures in
materials the Company purchased from third parties. While the Company generally requires suppliers to provide warranties that are
consistent with those the Company provides to customers, if any of the suppliers default on their warranty obligations to the Company, the
Company may nonetheless incur costs to repair or replace the defective materials. Costs incurred as a result of warranty claims could
adversely affect the Company's results of operations, financial condition and cash flows.
The Company is a holding company and relies on cash from its subsidiaries to pay dividends.
The Company is a holding company as a result of the Holding Company Reorganization. Its investments in its subsidiaries comprise the
Company's primary assets. The Company depends on earnings, cash flows and dividends from its subsidiaries to pay dividends on its
common stock. The Company's subsidiaries are separate legal entities that have no obligation to pay any amounts due on its obligations or
Part I
26 MDU Resources Group, Inc. Form 10-K
to make funds available to pay dividends on common stock. Regulatory, contractual and legal limitations, as well as their capital
requirements, affect the ability of the subsidiaries to pay dividends to the Company and thereby could restrict or influence the Company's
ability or decision to pay dividends on its common stock which could adversely affect the Company's stock price.
Costs related to obligations under MEPPs could have a material negative effect on the Company's results of operations and cash flows.
Various operating subsidiaries of the Company participate in approximately 70 MEPPs for employees represented by certain unions. The
Company is required to make contributions to these plans in amounts established under numerous collective bargaining agreements
between the operating subsidiaries and those unions.
The Company may be obligated to increase its contributions to underfunded plans that are classified as being in endangered, seriously
endangered or critical status as defined by the Pension Protection Act of 2006. Plans classified as being in one of these statuses are
required to adopt RPs or FIPs to improve their funded status through increased contributions, reduced benefits or a combination of the two.
Based on available information, the Company believes that approximately 30 percent of the MEPPs to which it contributes are currently in
endangered, seriously endangered or critical status.
The Company may also be required to increase its contributions to MEPPs if the other participating employers in such plans withdraw from
the plans and are not able to contribute amounts sufficient to fund the unfunded liabilities associated with their participation in the plans.
The amount and timing of any increase in the Company's required contributions to MEPPs may also depend upon one or more factors
including the outcome of collective bargaining; actions taken by trustees who manage the plans; actions taken by the plans' other
participating employers; the industry for which contributions are made; future determinations that additional plans reach endangered,
seriously endangered or critical status; newly-enacted government law or regulations and the actual return on assets held in the plans;
among others. The Company could experience increased operating expenses as a result of required contributions to MEPPs, which could
have a material adverse effect on the Company's results of operations, financial position or cash flows.
In addition, pursuant to ERISA, as amended by MPPAA, the Company could incur a partial or complete withdrawal liability upon
withdrawing from a plan, exiting a market in which it does business with a union workforce or upon termination of a plan. The Company
could also incur additional withdrawal liability if its withdrawal from a plan is determined by that plan to be part of a mass withdrawal.
Information technology disruptions or cyberattacks could adversely impact the Company's operations.
The Company uses technology in substantially all aspects of its business operations and requires uninterrupted operation of information
technology systems and network infrastructure. While the Company has policies, procedures and processes in place designed to strengthen
and protect these systems, they may be vulnerable to failures or unauthorized access, including disaster recovery and backup systems, due
to hacking, human error, theft, sabotage, malicious software, acts of terrorism, acts of war, acts of nature or other causes. If these systems
fail or become compromised, and they are not recovered in a timely manner, the Company may be unable to fulfill critical business
functions. This may include interruption of electric generation, transmission and distribution facilities, natural gas storage and pipeline
facilities and facilities for delivery of construction materials or other products and services, any of which could have a material adverse
effect on the Company's reputation, business, cash flows and results of operations or subject the Company to legal or regulatory liabilities
and increased costs.
The Company’s accounting systems and its ability to collect information and invoice customers for products and services could also be
disrupted. If the Company’s operations were disrupted, it could result in decreased revenues or significant remediation costs that have a
material adverse effect on the Company's results of operations and cash flows. Additionally, because electric generation and transmission
systems and natural gas pipelines are part of interconnected systems with other operators’ facilities, a cyber-related disruption in another
operator’s system could negatively impact the Company's business.
The Company is subject to cyber security and privacy laws and regulations of many government agencies, including FERC and NERC. NERC
issues comprehensive regulations and standards surrounding the security of bulk power systems and is continually in the process of
updating these requirements as well as establishing new requirements with which the utility industry must comply. As these regulations
evolve, the Company will experience increased compliance costs and be at higher risk for violating these standards. Experiencing a
cybersecurity incident could cause the Company to be non-compliant with applicable laws and regulations, causing the Company to incur
costs related to legal claims or proceedings and regulatory fines or penalties.
The Company, through the ordinary course of business, requires access to sensitive customer, employee and Company data. While the
Company has implemented extensive security measures, a breach of its systems could compromise sensitive data and could go unnoticed
for some time. In addition, there has been an increase in the number and sophistication of cyber-attacks across all industries worldwide and
the threats are continually evolving. Such an event could result in negative publicity and reputational harm, remediation costs, legal claims
and fines that could have an adverse effect on the Company's financial results. Third-party service providers that perform critical business
Part I
MDU Resources Group, Inc. Form 10-K 27
functions for the Company or have access to sensitive information within the Company also may be vulnerable to security breaches and
information technology risks that could have an adverse effect on the Company.
The Company’s information systems experience on-going and often sophisticated cyber-attacks by a variety of sources with the apparent aim
to breach our cyber-defenses. As cyber-attacks continue to increase in frequency and sophistication, the Company may be unable to prevent
all such attacks in the future. The Company is continuously reevaluating the need to upgrade and/or replace systems and network
infrastructure. These upgrades and/or replacements could adversely impact operations by imposing substantial capital expenditures,
creating delays or outages, or experiencing difficulties transitioning to new systems. Systems implementation disruption and any other
information technology disruption, if not anticipated and appropriately mitigated, could have an adverse effect on the Company.
Other factors that could impact the Company's businesses.
The following are other factors that should be considered for a better understanding of the risks to the Company. These other factors may
materially negatively impact the Company's financial results in future periods.
•Acquisition, disposal and impairments of assets or facilities.
•Changes in operation, performance and construction of plant facilities or other assets.
•Changes in present or prospective generation.
•The availability of economic expansion or development opportunities.
•Population growth rates and demographic patterns.
•Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services.
•The cyclical nature of large construction projects at certain operations.
•Unanticipated project delays or changes in project costs, including related energy costs.
•Unanticipated changes in operating expenses or capital expenditures.
•Labor negotiations or disputes.
•Inability of the contract counterparties to meet their contractual obligations.
•Changes in accounting principles and/or the application of such principles to the Company.
•Changes in technology.
•Changes in legal or regulatory proceedings.
•Losses or costs relating to litigation.
•The inability to effectively integrate the operations and the internal controls of acquired companies.
Part I
28 MDU Resources Group, Inc. Form 10-K
Item 1B. Unresolved Staff Comments
The Company has no unresolved comments with the SEC.
Item 3. Legal Proceedings
For information regarding legal proceedings required by this item, see Item 8 - Note 19, which is incorporated herein by reference.
Item 4. Mine Safety Disclosures
For information regarding mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and
Item 104 of Regulation S-K, see Exhibit 95 to this Form 10-K, which is incorporated herein by reference.
Part II
MDU Resources Group, Inc. Form 10-K 29
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
The Company's common stock is listed on the New York Stock Exchange under the symbol "MDU."
As of December 31, 2018, the Company's common stock was held by approximately 11,300 stockholders of record.
The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. The Company has paid quarterly
dividends for more than 80 consecutive years with an increase in the payout amount for the last 28 consecutive years. The declaration and
payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by the Company's credit agreements,
federal and state laws, and applicable regulatory limitations. For more information on factors that may limit the Company's ability to pay
dividends, see Item 8 - Note 11.
On June 4, 2018, the Company completed an acquisition in which a portion of the consideration consisted of the unregistered issuance of
shares of the Company's common stock. On November 7, 2018, an additional amount of consideration was paid relating to this acquisition,
which included 7,662 shares of the Company's common stock with a fair value of approximately $193,000. For additional information
about this acquisition, see Item 8 - Note 3. The shares of common stock issued relating to this acquisition were issued in reliance upon the
exemption from registration provided by Section 4(a)(2) of the Securities Act, as the shares were issued to the owners of businesses
acquired in privately negotiated transactions not involving any public offering or solicitation.
The following table includes information with respect to the Company's purchase of equity securities:
ISSUER PURCHASES OF EQUITY SECURITIES
Period
(a)Total Numberof Shares(or Units)Purchased (1)
(b) Average Price Paidper Share(or Unit)
(c)Total Number of Shares(or Units) Purchasedas Part of PubliclyAnnounced Plansor Programs (2)
(d)Maximum Number (orApproximate Dollar Value) of Shares (or Units) that May Yet BePurchased Under thePlans or Programs (2)
October 1 through October 31, 2018 ————
November 1 through November 30, 2018 38,605 $26.55 ——
December 1 through December 31, 2018 ————
Total 38,605 ——
(1)Represents shares of common stock purchased on the open market in connection with annual stock grants made to the Company's non-employee directors.
(2)Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.
Item 6. Selected Financial Data
2018 2017 2016 2015 2014 2013
Selected Financial Data
Operating revenues (000's):
Electric $335,123 $342,805 $322,356 $280,615 $277,874 $257,260
Natural gas distribution 823,247 848,388 766,115 817,419 921,986 851,945
Pipeline and midstream 128,923 122,213 141,602 154,904 157,292 144,568
Construction materials and contracting 1,925,854 1,812,529 1,874,270 1,904,282 1,765,330 1,712,137
Construction services 1,371,453 1,367,602 1,073,272 926,427 1,119,529 1,039,839
Other 11,259 7,874 8,643 9,191 9,364 9,620
Intersegment eliminations (64,307)(58,060)(57,430)(78,786)(136,302)(95,201)
$4,531,552 $4,443,351 $4,128,828 $4,014,052 $4,115,073 $3,920,168
Operating income (loss) (000's):
Electric $65,148 $79,902 $67,929 $59,915 $61,515 $54,386
Natural gas distribution 72,336 84,239 66,166 54,974 68,185 79,910
Pipeline and midstream 36,128 36,004 42,864 30,218 46,500 20,070
Construction materials and contracting 141,426 143,230 178,753 148,312 87,243 92,037
Construction services 86,764 81,292 53,546 43,678 82,408 85,242
Other (79)(619)(349)(8,414)(5,370)(4,384)
Intersegment eliminations ———(2,942)(9,900)(7,176)
$401,723 $424,048 $408,909 $325,741 $330,581 $320,085
Earnings (loss) on common stock (000's):
Electric $47,000 $49,366 $42,222 $35,914 $36,731 $34,837
Natural gas distribution 37,732 32,225 27,102 23,607 30,484 37,656
Pipeline and midstream 28,459 20,493 23,435 13,250 24,666 7,701
Construction materials and contracting 92,647 123,398 102,687 89,096 51,510 50,946
Construction services 64,309 53,306 33,945 23,762 54,432 52,213
Other (761)(1,422)(3,231)(14,941)(7,386)(10,776)
Intersegment eliminations —6,849 6,251 5,016 (6,095)(4,307)
Earnings on common stock before income (loss)from discontinued operations 269,386 284,215 232,411 175,704 184,342 168,270
Income (loss) from discontinued operations, netof tax*2,932 (3,783)(300,354)(834,080)109,311 109,615
Loss from discontinued operations attributable tononcontrolling interest ——(131,691)(35,256)(3,895)(363)
$272,318 $280,432 $63,748 $(623,120)$297,548 $278,248
Earnings per common share before discontinuedoperations - diluted $1.38 $1.45 $1.19 $.90 $.96 $.89
Discontinued operations attributable to theCompany, net of tax .01 (.02)(.86)(4.10).59 .58
$1.39 $1.43 $.33 $(3.20)$1.55 $1.47
Common Stock Statistics
Weighted average common shares outstanding -diluted (000's)196,150 195,687 195,618 194,986 192,587 189,693
Dividends declared per common share $.7950 $.7750 $.7550 $.7350 $.7150 $.6950
Book value per common share $13.09 $12.44 $11.78 $12.83 $16.66 $15.01
Market price per common share (year end)$23.84 $26.88 $28.77 $18.32 $23.50 $30.55
Market price ratios:
Dividend payout**58%53%63%82%74%78%
Yield 3.4%2.9%2.7%4.1%3.1%2.3%
Market value as a percent of book value 182.1%216.1%244.2%142.8%141.1%203.5%
*Reflects oil and natural gas properties noncash write-downs of $315.3 million (after tax) in 2015 and fair value impairments of assets held for sale of $157.8 million(after tax) and $475.4 million (after tax) in 2016 and 2015, respectively.
**Based on continuing operations.
Part II
30 MDU Resources Group, Inc. Form 10-K
Item 6. Selected Financial Data (continued)
2018 2017 2016 2015 2014 2013
General
Total assets (000's)$6,988,110 $6,334,666 $6,284,467 $6,565,154 $7,805,405 $7,043,365
Total long-term debt (000's)$2,108,695 $1,714,853 $1,790,159 $1,796,163 $2,016,198 $1,773,050
Capitalization ratios:
Total equity 55%59%56%58%62%62%
Total debt 45 41 44 42 38 38
100%100%100%100%100%100%
Electric
Retail sales (thousand kWh)3,354,401 3,306,470 3,258,537 3,316,017 3,308,358 3,173,086
Electric system summer and firm purchasecontract ZRCs (Interconnected system)574.5 553.1 559.7 547.3 584.0 583.5
Electric system peak demand obligation, includingfirm purchase contracts, planning reserve marginrequirement (Interconnected system)537.2 530.2 559.7 547.3 522.4 508.3
All-time demand peak - kW(Interconnected system)611,542 611,542 611,542 611,542 582,083 573,587
Electricity produced (thousand kWh)2,840,353 2,630,640 2,626,763 1,898,160 2,519,938 2,430,001
Electricity purchased (thousand kWh)831,039 955,687 904,702 1,658,002 1,010,422 971,261
Average cost of electric fuel and purchased powerper kWh $.022 $.022 $.021 $.024 $.025 $.025
Natural Gas Distribution
Sales (Mdk)112,566 112,551 99,296 95,559 104,297 108,260
Transportation (Mdk)149,497 144,477 147,592 154,225 145,941 149,490
Pipeline and Midstream
Transportation (Mdk)351,498 312,520 285,254 290,494 233,483 178,598
Gathering (Mdk)14,882 16,064 20,049 33,441 38,372 40,737
Customer natural gas storage balance (Mdk)13,928 22,397 26,403 16,600 14,885 26,693
Construction Materials and Contracting
Sales (000's):
Aggregates (tons)29,795 28,213 27,580 26,959 25,827 24,713
Asphalt (tons)6,838 6,237 7,203 6,705 6,070 6,228
Ready-mixed concrete (cubic yards)3,518 3,548 3,655 3,592 3,460 3,223
Aggregate reserves (000's tons)1,014,431 965,036 989,084 1,022,513 1,061,156 1,083,376
Part II
MDU Resources Group, Inc. Form 10-K 31
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The Company operates with a two-platform business model. Its regulated energy delivery platform and its construction materials
and services platform are each comprised of different operating segments. Some of these segments experience seasonality related
to the industries in which they operate. The two-platform approach helps balance this seasonality and the risk associated with
each type of industry. Through its regulated energy delivery platform, the Company provides electric and natural gas services to
customers, generates, transmits and distributes electricity, and provides natural gas transportation, storage and gathering services.
These businesses are regulated by state public service commissions and/or the FERC. The construction materials and services
platform provides construction services to a variety of industries, including commercial, industrial and governmental, and provides
construction materials through aggregate mining and marketing of related products, such as ready-mixed concrete and asphalt.
The Company is organized into five reportable business segments. These business segments include: electric, natural gas
distribution, pipeline and midstream, construction materials and contracting, and construction services. The Company's business
segments are determined based on the Company's method of internal reporting, which generally segregates the strategic business
units due to differences in products, services and regulation. The internal reporting of these segments is defined based on the reporting and
review process used by the Company's chief executive officer.
The Company's strategy is to apply its expertise in the regulated energy delivery and construction materials and services businesses to
increase market share, increase profitability and enhance shareholder value through organic growth opportunities and strategic acquisitions.
The Company is focused on a disciplined approach to the acquisition of well-managed companies and properties.
The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial
paper facilities, revolving credit facilities and the issuance from time to time of debt and equity securities. For more information on the
Company's capital expenditures, see Liquidity and Capital Commitments.
On December 22, 2017, President Trump signed into law the TCJA making significant changes to the United States federal income tax
laws. Some of the more material changes from the TCJA that impacted the Company were reduced corporate tax rates, repeal of the
domestic production deduction and disallowance of immediate expensing for regulated utility property. The Company has reviewed the
impacts of the TCJA and is complying with all known tax rules and guidance. For additional information on the impacts of the TCJA, see
Item 8 - Note 13.
Part II
32 MDU Resources Group, Inc. Form 10-K
Consolidated Earnings Overview
The following table summarizes the contribution to the consolidated earnings by each of the Company's business segments.
Years ended December 31,2018 2017 2016
(In millions, except per share amounts)
Electric $47.0 $49.4 $42.2
Natural gas distribution 37.7 32.2 27.1
Pipeline and midstream 28.5 20.5 23.4
Construction materials and contracting 92.6 123.4 102.7
Construction services 64.3 53.3 33.9
Other (.7)(1.5)(3.2)
Intersegment eliminations —6.9 6.3
Earnings before discontinued operations 269.4 284.2 232.4
Income (loss) from discontinued operations, net of tax 2.9 (3.8)(300.4)
Loss from discontinued operations attributable to noncontrolling interest ——(131.7)
Earnings on common stock $272.3 $280.4 $63.7
Earnings per common share - basic:
Earnings before discontinued operations $1.38 $1.46 $1.19
Discontinued operations attributable to the Company, net of tax .01 (.02)(.86)
Earnings per common share - basic $1.39 $1.44 $.33
Earnings per common share - diluted:
Earnings before discontinued operations $1.38 $1.45 $1.19
Discontinued operations attributable to the Company, net of tax .01 (.02)(.86)
Earnings per common share - diluted $1.39 $1.43 $.33
2018 compared to 2017 The Company's consolidated earnings decreased $8.1 million.
The Company's earnings were positively impacted in 2018 as a result of the lower federal statutory tax rate, which was partially offset by the
absence of a $39.5 million tax benefit recorded in the fourth quarter of 2017 for the revaluation of the business's net deferred tax
liabilities. Both tax impacts were the result of the enactment of the TCJA, as further discussed in Item 8 - Note 13. Decreased earnings due
to lower returns on investments also offset the lower income tax rate. Also positively impacting the Company's earnings were higher outside
specialty contracting gross margins due to increased outside equipment sales and rentals at the construction services business, as well as a
$4.2 million income tax benefit relating to the reversal of a regulatory liability recorded in 2017 based on a FERC final accounting order
issued during the third quarter of 2018 at the pipeline and midstream business.
2017 compared to 2016 The Company's consolidated earnings increased $216.7 million.
The Company's earnings were positively impacted due to the absence in 2017 of a loss associated with the sale of the refining business in
June 2016 relating to discontinued operations, as well as an overall income tax benefit to the Company of $39.5 million primarily for the
revaluation of the Company's net deferred tax liabilities. Also contributing to the Company's increased earnings were higher inside and
outside specialty contracting margins driven by decreased costs and higher contracting workloads at the construction services business,
higher natural gas retail sales margins as a result of increased retail sales volumes at the natural gas distribution business and higher
electric retail sales margins at the electric business. These increases were partially offset by lower asphalt product and construction margins
driven by competitive pricing and unfavorable weather at the construction materials and contracting business and lower gathering and
processing revenues resulting from lower volumes due to the sale of the Pronghorn assets in January 2017 at the pipeline and midstream
business.
A discussion of key financial data from the Company's business segments follows.
Part II
MDU Resources Group, Inc. Form 10-K 33
Business Segment Financial and Operating Data
Following are key financial and operating data for each of the Company's business segments. Also included are highlights on key growth
strategies, projections and certain assumptions for the Company and its subsidiaries and other matters of the Company's business segments.
Many of these highlighted points are "forward-looking statements." For more information, see Part I - Forward-Looking Statements. There is
no assurance that the Company's projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer
to assumptions contained in this section, as well as the various important factors listed in Item 1A - Risk Factors. Changes in such
assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections.
For information pertinent to various commitments and contingencies, see Item 8 - Notes to Consolidated Financial Statements. For a
summary of the Company's business segments, see Item 8 - Note 15.
Electric and Natural Gas Distribution
Strategy and challenges The electric and natural gas distribution segments provide electric and natural gas distribution services to
customers, as discussed in Items 1 and 2 - Business Properties. Both segments strive to be a top performing utility company measured by
integrity, safety, employee satisfaction, customer service and shareholder return, while continuing to focus on providing safe, reliable and
competitively priced energy and related services to customers. The Company continues to monitor opportunities for these segments to
retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation,
transmission and distribution and natural gas systems, and through selected acquisitions of companies and properties at prices that will
provide stable cash flows and an opportunity to earn a competitive return on investment. The continued efforts to create operational
improvements and efficiencies across both segments promotes the Company's business integration strategy. The primary factors that impact
the results of these segments are the ability to earn authorized rates of return, the cost of natural gas, cost of electric fuel and purchased
power, weather, competitive factors in the energy industry, population growth and economic conditions in the segments' service areas.
The electric and natural gas distribution segments are subject to extensive regulation in the jurisdictions where they conduct operations with
respect to costs, timely recovery of investments and permitted returns on investment, as well as certain operational, system integrity and
environmental regulations. To assist in the reduction of regulatory lag with the increase in investments, tracking mechanisms have been
implemented in certain jurisdictions. Legislative and regulatory initiatives to increase renewable energy resources and reduce GHG
emissions could impact the price and demand for electricity and natural gas and result in the retirement of certain electric generating
facilities before they are fully depreciated. Although the current administration has slowed environmental regulations, the segments
continue to invest in facility upgrades to be in compliance with the existing and future regulations.
Tariff increases on steel and aluminum materials could negatively affect the segments' construction projects and maintenance work. The
Company continues to monitor the impact tariff increases will have on raw material costs. The natural gas distribution segment is also facing
increased lead times on delivery of certain raw materials used in pipeline projects. In addition to the effect of tariffs, long lead times are
attributable to increased demand for steel products from pipeline companies as they respond to the United States Department of
Transportation Pipeline System Safety and Integrity Plan. The Company continues to monitor the material lead times and is working with
manufacturers to proactively order such materials to help mitigate the extended lead times.
The ability to grow through acquisitions is subject to significant competition and acquisition premiums. In addition, the ability of the
segments to grow their service territory and customer base is affected by the economic environment of the markets served and competition
from other energy providers and fuels. The construction of any new electric generating facilities, transmission lines and other service
facilities is subject to increasing cost and lead time, extensive permitting procedures, and federal and state legislative and regulatory
initiatives, which will likely necessitate increases in electric energy prices.
Revenues are impacted by both customer growth and usage, the latter of which is primarily impacted by weather. Very cold winters increase
demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially
among residential and commercial customers. Average consumption among natural gas customers has tended to decline as more efficient
appliances and furnaces are installed, and as the Company has implemented conservation programs. Natural gas decoupling mechanisms in
certain jurisdictions have been implemented to largely mitigate the effect that would otherwise be caused by variations in volumes sold to
these customers due to weather and changing consumption patterns on the Company's distribution margins.
Earnings overview - The following information summarizes the performance of the electric segment.
Years ended December 31,2018 2017 2016
(Dollars in millions, where applicable)
Operating revenues $335.1 $342.8 $322.3
Electric fuel and purchased power 80.7 78.7 75.5
Taxes, other than income .7 .8 .6
Adjusted gross margin 253.7 263.3 246.2
Operating expenses:
Operation and maintenance 123.0 122.2 115.8
Depreciation, depletion and amortization 51.0 47.7 50.2
Taxes, other than income 14.5 13.5 12.3
Total operating expenses 188.5 183.4 178.3
Operating income 65.2 79.9 67.9
Other income 1.2 3.2 1.3
Interest expense 25.9 25.4 25.0
Income before income taxes 40.5 57.7 44.2
Income taxes (6.5)7.7 1.4
Net income 47.0 50.0 42.8
Loss/dividends on preferred stock —.6 .6
Earnings $47.0 $49.4 $42.2
Retail sales (million kWh):
Residential 1,196.6 1,153.5 1,132.5
Commercial 1,513.9 1,513.1 1,491.8
Industrial 551.0 539.9 544.2
Other 92.9 100.0 90.0
3,354.4 3,306.5 3,258.5
Average cost of electric fuel and purchased power per kWh $.022 $.022 $.021
Adjusted gross margin is a non-GAAP financial measure. For additional information and reconciliation of the non-GAAP adjusted gross
margin attributable to the electric segment, see the Non-GAAP Financial Measures section later in this Item.
2018 compared to 2017 Electric earnings decreased $2.4 million (5 percent) as a result of:
Adjusted gross margin: Decrease of $9.6 million, primarily due to lower operating revenues driven by the reserves against revenues in
certain jurisdictions for anticipated refunds to customers for lower income taxes due to the enactment of TCJA and a transmission formula
rate adjustment due to lower than anticipated project costs on the BSSE project recorded in the third quarter of 2018. Partially offsetting
the decreases to adjusted gross margin were the absence in 2018 of reserves related to tracker balances in prior years and increased
Part II
34 MDU Resources Group, Inc. Form 10-K
retail sales volumes of 1 percent to all major customer classes.
Operation and maintenance: Increase of $800,000, largely from higher contract services at certain generating stations. Partially offsetting
the increase were lower payroll-related costs.
Depreciation, depletion and amortization: Increase of $3.3 million as a result of increased plant balances.
Taxes, other than income: Increase of $1.0 million, primarily from higher property taxes in certain jurisdictions.
Other income: Decrease of $2.0 million, largely the result of lower returns on investments.
Interest expense: Comparable to the prior year.
Income taxes: Decrease of $14.2 million, largely due to the enactment of the TCJA reduced corporate tax rate, reduced income before
income taxes and the absence of $2.1 million of income tax expense in 2018 for the revaluation of nonutility net deferred tax assets in
2017, as discussed in Item 8 - Note 13. Partially offsetting these decreases were lower production tax credits. A portion of the reduction
in income taxes are being reserved against revenues, as previously discussed, resulting in a minimal impact on overall earnings.
2017 compared to 2016 Electric earnings increased $7.2 million (17 percent) as a result of:
Adjusted gross margin: Increase of $17.1 million, primarily from increased electric retail sales margins from the recovery of an additional
investment on the BSSE project, approved rate recovery in all jurisdictions and 2 percent higher retail sales volumes to commercial and
residential customers.
Operation and maintenance: Increase of $6.4 million, largely from higher payroll-related costs, material costs and contract services at
certain generating stations.
Depreciation, depletion and amortization: Decrease of $2.5 million, largely from lower depreciation rates implemented in conjunction
with regulatory recovery activity.
Taxes, other than income: Increase of $1.2 million, primarily from higher property taxes in certain jurisdictions.
Other income: Increase of $1.9 million, largely the result of higher returns on investments.
Interest expense: Comparable to the prior year.
Income taxes: Increase of $6.3 million, largely from increased income before income taxes and $2.1 million of income tax expense for
the revaluation of nonutility net deferred tax assets, as discussed in Item 8 - Note 13.
Part II
MDU Resources Group, Inc. Form 10-K 35
Earnings overview - The following information summarizes the performance of the natural gas distribution segment.
Years ended December 31,2018 2017 2016
(Dollars in millions, where applicable)
Operating revenues $823.2 $848.4 $766.1
Purchased natural gas sold 454.8 479.9 431.5
Taxes, other than income 28.5 30.0 26.5
Adjusted gross margin 339.9 338.5 308.1
Operating expenses:
Operation and maintenance 173.4 164.3 156.9
Depreciation, depletion and amortization 72.5 69.4 65.4
Taxes, other than income 21.7 20.5 19.6
Total operating expenses 267.6 254.2 241.9
Operating income 72.3 84.3 66.2
Other income .2 2.0 .6
Interest expense 30.7 31.2 30.4
Income before income taxes 41.8 55.1 36.4
Income taxes 4.1 22.8 9.2
Net income 37.7 32.3 27.2
Loss/dividends on preferred stock —.1 .1
Earnings $37.7 $32.2 $27.1
Volumes (MMdk)
Retail sales:
Residential 63.7 63.6 56.2
Commercial 44.4 44.3 38.9
Industrial 4.5 4.6 4.2
112.6 112.5 99.3
Transportation sales:
Commercial 2.2 2.0 1.8
Industrial 147.3 142.5 145.8
149.5 144.5 147.6
Total throughput 262.1 257.0 246.9
Average cost of natural gas, including transportation, per dk $4.04 $4.26 $4.35
Adjusted gross margin is a non-GAAP financial measure. For additional information and reconciliation of the non-GAAP adjusted gross
margin attributable to the natural gas distribution segment, see the Non-GAAP Financial Measures section later in this Item.
2018 compared to 2017 Natural gas distribution earnings increased $5.5 million (17 percent) as a result of:
Adjusted gross margin: Increase of $1.4 million, primarily due to increased retail sales margins, mainly the result of weather
normalization mechanisms in certain jurisdictions and conservation revenue, which offsets the conservation expense in operation and
maintenance expense. Also contributing to the retail sales margin increase were higher basic service charges as a result of increased retail
sales customers and rate design. These increases were partially offset by tax reform revenue impacts for refunds to customers as a result
of lower income taxes due to the enactment of TCJA and lower volumes in certain jurisdictions.
Operation and maintenance: Increase of $9.1 million, largely related to conservation expenses being recovered in revenue; contract
services, which includes the recognition of a non-recurring expense related to the approved WUTC general rate case settlement in the
second quarter 2018; and higher payroll-related costs.
Depreciation, depletion and amortization: Increase of $3.1 million, primarily as a result of increased plant balances offset in part by lower
depreciation rates implemented in certain jurisdictions.
Taxes, other than income: Increase of $1.2 million due to higher property taxes in certain jurisdictions.
Other income: Decrease of $1.8 million, primarily the result of lower returns on investments.
Interest expense: Comparable to the prior year.
Income taxes: Decrease of $18.7 million, largely due to the enactment of the TCJA reduced corporate tax rate, as well as the absence of
$4.3 million income tax expense related to the 2017 revaluation of nonutility net deferred tax assets, as discussed in Item 8 - Note 13,
Part II
36 MDU Resources Group, Inc. Form 10-K
and reduced income before income taxes. A portion of the reduction in income taxes are being reserved against revenues or passed back
to customers, as previously discussed, resulting in a minimal impact on overall earnings.
2017 compared to 2016 Natural gas distribution earnings increased $5.1 million (19 percent) as a result of:
Adjusted gross margin: Increase of $30.4 million, primarily due to increased retail sales margins as a result of increased retail sales
volumes of 13 percent across all customer classes from colder weather in all jurisdictions, offset in part by weather normalization in
certain jurisdictions and 2 percent customer growth. Also contributing to the increases were approved final and interim rate increases.
Operation and maintenance: Increase of $7.4 million, primarily from increased payroll-related costs and material costs.
Depreciation, depletion and amortization: Increase of $4.0 million as a result of increased plant balances.
Taxes, other than income: Increase of $900,000 due to higher property taxes in certain jurisdictions.
Other income: Increase of $1.4 million as a result of higher returns on investments.
Interest expense: Increase of $800,000 due to increased debt balances.
Income taxes: Increase of $13.6 million, largely the result of increased income before income taxes, as well as an additional $4.3 million
income tax expense for the revaluation of nonutility net deferred tax assets, as discussed in Item 8 - Note 13.
Outlook The Company expects these segments will grow rate base by approximately 5 percent annually over the next five years on a
compound basis. This growth projection is on a much larger base, having grown rate base at a record pace of 12 percent compounded
annually over the past five-year period. Operations are spread across eight states where the Company expects customer growth to be higher
than the national average. The Company expects its customer base to grow by 1 percent to 2 percent per year. This customer growth, along
with system upgrades and replacements needed to supply safe and reliable service, will require investments in new electric generation and
transmission and natural gas systems.
In November 2017, the NDPSC approved the advance determination of prudence for the purchase of the Thunder Spirit Wind farm
expansion in southwest North Dakota. Construction of the Thunder Spirit Wind farm expansion began in May 2018 and on October 31,
2018, the Company finalized the purchase and placed it into service. With the addition of the expansion, the total Thunder Spirit Wind farm
generation capacity is approximately 155 MW and increased the Company's electric generation portfolio to approximately 27 percent
renewables based on nameplate ratings. The Company's integrated resource plans filed in North Dakota and Montana in 2017 include
additional generation projects in the 2025 timeframe.
In June 2016, the Company, along with a partner, began construction on the BSSE project. The estimated capital investment for this
project has been updated to approximately $130 million. All necessary easements have been secured and construction is complete. The
Company began bringing the project on-line on February 5, 2019. In addition, the Company is also expecting to receive a continuation of
the return on the project throughout the year.
On February 19, 2019, the Company announced that it intends to retire three aging coal-fired electric generation units within the next three
years due to the fact that the plants are no longer expected to be cost competitive. The retirements are expected to be in late 2020 for
Lewis & Clark station in Sidney, Montana, and in late 2021 for units 1 and 2 at Heskett station in Mandan, North Dakota. These dates may
be impacted by the Company's coal supplier's pending bankruptcy proceeding. In addition, the Company announced that it intends to
construct a new simple-cycle natural gas combustion turbine peaking unit at the existing plant site in Mandan, North Dakota.
The Company continues to be focused on the regulatory recovery of its investments. Since January 1, 2018, these segments have
implemented rate increases, as well as system integrity mechanisms, in Minnesota, Montana, North Dakota, Washington and before the
FERC. The Company files for rate adjustments to seek recovery of operating costs and capital investments, as well as reasonable returns as
allowed by regulators. The Company's most recent cases by jurisdiction are discussed in Item 8 - Note 18.
With the enactment of the TCJA, the state regulators in jurisdictions where the segments operate requested companies submit plans for the
estimated impact of the TCJA. The segments determined the use of the deferral method of accounting for the revaluation of its regulated
deferred tax assets and liabilities was appropriate. As such, the Company recorded a regulatory liability for the excess deferred income taxes
that related to the effect of the change in tax rates on its regulated deferred tax assets and liabilities in the fourth quarter of 2017. For the
twelve months ended December 31, 2018, the Company reserved an additional regulatory liability of approximately $18.5 million, which is
an offset to the Company's revenues, as previously discussed. The additional reserves were calculated by completing a revenue requirement
calculation in each state where the Company thought it was probable that the refund of tax savings would be returned to the Company's
customers, or based on calculations or amounts prescribed by the commissions. The Company has been working on various rate cases with
the state regulators relating to the impacts of the TCJA. A majority of these rate cases have been settled with new rates being implemented
in 2018 or upcoming in 2019. For further details on the status of implementing the new rates, as well as the status on open rate cases, see
Part II
MDU Resources Group, Inc. Form 10-K 37
Item 8 - Note 18. Due to not being able to immediately expense utility property for tax purposes, the segments' cash flows are negatively
impacted.
Part II
38 MDU Resources Group, Inc. Form 10-K
Pipeline and Midstream
Strategy and challenges The pipeline and midstream segment provides natural gas transportation, gathering and underground storage
services, as discussed in Items 1 and 2 - Business Properties. The segment focuses on utilizing its extensive expertise in the design,
construction and operation of energy infrastructure and related services to increase market share and profitability through optimization of
existing operations, organic growth and investments in energy-related assets within or in close proximity to its current operating areas. The
segment focuses on the continual safety and reliability of its systems, which entails building and maintaining safe natural gas pipelines and
facilities. The segment continues to evaluate growth opportunities including the expansion of existing storage, gathering and transmission
facilities; incremental pipeline projects to expand pipeline capacity; and expansion of energy-related services leveraging on its core
competencies.
The segment is exposed to energy price volatility which is impacted by the fluctuations in pricing, production and basis differentials of the
energy market's commodities. Legislative and regulatory initiatives to increase pipeline safety regulations and reduce methane emissions
could also impact the price and demand for natural gas.
Tariff increases on steel and aluminum materials could negatively affect the segment's construction projects and maintenance work. The
Company continues to monitor the impact tariff increases will have on raw material costs. The segment experiences extended lead times on
raw materials that are critical to the segment's construction and maintenance work. Long lead times on materials could delay maintenance
work and project construction potentially causing lost revenues and/or increased costs. The Company continues to proactively monitor and
plan for the material lead times, as well as work with manufacturers and suppliers to help mitigate the extended lead times.
The pipeline and midstream segment is subject to extensive regulation including certain operational, system integrity and environmental
regulations, as well as various permit terms and operational compliance conditions. The segment is charged with the ongoing process of
reviewing existing permits and easements, as well as securing new permits and easements as necessary to meet current demand and future
growth opportunities. Exposure to pipeline opposition groups could also cause negative impacts on the segment with increased costs and
potential delays to project completion.
The segment focuses on the recruitment and retention of a skilled workforce to remain competitive and provide services to its customers.
The industry in which it operates relies on a skilled workforce to construct energy infrastructure and operate existing infrastructure in a safe
manner. A shortage of skilled personnel can create a competitive labor market which could increase costs incurred by the segment.
Competition from other pipeline and midstream companies can also have a negative impact on the segment.
Earnings overview - The following information summarizes the performance of the pipeline and midstream segment.
Years ended December 31,2018 2017 2016
(Dollars in millions)
Operating revenues $128.9 $122.2 $141.6
Operating expenses:
Operation and maintenance 62.2 56.9 61.9
Depreciation, depletion and amortization 17.9 16.8 24.9
Taxes, other than income 12.7 12.5 11.9
Total operating expenses 92.8 86.2 98.7
Operating income 36.1 36.0 42.9
Other income 1.0 1.8 .9
Interest expense 5.9 5.0 8.0
Income before income taxes 31.2 32.8 35.8
Income taxes 2.7 12.3 12.4
Earnings $28.5 $20.5 $23.4
Transportation volumes (MMdk)351.5 312.5 285.3
Natural gas gathering volumes (MMdk)14.9 16.1 20.0
Customer natural gas storage balance (MMdk):
Beginning of period 22.4 26.4 16.6
Net injection (withdrawal)(8.5)(4.0)9.8
End of period 13.9 22.4 26.4
2018 compared to 2017 Pipeline and midstream earnings increased $8.0 million (39 percent) as a result of:
Revenues: Increase of $6.7 million, largely attributable to increased volumes of natural gas transported through its system as a result of
completed organic growth projects and higher nonregulated project workloads, which increased revenues $4.1 million. These increases
were partially offset by decreased storage-related revenues reflecting the decrease in natural gas pricing spreads, as discussed in the
Outlook section.
Operation and maintenance: Increase of $5.3 million, primarily from higher nonregulated project costs of $3.9 million directly related to
the increase in nonregulated project workloads, as previously discussed, as well as higher professional services, material costs and
contract services.
Depreciation, depletion and amortization: Increase of $1.1 million, largely resulting from organic growth projects.
Taxes, other than income: Comparable to the prior year.
Other income: Decrease of $800,000, primarily the result of lower returns on investments partially offset by higher AFUDC.
Interest expense: Increase of $900,000, largely resulting from higher debt balances.
Income taxes: Decrease of $9.6 million, primarily resulting from the lower corporate tax rate due to the enactment of the TCJA creating a
reduction to income tax expense, as well as the realization of a $4.2 million income tax benefit related to the reversal of a regulatory
liability recorded in 2017 based on a FERC final accounting order issued during third quarter of 2018.
2017 compared to 2016 Pipeline and midstream earnings decreased $2.9 million (13 percent) as a result of:
Revenues: Decrease of $19.4 million, largely resulting from lower gathering and processing revenues of $22.6 million. The decrease in
revenues resulted from lower volumes from the sale of the Pronghorn assets in January 2017. Partially offsetting the decrease was higher
transportation revenues of $1.6 million, largely from increased off-system transportation volumes due to organic growth projects
completed in 2017.
Operation and maintenance: Decrease of $5.0 million, which includes $3.6 million primarily from the absence of Pronghorn, as
previously discussed, and the absence in 2017 of a fair value impairment in 2016 associated with the Pronghorn sale.
Depreciation, depletion and amortization: Decrease of $8.1 million, largely due to the absence of the Pronghorn assets, as previously
discussed.
Taxes, other than income: Increase of $600,000 from higher property taxes.
Other income: Increase of $900,000 attributable to higher AFUDC.
Part II
MDU Resources Group, Inc. Form 10-K 39
Interest expense: Decrease of $3.0 million due to lower debt balances.
Income taxes: Comparable to the prior year.
Outlook The Company has continued to experience the effects of natural gas production at record levels, which has provided opportunities
for organic growth projects and increased demand. The completion of organic growth projects has contributed to the Company transporting
increasing volumes of natural gas through its system. Additionally, the record levels of natural gas supply have moderated the need for
storage services and put downward pressure on natural gas prices and minimized pricing volatility. Both natural gas production levels and
pressure on natural gas prices are expected to continue in the near term. The Company continues to focus on growth and improving existing
operations through organic projects in all areas in which it operates. The following describes recent growth projects.
In January 2019, the Company announced plans to construct approximately 67 miles of new pipeline, compression and ancillary facilities to
transport natural gas from core Bakken production areas near Tioga, North Dakota, and extend to a new interconnection point in McKenzie
County, North Dakota. This North Bakken Expansion project, as designed, would provide 200 MMcf per day of natural gas transportation
capacity. Construction is expected to begin in early 2021 with an estimated completion date late in 2021, which is dependent on regulatory
and environmental permitting and finalization of transportation agreements with customers. The estimated cost of the project is
approximately $220 million.
In November 2018, the Company completed construction and placed into service its Valley Expansion project, a 38-mile pipeline that
delivers natural gas supply to eastern North Dakota and far western Minnesota. The project, which is designed to transport 40 MMcf of
natural gas per day, is under the jurisdiction of the FERC.
In September 2018, the Company completed construction and placed into service its Line Section 27 Expansion project in the Bakken area
of northwestern North Dakota. The project includes approximately 13 miles of new pipeline and associated facilities and increases capacity
by over 200 MMcf per day. The project brings the total capacity of Line Section 27 to over 600 MMcf per day.
In early 2018, the Company announced two additional natural gas pipeline growth projects, the Demicks Lake project and Line Section 22
Expansion project. The Company has signed long-term commitment contracts supporting both projects. The Demicks Lake project, which
includes approximately 14 miles of 20-inch pipe and will increase capacity by 175 MMcf per day, is located in McKenzie County, North
Dakota. Construction is expected to begin in 2019, with an in-service date in the fall of 2019. The Line Section 22 Expansion project in the
Billings, Montana, area is also scheduled to begin construction in 2019, with an expected in-service date in late 2019. This project will
increase capacity by 22.5 MMcf per day to serve incremental demand in Billings, Montana.
Part II
40 MDU Resources Group, Inc. Form 10-K
Construction Materials and Contracting
Strategy and challenges The construction materials and contracting segment provides an integrated set of construction services, as
discussed in Items 1 and 2 - Business Properties. The segment focuses on high-growth strategic markets located near major transportation
corridors and desirable mid-sized metropolitan areas; strengthening the long-term, strategic aggregate reserve position through available
purchase and/or lease opportunities; enhancing profitability through cost containment, margin discipline and vertical integration of the
segment's operations; development and recruitment of talented employees; and continued growth through organic and acquisition
opportunities.
A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials
business (rock, sand, gravel, liquid asphalt, asphalt concrete, ready-mixed concrete and related products), complementing and expanding on
the segment's expertise. The Company's acquisitions in 2018 support this strategy.
As one of the country's largest sand and gravel producers, the segment continues to strategically manage its 1.0 billion tons of aggregate
reserves in all its markets, as well as take further advantage of being vertically integrated. The segment's vertical integration allows the
segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted
aggregate reserves being significant. The Company's aggregate reserves are naturally declining and as a result, the Company seeks
acquisition opportunities to replace the reserves. In 2018, the Company's aggregate reserves increased by nearly 50 million tons primarily
due to acquisition activity.
The construction materials and contracting segment faces challenges that are not under the direct control of the business. The segment
operates in geographically diverse and highly competitive markets. Competition can put negative pressure on the segment's operating
margins. The segment is also subject to volatility in the cost of raw materials such as diesel fuel, gasoline, liquid asphalt, cement and steel.
Although it is difficult to determine the split between inflation and supply/demand increases, diesel fuel costs remained fairly stable for the
past twelve months, while asphalt oil costs have trended higher in 2018 as compared to 2017. Such volatility can have a negative impact
on the segment's margins. Other variables that can impact the segment's margins include adverse weather conditions, the timing of project
starts or completion and declines or delays in new and existing projects due to the cyclical nature of the construction industry and federal
infrastructure spending.
The segment also faces challenges in the recruitment and retention of employees. Trends in the labor market include an aging workforce and
availability issues. The segment continues to face increasing pressure to control costs, as well as find and train a skilled workforce to meet
the needs of increasing demand and seasonal work.
Earnings overview - The following information summarizes the performance of the construction materials and contracting segment.
Years ended December 31,2018 2017 2016
(Dollars in millions)
Operating revenues $1,925.9 $1,812.5 $1,874.3
Cost of sales:
Operation and maintenance 1,601.7 1,500.1 1,533.2
Depreciation, depletion and amortization 59.0 52.5 54.1
Taxes, other than income 39.7 38.0 37.5
Total cost of sales 1,700.4 1,590.6 1,624.8
Gross margin 225.5 221.9 249.5
Selling, general and administrative expense:
Operation and maintenance 77.6 71.5 62.2
Depreciation, depletion and amortization 2.2 3.4 4.3
Taxes, other than income 4.3 3.8 4.3
Total selling, general and administrative expense 84.1 78.7 70.8
Operating income 141.4 143.2 178.7
Other income (expense)(3.1).4 (.1)
Interest expense 17.3 14.8 15.3
Income before income taxes 121.0 128.8 163.3
Income taxes 28.4 5.4 60.6
Earnings $92.6 $123.4 $102.7
Sales (000's):
Aggregates (tons)29,795 28,213 27,580
Asphalt (tons)6,838 6,237 7,203
Ready-mixed concrete (cubic yards)3,518 3,548 3,655
2018 compared to 2017 Construction materials and contracting's earnings decreased $30.8 million (25 percent) as a result of:
Revenues: Increase of $113.4 million driven by higher asphalt product and aggregate volumes due to increased agency demand,
increased realized prices and lower material costs. Partially offsetting these increases were lower ready-mixed concrete volumes due to a
decrease in available work and unfavorable weather conditions in certain regions.
Gross margin: Increase of $3.6 million resulting from higher asphalt product volumes and margins, largely from recent acquisitions and
higher realized prices. Also contributing to the increase were higher aggregate volumes and margins due to strong market demand and
lower material costs. Partially offsetting these increases were lower ready-mixed concrete volumes and margins due to a decrease in
available work and unfavorable weather conditions in certain regions.
Selling, general and administrative expense: Increase of $5.4 million, primarily payroll-related costs, acquisition costs and higher
insurance-related costs.
Other income: Decrease of $3.5 million, largely the result of lower returns on investments.
Interest expense: Increase of $2.5 million, largely resulting from higher debt balances as a result of recent acquisitions, capital
expenditures and higher working capital needs.
Income taxes: Increase of $23.0 million, primarily resulting from the absence in 2018 of a $41.9 million tax benefit recorded in the
fourth quarter of 2017 for the revaluation of the segment's net deferred tax liabilities, as discussed in Item 8 - Note 13. Partially
offsetting this increase were lower income taxes due to the enactment of the TCJA, which reduced the corporate tax rate.
2017 compared to 2016 Construction materials and contracting's earnings increased $20.7 million (20 percent) as a result of:
Revenues: Decrease of $61.8 million resulting from lower asphalt product volumes driven by competitive pricing and unfavorable weather
Part II
MDU Resources Group, Inc. Form 10-K 41
during the first half of the year, less available work and increased competition in certain regions.
Gross margin: Decrease of $27.6 million, largely resulting from lower asphalt product margins, as previously discussed, and lower
construction margins of $8.8 million driven by decreased workloads caused by unfavorable weather during the first half of the year and
less available work in energy-producing states. Partially offsetting these decreases were higher aggregate margins of $8.0 million,
primarily due to strong commercial and residential demand in certain regions.
Selling, general and administrative expense: Increase of $7.9 million, largely resulting from the absence in 2017 of an $11.1 million
reduction to a MEPP withdrawal liability. Partially offsetting the increase were lower depreciation, depletion and amortization expense and
lower office expense.
Other income: Comparable to the prior year.
Interest expense: Comparable to the prior year.
Income taxes: Decrease of $55.2 million, largely resulting from an income tax benefit of $41.9 million for the revaluation of the
segment's net deferred tax liabilities, as discussed in Item 8 - Note 13, and lower income before income taxes.
Outlook The segment's vertically integrated aggregates based business model provides the Company with the ability to capture margin
throughout the sales delivery process. The aggregate products are sold internally and externally for use in other products such as ready-
mixed concrete, asphaltic concrete and public and private construction markets. The contracting services and construction materials are
sold primarily to construction contractors in connection with street, highway and other public infrastructure projects, as well as private
commercial and residential development projects. The public infrastructure projects have traditionally been more stable markets as public
funding is more secure during periods of economic decline. The public funding is, however, dependent on federal funding such as
appropriations to the Federal Highway Administration. Spending on private development is highly dependent on both local and national
economic cycles, providing additional sales during times of strong economic cycles.
The Company remains optimistic about overall economic growth and infrastructure spending. The IBISWorld Incorporated Industry Report
issued in May 2018 for sand and gravel mining in the United States projects a 1.8 percent annual growth rate over the next five years. The
report also states the demand for clay and refractory materials is projected to continue deteriorating in several downstream manufacturing
industries, but this decline will be offset by stronger demand from the housing market and buoyant demand from the highway and bridge
construction market. The Company believes stronger demand in the housing markets along with continued demand from the highway and
bridge construction markets should provide a stable demand for construction materials and contracting products and services in the near
future.
In April 2018, the Company acquired Teevin & Fischer Quarry, LLC, a crushed rock and gravel supplier in northwestern Oregon. In June
2018, the Company acquired Tri-City Paving, Inc., a general contractor and aggregate, asphalt and ready-mixed concrete supplier
headquartered in Little Falls, Minnesota. In July 2018, the Company acquired Molalla Redi-Mix and Rock Products, Inc., which produces
ready-mixed concrete in Molalla, Oregon. In October 2018, the Company acquired Sweetman Construction Company, a premier provider of
aggregates, asphalt and ready-mixed concrete in Sioux Falls, South Dakota. These acquisitions are expected to be accretive to the segment's
earnings in 2019. The Company continues to evaluate additional acquisition opportunities. For more information on these acquisitions, see
Item 8 - Note 3.
The Company had backlog at December 31, 2018, of $706 million, up from $486 million at December 31, 2017. The Company has
benefited from increased bidding opportunities in each of its regions. The increase in backlog was primarily attributable to work for state
transportation departments, airports, the military, homebuilders and commercial developers. The Company expects to complete a significant
amount of the backlog at December 31, 2018, during the next 12 months.
Part II
42 MDU Resources Group, Inc. Form 10-K
Construction Services
Strategy and challenges The construction services segment provides inside and outside specialty contracting, as discussed in Items 1 and 2
- Business Properties. The construction services segment focuses on providing a superior return on investment by building new and
strengthening existing customer relationships; ensuring quality service; safely executing projects; effectively controlling costs; collecting on
receivables; retaining, developing and recruiting talented employees; growing through organic and acquisition opportunities; and focusing
efforts on projects that will permit higher margins while properly managing risk.
The construction services segment faces challenges in the highly competitive markets in which it operates. Competitive pricing
environments, project delays and effects from restrictive regulatory requirements have negatively impacted margins in the past and could
affect margins in the future. Additionally, margins may be negatively impacted on a quarterly basis due to adverse weather conditions, as
well as timing of project starts or completions, declines or delays in new projects due to the cyclical nature of the construction industry and
other factors. These challenges may also impact the risk of loss on certain projects. Accordingly, operating results in any particular period
may not be indicative of the results that can be expected for any other period.
The need to ensure available specialized labor resources for projects also drives strategic relationships with customers and project margins.
These trends include an aging workforce and labor availability issues, increasing pressure to reduce costs and improve reliability, and
increasing duration and complexity of customer capital programs. Due to these and other factors, the Company believes customer demand
for labor resources will continue to increase, possibly surpassing the supply of industry resources.
Earnings overview - The following information summarizes the performance of the construction services segment.
Years ended December 31,2018 2017 2016
(In millions)
Operating revenues $1,371.5 $1,367.6 $1,073.3
Cost of sales:
Operation and maintenance 1,150.4 1,153.9 905.4
Depreciation, depletion and amortization 14.3 14.2 13.5
Taxes, other than income 42.0 43.4 35.2
Total cost of sales 1,206.7 1,211.5 954.1
Gross margin 164.8 156.1 119.2
Selling, general and administrative expense:
Operation and maintenance 72.2 69.3 60.1
Depreciation, depletion and amortization 1.4 1.5 1.8
Taxes, other than income 4.4 4.0 3.8
Total selling, general and administrative expense 78.0 74.8 65.7
Operating income 86.8 81.3 53.5
Other income 1.1 1.3 2.2
Interest expense 3.6 3.7 4.0
Income before income taxes 84.3 78.9 51.7
Income taxes 20.0 25.6 17.8
Earnings $64.3 $53.3 $33.9
2018 compared to 2017 Construction services earnings increased $11.0 million (21 percent) as a result of:
Revenues: Comparable to the prior year.
Gross margin: Increase of $8.7 million, largely resulting from higher outside specialty contracting gross margins due to increased outside
equipment sales and rentals. Partially offsetting the increase were decreased inside specialty contracting gross margins as a result of
decreased workloads and customer demand.
Selling, general and administrative expense: Increase of $3.2 million, primarily higher office expense, outside professional costs and
payroll-related costs.
Other income: Comparable to the prior year.
Interest expense: Comparable to the prior year.
Income taxes: Decrease of $5.6 million, largely the lower corporate tax rate due to the enactment of the TCJA.
2017 compared to 2016 Construction services earnings increased $19.4 million (57 percent) as a result of:
Revenues: Increase of $294.3 million, primarily from an increase in the number and size of construction projects in 2017, as well as
increased equipment sales and rentals.
Gross margin: Increase of $36.9 million resulting from higher inside specialty contracting margins of $20.9 million driven by increased
revenues, as previously discussed, and decreased costs from the successful management of labor performance on projects in a majority of
the business activities performed partially offset by job losses on certain projects. Also contributing to the increased margins were higher
outside specialty contracting margins of $16.0 million driven by higher contracting workloads and equipment revenues in areas impacted
by storm activity.
Selling, general and administrative expense: Increase of $9.1 million, primarily higher payroll-related costs, office expense and outside
professional costs.
Other income: Decrease of $900,000 due to the absence of interest income earned on prior year completed jobs.
Interest expense: Comparable to the prior year.
Part II
MDU Resources Group, Inc. Form 10-K 43
Income taxes: Increase of $7.8 million resulting from an increase in income before income taxes and the absence in 2017 of a
$1.5 million tax benefit related to the disposition of a non-strategic asset. Partially offsetting this increase was an income tax benefit of
$4.3 million for the revaluation of the segment's net deferred tax liabilities, as discussed in Item 8 - Note 13.
Outlook The Company continues to expect long-term growth in the electric transmission and distribution market, although the timing of large
bids and subsequent construction is likely to be highly variable from year to year. The Company believes several small and medium-sized
transmission and distribution projects will continue to be available for bid in 2019. The Company expects bidding activity to remain strong
for both outside and inside specialty construction companies in 2019. Although bidding remains highly competitive in all areas, the
Company expects the segment's skilled workforce will continue to provide a benefit in securing and executing profitable projects.
The Company had backlog at December 31, 2018, of $939 million, up from $708 million at December 31, 2017. The increase in backlog
was largely attributable to the new project opportunities that the Company continues to see across its diverse operations, particularly in
inside specialty electrical and mechanical contracting for the hospitality and gaming, high-tech, mission critical and public entities. The
Company's outside power, communications and natural gas specialty operations also have a high volume of work. The Company expects to
complete a significant amount of the backlog at December 31, 2018, during the next 12 months. Additionally, the Company continues to
evaluate potential acquisition opportunities that would be accretive to the Company and grow the Company's backlog.
Part II
44 MDU Resources Group, Inc. Form 10-K
Other
Years ended December 31,2018 2017 2016
(In millions)
Operating revenues $11.3 $7.9 $8.6
Operating expenses:
Operation and maintenance 9.3 6.3 6.7
Depreciation, depletion and amortization 2.0 2.0 2.1
Taxes, other than income .1 .2 .1
Total operating expenses 11.4 8.5 8.9
Operating loss (.1)(.6)(.3)
Other income 1.0 .9 .9
Interest expense 2.8 3.6 5.8
Loss before income taxes (1.9)(3.3)(5.2)
Income taxes (1.2)(1.8)(2.0)
Loss $(.7)$(1.5)$(3.2)
Included in Other are general and administrative costs and interest expense previously allocated to the exploration and production and
refining businesses that do not meet the criteria for income (loss) from discontinued operations. Largely contributing to the increase in
operation and maintenance expense in 2018 were costs associated with the Holding Company Reorganization. For further details on the
Company's reorganization, see Items 1 and 2 Business Properties - General.
Discontinued Operations
Years ended December 31,2018 2017 2016
(In millions)
Income (loss) from discontinued operations before intercompanyeliminations, net of tax $2.9 $3.1 $(303.2)
Intercompany eliminations —(6.9)2.8
Income (loss) from discontinued operations, net of tax 2.9 (3.8)(300.4)
Loss from discontinued operations attributable to noncontrollinginterest ——(131.7)
Income (loss) from discontinued operations attributable to theCompany, net of tax $2.9 $(3.8)$(168.7)
2018 compared to 2017 The income from discontinued operations attributable to the Company was $2.9 million, primarily related to
income tax adjustments, compared to a loss of $3.8 million in the prior year. The loss in 2017 was largely due to eliminations for the
presentation of income tax adjustments between continuing and discontinued operations.
2017 compared to 2016 The loss from discontinued operations attributable to the Company was $3.8 million compared to a loss of
$168.7 million in the prior year. The decreased loss was largely due to the absence in 2017 of a loss associated with the sale of the refining
business in June 2016, as well as the reversal in 2017 of a previously accrued liability due to the resolution of a legal matter, as discussed
in Item 8 - Note 4.
Part II
MDU Resources Group, Inc. Form 10-K 45
Intersegment Transactions
Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's elimination of
intersegment transactions. The amounts related to these items were as follows:
Years ended December 31,2018 2017 2016
(In millions)
Intersegment transactions:
Operating revenues $64.3 $58.0 $57.4
Operation and maintenance 13.7 9.1 8.7
Purchased natural gas sold 50.6 48.9 48.7
Income from continuing operations*—(6.9)(6.3)
*Includes eliminations for the presentation of income tax adjustments between
continuing and discontinued operations.
For more information on intersegment eliminations, see Item 8 - Note 15.
Liquidity and Capital Commitments
At December 31, 2018, the Company had cash and cash equivalents of $53.9 million and available borrowing capacity of $384.6 million
under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing
within one year and its other operating and capital requirements from various sources, including internally generated funds; the Company's
credit facilities, as described later in Capital resources; the issuance of long-term debt; and issuance of equity securities.
Cash flows
Operating activities The changes in cash flows from operating activities generally follow the results of operations as discussed in Business
Segment Financial and Operating Data and also are affected by changes in working capital. Changes in cash flows for discontinued
operations are related to the former exploration and production and refining businesses. Cash flows provided by operating activities in 2018
increased $51.9 million from 2017.
Increases: The increase in cash flows provided by operating activities was largely driven by stronger collection of accounts receivable at the
construction services and construction materials and contracting businesses and bonus depreciation for tax purposes due to the enactment
of TCJA at the construction materials and contracting business.
Decreases: Partially offsetting these increases were higher inventory balances at the construction materials and contracting business due to
higher asphalt oil inventory, largely resulting from higher average per ton cost, and higher aggregate inventory from higher production. Also
contributing to the decrease were decreased deferral of production tax credits, re-measurements of taxes on investments and accelerated tax
deductions related to the TCJA.
Cash flows provided by operating activities in 2017 decreased $14.2 million from 2016. The decrease in cash flows provided by operating
activities reflects higher working capital requirements at the construction services business largely resulting from higher receivables due to
increased workloads during the year and at the construction materials business due to higher receivables resulting from increased workloads
later in the year. Higher natural gas purchases including the effects of colder weather also added to higher working capital requirements at
the natural gas distribution business. Higher income taxes paid from continuing operations was largely offset by higher income tax benefits
received from discontinued operations resulting from the realization of net operating losses at the discontinued operations. Higher earnings
from continuing operations in 2017, compared to 2016, partially offset the decrease in cash flows provided by operating activities. Higher
margins at the electric, natural gas distribution and construction services businesses were partially offset by lower margins at the
construction materials business.
Investing activities Cash flows used in investing activities in 2018 increased $496.7 million from 2017. The increase in cash used in
investing activities was primarily related to acquisition activity in 2018 at the construction materials and contracting business; the absence
in 2018 of net proceeds from the sale of Pronghorn in January 2017 and higher capital expenditures in 2018 at the pipeline and
midstream business; and higher capital expenditures related to various construction projects in 2018 at the electric and natural gas
distribution businesses.
Cash flows used in investing activities in 2017 decreased $90.9 million from 2016, largely resulting from net proceeds from the sale of
Pronghorn in January 2017 at the pipeline and midstream business.
Financing activities Cash flows provided by financing activities in 2018 increased $475.7 million from 2017. The increase in cash provided
by financing activities was largely due to increased debt issuance from an increase in commercial paper balances used for acquisitions,
ongoing capital expenditures and working capital needs at the construction materials and contacting business; the issuance of an additional
$200 million in term loans for capital projects at the electric and natural gas distribution businesses; and the issuance of an additional
$40 million under the private shelf agreement for capital projects at the pipeline and midstream business. The increase in issuance of long-
term debt was partially offset by higher debt repayment on a line of credit at the natural gas distribution business; higher debt repayment on
debt that matured during third quarter 2018 at the electric and natural gas distribution businesses; and the strong collection of accounts
receivable resulting in lower commercial paper balances at the construction services business.
Cash flows used in financing activities in 2017 increased $50.4 million from 2016, primarily due to the higher net repayment of long-term
debt.
Part II
46 MDU Resources Group, Inc. Form 10-K
Defined benefit pension plans
The Company has noncontributory qualified defined benefit pension plans for certain employees. Plan assets consist of investments in
equity and fixed-income securities. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset)
related to the pension plans. Actuarial assumptions include assumptions about the discount rate and expected return on plan assets. At
December 31, 2018, the pension plans' accumulated benefit obligations exceeded these plans' assets by approximately $83.8 million.
Pretax pension expense reflected in the Company's Consolidated Statements of Income for the years ended December 31, 2018, 2017 and
2016, was $843,000, $1.7 million and $2.0 million, respectively. The Company's pension expense is currently projected to be less than
$1.0 million in 2019. Funding for the pension plans is actuarially determined. The minimum required contributions for the year ended
December 31, 2018 were approximately $6.1 million. There were no minimum required contributions for 2017 and 2016. For more
information on the Company's pension plans, see Item 8 - Note 16.
Capital expenditures
The Company's capital expenditures from continuing operations for 2016 through 2018 and as anticipated for 2019 through 2021 are
summarized in the following table.
Actual*Estimated
2016 2017 2018 2019 2020 2021
(In millions)
Capital expenditures:
Electric $111 $109 $186 $104 $103 $88
Natural gas distribution 126 147 206 204 180 158
Pipeline and midstream 35 31 70 113 93 204
Construction materials and contracting 38 44 280 133 135 127
Construction services 60 19 25 25 17 18
Other 2 2 2 5 3 3
Total capital expenditures $372 $352 $769 $584 $531 $598
*Capital expenditures for 2018, 2017 and 2016 include noncash transactions such as the issuance of the Company's
equity securities in connection with acquisitions, capital expenditure-related accounts payable and AFUDC, totaling$33.4 million, $10.5 million and $(15.8) million, respectively.
The 2018 capital expenditures include the four acquisitions at the construction materials and contracting segment, as discussed in Item 8 -
Note 3. The 2018 capital expenditures were funded by internal sources, issuance of long-term debt and issuance of the Company's equity
securities. The Company has included in the estimated capital expenditures for 2019 through 2021 the Demicks Lake project, Line Section
22 Expansion project and North Bakken Expansion project, as previously discussed in Business Segment Financial and Operating Data.
Estimated capital expenditures for the years 2019 through 2021 include those for:
•System upgrades
•Routine replacements
•Service extensions
•Routine equipment maintenance and replacements
•Buildings, land and building improvements
•Pipeline, gathering and other midstream projects
•Power generation and transmission opportunities
•Environmental upgrades
•Other growth opportunities
The Company continues to evaluate potential future acquisitions and other growth opportunities that would be incremental to the outlined
capital program; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary
significantly from the estimates in the preceding table. It is anticipated that all of the funds required for capital expenditures for the years
2019 through 2021 will be funded by various sources, including internally generated funds; the Company's credit facilities, as described
later; issuance of long-term debt; and issuance of equity securities.
Part II
MDU Resources Group, Inc. Form 10-K 47
Capital resources
Certain debt instruments of the Company and its subsidiaries, including those discussed later, contain restrictive and financial covenants
and cross-default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in
compliance with the applicable covenants and certain other conditions, all of which the Company and its subsidiaries, as applicable, were in
compliance with at December 31, 2018. In the event the Company and its subsidiaries do not comply with the applicable covenants and
other conditions, alternative sources of funding may need to be pursued. For more information on the covenants, certain other conditions
and cross-default provisions, see Item 8 - Note 8.
The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries at December 31, 2018:
Company Facility FacilityLimit AmountOutstanding Lettersof Credit ExpirationDate
(In millions)
MDU Resources Group, Inc.Commercial paper/Revolvingcredit agreement (a)$175.0 $48.5 $—6/8/23
Cascade Natural GasCorporation Revolving credit agreement $75.0 (c)$53.8 $2.2 (d)4/24/20
Intermountain Gas Company Revolving credit agreement $85.0 (e)$56.3 $—4/24/20
Centennial Energy Holdings,Inc.Commercial paper/Revolvingcredit agreement (f)$500.0 $289.6 (b)$—9/23/21
(a)The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of the
Company on stated conditions, up to a maximum of $225.0 million). The amount outstanding under the revolving credit agreement was $48.5 million.(b)Amount outstanding under commercial paper program.
(c)Certain provisions allow for increased borrowings, up to a maximum of $100.0 million.
(d)Outstanding letter(s) of credit reduce the amount available under the credit agreement.
(e)Certain provisions allow for increased borrowings, up to a maximum of $110.0 million.
(f)The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Centennialon stated conditions, up to a maximum of $600.0 million). There were no amounts outstanding under the revolving credit agreement.
The Company's and Centennial's respective commercial paper programs are supported by revolving credit agreements. While the amount of
commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, the Company and
Centennial do not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreements. The
commercial paper borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the
seasonality of the construction businesses.
Total equity as a percent of total capitalization was 55 percent and 59 percent at December 31, 2018 and 2017, respectively. This ratio is
calculated as the Company's total equity, divided by the Company's total capital. Total capital is the Company's total debt, including short-
term borrowings and long-term debt due within one year, plus total equity. This ratio is an indicator of how the Company is financing its
operations, as well as its financial strength.
The following includes information related to the preceding table.
MDU Resources Group, Inc. The Company's revolving credit agreement supports its commercial paper program. Commercial paper borrowings
under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued
commercial paper borrowings. The Company's objective is to maintain acceptable credit ratings in order to access the capital markets
through the issuance of commercial paper. Historically, downgrades in the Company's credit ratings have not limited, nor are currently
expected to limit, the Company's ability to access the capital markets. If the Company were to experience a downgrade of its credit ratings
in the future, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its
cost of borrowings.
On January 1, 2019, the Company's revolving credit agreement and commercial paper program became Montana-Dakota's revolving credit
agreement and commercial paper program as a result of the Holding Company Reorganization. The outstanding balance of the revolving
credit agreement was also transferred to Montana-Dakota. All of the related terms and covenants of the credit agreements remained the
same.
Prior to the maturity of the credit agreement, Montana-Dakota expects that it will negotiate the extension or replacement of this agreement.
If Montana-Dakota is unable to successfully negotiate an extension of, or replacement for, the credit agreement, or if the fees on this facility
become too expensive, which Montana-Dakota does not currently anticipate, it would seek alternative funding.
Cascade Cascade's credit agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any
time, the ratio of total debt to total capitalization to be greater than 65 percent. Cascade's ratio of total debt to total capitalization as of
December 31, 2018, was 51 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the
making of certain investments.
Cascade's credit agreement also contains cross-default provisions. These provisions state that if Cascade fails to make any payment with
respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness
to be due prior to its stated maturity or the contingent obligation to become payable, Cascade will be in default under the revolving credit
agreement.
Intermountain Intermountain's credit agreement contains customary covenants and provisions, including a covenant of Intermountain not to
permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. Intermountain's ratio of total debt to total
capitalization as of December 31, 2018, was 49 percent. Other covenants include restrictions on the sale of certain assets, limitations on
indebtedness and the making of certain investments.
Intermountain's credit agreement also contains cross-default provisions. These provisions state that if Intermountain fails to make any
payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such
indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, or certain conditions result in an early
termination date under any swap contract that is in excess of a specified amount, then Intermountain will be in default under the revolving
credit agreement.
Centennial Centennial's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this
agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper
borrowings. Centennial's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of
commercial paper. Historically, downgrades in Centennial's credit ratings have not limited, nor are currently expected to limit, Centennial's
ability to access the capital markets. If Centennial were to experience a downgrade of its credit ratings in the future, it may need to borrow
under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.
Prior to the maturity of the Centennial credit agreement, Centennial expects that it will negotiate the extension or replacement of this
agreement, which provides credit support to access the capital markets. In the event Centennial is unable to successfully negotiate this
agreement, or in the event the fees on this facility become too expensive, which Centennial does not currently anticipate, it would seek
alternative funding.
WBI Energy Transmission WBI Energy Transmission has a $200.0 million uncommitted note purchase and private shelf agreement with an
expiration date of May 16, 2019. WBI Energy Transmission had $140.0 million of notes outstanding at December 31, 2018, which reduced
the remaining capacity under this uncommitted private shelf agreement to $60.0 million.
Part II
48 MDU Resources Group, Inc. Form 10-K
Off balance sheet arrangements
As of December 31, 2018, the Company had no material off balance sheet arrangements as defined by the rules of the SEC.
Contractual obligations and commercial commitments
For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see
Item 8 - Notes 8 and 19. At December 31, 2018, the Company's commitments under these obligations were as follows:
Less than 1 year 1-3 years 3-5 years More than 5 years Total
(In millions)
Long-term debt*$251.9 $416.3 $273.0 $1,173.0 $2,114.2
Estimated interest payments**83.0 153.9 123.6 472.5 833.0
Operating leases 37.7 44.2 18.9 49.1 149.9
Purchase commitments 418.1 384.8 200.1 622.4 1,625.4
$790.7 $999.2 $615.6 $2,317.0 $4,722.5
*Unamortized debt issuance costs and discount are excluded from the table.
**Estimated interest payments are calculated based on the applicable rates and payment dates.
At December 31, 2018, the Company had total liabilities of $375.6 million related to asset retirement obligations that are excluded from
the table above. Of the total asset retirement obligations, the current portion was $5.0 million at December 31, 2018, and was included in
other accrued liabilities on the Consolidated Balance Sheet. The remainder, which constitutes the long-term portion of asset retirement
obligations, was included in deferred credits and other liabilities - other on the Consolidated Balance Sheet. Due to the nature of these
obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. For more information, see
Item 8 - Note 9.
Not reflected in the previous table are $382,000 in uncertain tax positions at December 31, 2018. For more information, see Item 8 -
Note 13.
The Company's minimum funding requirements for its defined benefit pension plans for 2019, which are not reflected in the previous table,
are $4.0 million. For information on potential contributions above the funding minimum requirements, see item 8 - Note 16.
The Company's MEPP contributions are based on union employee payroll, which cannot be determined in advance for future periods. The
Company may also be required to make additional contributions to its MEPPs as a result of their funded status. For more information, see
Item 1A - Risk Factors and Item 8 - Note 16.
Part II
MDU Resources Group, Inc. Form 10-K 49
New Accounting Standards
For information regarding new accounting standards, see Item 8 - Note 1, which is incorporated herein by reference.
Critical Accounting Policies Involving Significant Estimates
The Company has prepared its financial statements in conformity with GAAP. The preparation of these financial statements requires
management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent
assets and liabilities, at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting
period. The Company's significant accounting policies are discussed in Item 8 - Note 1.
Estimates are used for items such as impairment testing of long-lived assets and goodwill; fair values of acquired assets and liabilities under
the acquisition method of accounting; aggregate reserves; property depreciable lives; tax provisions; revenue recognized using the cost-to-
cost measure of progress for contracts; uncollectible accounts; environmental and other loss contingencies; accumulated provision for
revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement
obligations; and the valuation of stock-based compensation. The Company's critical accounting policies are subject to judgments and
uncertainties that affect the application of such policies. As discussed below, the Company's financial position or results of operations may
be materially different when reported under different conditions or when using different assumptions in the application of such policies.
As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently,
operating results can be affected by revisions to prior accounting estimates. The following critical accounting policies involve significant
judgments and estimates.
Impairment of long-lived assets and intangibles
The Company reviews the carrying values of its long-lived assets and intangibles, excluding assets held for sale, whenever events or changes
in circumstances indicate that such carrying values may not be recoverable and at least annually for goodwill.
Goodwill The Company performs its goodwill impairment testing annually in the fourth quarter. In addition, the test is performed on an
interim basis whenever events or circumstances indicate that the carrying amount of goodwill may not be recoverable. Examples of such
events or circumstances may include a significant adverse change in business climate, weakness in an industry in which the Company's
reporting units operate or recent significant cash or operating losses with expectations that those losses will continue.
The goodwill impairment test is a two-step process performed at the reporting unit level. The Company has determined that the reporting
units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for
which discrete financial information is available and for which segment management regularly reviews the operating results. For more
information on the Company's operating segments, see Item 8 - Note 15. The first step of the impairment test involves comparing the fair
value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no
impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the
amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the
carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the
years ended December 31, 2018, 2017 and 2016, there were no impairment losses recorded. At December 31, 2018, the fair value
substantially exceeded the carrying value at all reporting units.
Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the
Company's future revenue, profitability and cash flows, amount and timing of estimated capital expenditures, inflation rates, risk adjusted
cost of capital, operational plans, and current and future economic conditions, among others. The fair value of each reporting unit is
determined using a weighted combination of income and market approaches. The Company uses a discounted cash flow methodology for its
income approach. Under the income approach, the discounted cash flow model determines fair value based on the present value of
projected cash flows over a specified period and a residual value related to future cash flows beyond the projection period. Both values are
discounted using a rate which reflects the best estimate of the risk adjusted cost of capital at each reporting unit. The risk adjusted cost of
capital, which varies by reporting unit and is in the range of 5 percent to 9 percent, and a long-term growth rate projection of approximately
3 percent were utilized in the goodwill impairment test performed in the fourth quarter of 2018. Under the market approach, the Company
estimates fair value using multiples derived from enterprise value to EBITDA for comparative peer companies for each respective reporting
unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company
adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that
would be received in a sale in an orderly transaction between market participants. The Company believes that the estimates and
assumptions used in its impairment assessments are reasonable and based on available market information.
Long-Lived Assets Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived
assets and intangibles due to changes in estimates of future cash flows could negatively affect the fair value of the Company's assets and
result in an impairment charge. If an impairment indicator exists for tangible and intangible assets, excluding goodwill, the asset group held
and used is tested for recoverability by comparing an estimate of undiscounted future cash flows attributable to the assets compared to the
carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair
value of the assets and recording a loss if the carrying value is greater than the fair value.
There is risk involved when determining the fair value of assets, tangible and intangible, as there may be unforeseen events and changes in
circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the
fair value of the asset could be different using different estimates and assumptions in the valuation techniques used.
The Company believes its estimates used in calculating the fair value of long-lived assets, including goodwill and identifiable intangibles,
are reasonable based on the information that is known when the estimates are made.
Business combinations
The Company accounts for acquisitions on the Consolidated Financial Statements starting from the date of the acquisition, which is the date
that control is obtained. The acquisition method of accounting requires acquired assets and liabilities assumed be recorded at their
respective fair values as of the date of the acquisition. The excess of the purchase price over the fair value of the assets acquired and
liabilities assumed is recorded as goodwill. The estimation of fair values of acquired assets and liabilities assumed by the Company requires
significant judgment and requires various assumptions. Although independent appraisals may be used to assist in the determination of the
fair value of certain assets and liabilities, the appraised values may be based on significant estimates provided by management. The
amounts and useful lives assigned to depreciable and amortizable assets compared to amounts assigned to goodwill, which is not amortized,
can affect the results of operations in the period of and periods subsequent to a business combination.
In determining fair values of acquired assets and liabilities assumed, the Company uses various observable inputs for similar assets or
liabilities in active markets and various unobservable inputs, which includes the use of valuation models. Fair values are based on various
Part II
50 MDU Resources Group, Inc. Form 10-K
factors including, but not limited to, age and condition of property, maintenance records, auction values for equipment with similar
characteristics, recent sales and listings of comparable properties, data collected from drill holes and other subsurface investigations and
geologic data. The Company primarily uses the market and cost approaches in determining the fair value of land and property, plant and
equipment. A combination of the market and income approaches are used for aggregate reserves and intangibles, primarily a discounted
cash flow model.
There is a measurement period after the acquisition date during which the Company may adjust the amounts recognized for a business
combination. Any such adjustments are recorded in the period the adjustment is determined with the corresponding offset to goodwill.
These adjustments are typically based on obtaining additional information that existed at the acquisition date regarding the assets acquired
and the liabilities assumed. The measurement period ends once the Company has obtained all necessary information that existed as of the
acquisition date, but does not extend beyond one year from the date of the acquisition. Once the measurement period has ended, any
adjustments to assets acquired or liabilities assumed are recorded in income from continuing operations.
Revenue recognition
Revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to
which the entity expects to be entitled in exchange for those goods or services. The recognition of revenue requires the Company to make
estimates and assumptions that affect the reported amounts of revenue. The accuracy of revenues reported on the Consolidated Financial
Statements depends on, among other things, management's estimates of total costs to complete projects because the Company uses the
cost-to-cost measure of progress on construction contracts for revenue recognition.
To determine the proper revenue recognition method for contracts, the Company evaluates whether two or more contracts should be
combined and accounted for as one single contract and whether the combined or single contract should be accounted for as more than one
performance obligation. This evaluation requires significant judgment and the decision to combine a group of contracts or separate the
combined or single contract into multiple performance obligations could change the amount of revenue and profit recorded in a given
period. For most contracts, the customer contracts with the Company to provide a significant service of integrating a complex set of tasks
and components into a single project. Hence, the Company's contracts are generally accounted for as one performance obligation.
The Company recognizes construction contract revenue over time using the cost-to-cost measure of progress for contracts because it best
depicts the transfer of assets to the customer which occurs as the Company incurs costs on the contract. Under the cost-to-cost measure of
progress, the costs incurred are compared with total estimated costs of a performance obligation. Revenues are recorded proportionately to
the costs incurred. This method depends largely on the ability to make reasonably dependable estimates related to the extent of progress
toward completion of the contract, contract revenues and contract costs. Inasmuch as contract prices are generally set before the work is
performed, the estimates pertaining to every project could contain significant unknown risks such as volatile labor, material and fuel costs,
weather delays, adverse project site conditions, unforeseen actions by regulatory agencies, performance by subcontractors, job management
and relations with project owners. Changes in estimates could have a material effect on the Company's results of operations, financial
position and cash flows.
Several factors are evaluated in determining the bid price for contract work. These include, but are not limited to, the complexities of the
job, past history performing similar types of work, seasonal weather patterns, competition and market conditions, job site conditions, work
force safety, reputation of the project owner, availability of labor, materials and fuel, project location and project completion dates. As a
project commences, estimates are continually monitored and revised as information becomes available and actual costs and conditions
surrounding the job become known. If a loss is anticipated on a contract, the loss is immediately recognized.
Contracts are often modified to account for changes in contract specifications and requirements. The Company considers contract
modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Generally,
contract modifications are for goods or services that are not distinct from the existing contract due to the significant integration of services
provided in the context of the contract and are accounted for as if they were part of that existing contract. The effect of a contract
modification on the transaction price and the measure of progress for the performance obligation to which it relates, is recognized as an
adjustment to revenue on a cumulative catch-up basis.
The Company's construction contracts generally contain variable consideration including liquidated damages, performance bonuses or
incentives, claims, unapproved/unpriced change orders and penalties or index pricing. The variable amounts usually arise upon achievement
of certain performance metrics or change in project scope. The Company estimates the amount of revenue to be recognized on variable
consideration using estimation methods that best predict the most likely amount of consideration the Company expects to be entitled to or
expects to incur. The Company includes variable consideration in the estimated transaction price to the extent it is probable that a
significant reversal of cumulative revenue recognized will not occur or when the uncertainty associated with the variable consideration is
resolved. Changes in circumstances could impact management's estimates made in determining the value of variable consideration
Part II
MDU Resources Group, Inc. Form 10-K 51
recorded. The Company updates its estimate of the transaction price each reporting period and the effect of variable consideration on the
transaction price is recognized as an adjustment to revenue on a cumulative catch-up basis.
The Company believes its estimates surrounding the cost-to-cost method are reasonable based on the information that is known when the
estimates are made. The Company has contract administration, accounting and management control systems in place that allow its
estimates to be updated and monitored on a regular basis. Because of the many factors that are evaluated in determining bid prices, it is
inherent that the Company's estimates have changed in the past and will continually change in the future as new information becomes
available for each job.
Pension and other postretirement benefits
The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees.
Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to these plans. Costs of
providing pension and other postretirement benefits bear the risk of change, as they are dependent upon numerous factors based on
assumptions of future conditions.
The Company makes various assumptions when determining plan costs, including the current discount rates and the expected long-term
return on plan assets, the rate of compensation increases, actuarially determined mortality data and health care cost trend rates. In
selecting the expected long-term return on plan assets, which is considered to be one of the key variables in determining benefit expense or
income, the Company considers historical returns, current market conditions and expected future market trends, including changes in
interest rates and equity and bond market performance. Another key variable in determining benefit expense or income is the discount rate.
In selecting the discount rate, the Company matches forecasted future cash flows of the pension and postretirement plans to a yield curve
which consists of a hypothetical portfolio of high-quality corporate bonds with varying maturity dates, as well as other factors, as a basis.
The Company's pension and other postretirement benefit plan assets are primarily made up of equity and fixed-income investments.
Fluctuations in actual equity and bond market returns, as well as changes in general interest rates, may result in increased or decreased
pension and other postretirement benefit costs in the future. Management estimates the rate of compensation increase based on long-term
assumed wage increases and the health care cost trend rates are determined by historical and future trends. The Company estimates that a
50 basis point decrease in the discount rate or in the expected return on plan assets would each increase expense by less than $1.5 million
(after tax) for the year ended December 31, 2018.
The Company believes the estimates made for its pension and other postretirement benefits are reasonable based on the information that is
known when the estimates are made. These estimates and assumptions are subject to a number of variables and are expected to change in
the future. Estimates and assumptions will be affected by changes in the discount rate, the expected long-term return on plan assets, the
rate of compensation increase and health care cost trend rates. The Company plans to continue to use its current methodologies to
determine plan costs. For more information on the assumptions used in determining plan costs, see Item 8 - Note 16.
Income taxes
The Company is required to make judgments regarding the potential tax effects of various financial transactions and ongoing operations to
estimate the Company's obligation to taxing authorities. These tax obligations include income, real estate, franchise and sales/use taxes.
Judgments related to income taxes require the recognition in the Company's financial statements a tax position that is more-likely-than-not
to be sustained on audit.
Judgment and estimation is required in developing the provision for income taxes and the reporting of tax-related assets and liabilities and,
if necessary, any valuation allowances. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws
differently. Actual income tax could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash
flows, and tax-related assets and liabilities. In addition, the effective tax rate may be affected by other changes including the allocation of
property, payroll and revenues between states. 
The Company assesses the deferred tax assets for recoverability taking into consideration historical and anticipated earnings levels; the
reversal of other existing temporary differences; available net operating losses and tax carryforwards; and available tax planning strategies
that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and
amount of, a valuation allowance against the deferred tax assets. As facts and circumstances change, adjustment to the valuation allowance
may be required.
Part II
52 MDU Resources Group, Inc. Form 10-K
Non-GAAP Financial Measures
The Business Segment Financial and Operating Data includes financial information prepared in accordance with GAAP, as well as another
financial measure, adjusted gross margin, that is considered a non-GAAP financial measure as it relates to the Company's electric and
natural gas distribution segments. The presentation of adjusted gross margin is intended to be a useful supplemental financial measure for
investors’ understanding of the segments' operating performance. This non-GAAP financial measure should not be considered as an
alternative to, or more meaningful than, GAAP financial measures such as operating income (loss) or earnings (loss). The Company's non-
GAAP financial measure, adjusted gross margin, is not standardized; therefore, it may not be possible to compare this financial measure
with other companies’ gross margin measures having the same or similar names.
In addition to operating revenues and operating expenses, management also uses the non-GAAP financial measure of adjusted gross margin
when evaluating the results of operations for the electric and natural gas distribution segments. Adjusted gross margin for the electric and
natural gas distribution segments is calculated by adding back adjustments to operating income (loss). These add-back adjustments
include: operation and maintenance expense; depreciation, depletion and amortization expense; and certain taxes, other than income.
Adjusted gross margin includes operating revenues less the cost of electric fuel and purchased power, purchased natural gas sold and
certain taxes, other than income. These taxes, other than income, included as a reduction to adjusted gross margin relate to revenue taxes.
These segments pass on to their customers the increases and decreases in the wholesale cost of power purchases, natural gas and other fuel
supply costs in accordance with regulatory requirements. As such, the segments' revenues are directly impacted by the fluctuations in such
commodities. Revenue taxes, which are passed back to customers, fluctuate with revenues as they are calculated as a percentage of
revenues. For these reasons, period over period, the segments' operating income (loss) is generally not impacted. The Company's
management believes the adjusted gross margin is a useful supplemental financial measure as these items are included in both operating
revenues and operating expenses. The Company's management also believes that adjusted gross margin and the remaining operating
expenses that calculate operating income (loss) are useful in assessing the Company's utility performance as management has the ability to
influence control over the remaining operating expenses.
The following information reconciles operating income to adjusted gross margin for the electric segment.
Years ended December 31,2018 2017 2016
(In millions)
Operating income $65.2 $79.9 $67.9
Adjustments:
Operating expenses:
Operation and maintenance 123.0 122.2 115.8
Depreciation, depletion and amortization 51.0 47.7 50.2
Taxes, other than income 14.5 13.5 12.3
Total adjustments 188.5 183.4 178.3
Adjusted gross margin $253.7 $263.3 $246.2
The following information reconciles operating income to adjusted gross margin for the natural gas distribution segment.
Years ended December 31,2018 2017 2016
(In millions)
Operating income $72.3 $84.3 $66.2
Adjustments:
Operating expenses:
Operation and maintenance 173.4 164.3 156.9
Depreciation, depletion and amortization 72.5 69.4 65.4
Taxes, other than income 21.7 20.5 19.6
Total adjustments 267.6 254.2 241.9
Adjusted gross margin $339.9 $338.5 $308.1
Part II
MDU Resources Group, Inc. Form 10-K 53
Effects of Inflation
Inflation did not have a significant effect on the Company's operations in 2018, 2017 or 2016.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company is exposed to the impact of market fluctuations associated with interest rates. The Company has policies and procedures to
assist in controlling these market risks and from time to time has utilized derivatives to manage a portion of its risk.
Interest rate risk
The Company uses fixed and variable rate long-term debt to partially finance capital expenditures and mandatory debt retirements. These
debt agreements expose the Company to market risk related to changes in interest rates. The Company manages this risk by taking
advantage of market conditions when timing the placement of long-term financing. The Company from time to time has utilized interest rate
swap agreements to manage a portion of the Company's interest rate risk and may take advantage of such agreements in the future to
minimize such risk. For additional information on the Company's long-term debt, see Item 8 - Notes 7 and 8.
At December 31, 2018 and 2017, the Company had no outstanding interest rate hedges.
The following table shows the amount of long-term debt, which excludes unamortized debt issuance costs and discount, and related
weighted average interest rates, both by expected maturity dates, as of December 31, 2018.
2019 2020 2021 2022 2023 Thereafter Total FairValue
(Dollars in millions)
Long-term debt:
Fixed rate $51.9 $15.8 $.8 $147.3 $77.2 $1,173.0 $1,466.0 $1,540.9
Weighted average interest rate 4.3%5.1%2.2%4.5%3.7%4.7%4.6%—
Variable rate 200.0 $110.1 $289.6 —$48.5 —$648.2 $648.2
Weighted average interest rate 2.8%4.4%3.1%—2.8%—3.2%—
Part II
54 MDU Resources Group, Inc. Form 10-K
Item 8. Financial Statements and Supplementary Data
Management's Report on Internal Control Over Financial Reporting
The management of MDU Resources Group, Inc. is responsible for establishing and maintaining adequate internal control over financial
reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company's internal control system
is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial
statements for external purposes in accordance with generally accepted accounting principles in the United States of America.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be
effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent
limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2018. In making this
assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in
Internal Control-Integrated Framework (2013).
Based on our evaluation under the framework in Internal Control-Integrated Framework (2013), management concluded that the Company's
internal control over financial reporting was effective as of December 31, 2018.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2018, has been audited by Deloitte &
Touche LLP, an independent registered public accounting firm, as stated in their report.
David L. Goodin Jason L. Vollmer
President and Chief Executive Officer Vice President, Chief Financial Officer and Treasurer
Part II
MDU Resources Group, Inc. Form 10-K 55
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of MDU Resources Group, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of MDU Resources Group, Inc. and subsidiaries (the "Company") as of
December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of
the three years in the period ended December 31, 2018, and the related notes and the financial statement schedules listed in the Index at
Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United
States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22,
2019, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the
Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the
amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits
provide a reasonable basis for our opinion.
Minneapolis, Minnesota
February 22, 2019
We have served as the Company's auditor since 2002.
Part II
56 MDU Resources Group, Inc. Form 10-K
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of MDU Resources Group, Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of MDU Resources Group, Inc. and subsidiaries (the "Company") as of
December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013)
issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2018, of the Company and
our report dated February 22, 2019, expressed an unqualified opinion on those consolidated financial statements and financial statement
schedules.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our
audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and
the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our
audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists,
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Minneapolis, Minnesota
February 22, 2019
Part II
MDU Resources Group, Inc. Form 10-K 57
Consolidated Statements of Income
Years ended December 31,2018 2017 2016
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and regulated pipeline and midstream $1,213,227 $1,244,759 $1,141,454
Nonregulated pipeline and midstream, construction materials and contracting,construction services and other 3,318,325 3,198,592 2,987,374
Total operating revenues 4,531,552 4,443,351 4,128,828
Operating expenses:
Operation and maintenance:
Electric, natural gas distribution and regulated pipeline and midstream 340,331 326,687 312,211
Nonregulated pipeline and midstream, construction materials and contracting,construction services and other 2,915,790 2,808,779 2,581,299
Total operation and maintenance 3,256,121 3,135,466 2,893,510
Purchased natural gas sold 404,153 430,954 382,753
Depreciation, depletion and amortization 220,205 207,486 216,318
Taxes, other than income 168,638 166,673 151,826
Electric fuel and purchased power 80,712 78,724 75,512
Total operating expenses 4,129,829 4,019,303 3,719,919
Operating income 401,723 424,048 408,909
Other income (expense)(238)8,767 5,167
Interest expense 84,614 82,788 87,848
Income before income taxes 316,871 350,027 326,228
Income taxes 47,485 65,041 93,132
Income from continuing operations 269,386 284,986 233,096
Income (loss) from discontinued operations, net of tax (Note 4)2,932 (3,783)(300,354)
Net income (loss)272,318 281,203 (67,258)
Loss from discontinued operations attributable to noncontrolling interest (Note 4)——(131,691)
Loss on redemption of preferred stocks (Note 10)—600 —
Dividends declared on preferred stocks —171 685
Earnings on common stock $272,318 $280,432 $63,748
Earnings per common share - basic:
Earnings before discontinued operations $1.38 $1.46 $1.19
Discontinued operations attributable to the Company, net of tax .01 (.02)(.86)
Earnings per common share - basic $1.39 $1.44 $.33
Earnings per common share - diluted:
Earnings before discontinued operations $1.38 $1.45 $1.19
Discontinued operations attributable to the Company, net of tax .01 (.02)(.86)
Earnings per common share - diluted $1.39 $1.43 $.33
Weighted average common shares outstanding - basic 195,720 195,304 195,299
Weighted average common shares outstanding - diluted 196,150 195,687 195,618
The accompanying notes are an integral part of these consolidated financial statements.
Part II
58 MDU Resources Group, Inc. Form 10-K
Consolidated Statements of Comprehensive Income
Years ended December 31,2018 2017 2016
(In thousands)
Net income (loss)$272,318 $281,203 $(67,258)
Other comprehensive income (loss):
Reclassification adjustment for loss on derivative instruments included in netincome (loss), net of tax of $429, $224 and $226 in 2018, 2017 and 2016,respectively 162 366 367
Postretirement liability adjustment:
Postretirement liability gains (losses) arising during the period, net of tax of$1,471, $(1,162) and $(836) in 2018, 2017 and 2016, respectively 4,441 (1,812)(1,470)
Amortization of postretirement liability losses included in net periodic benefitcost (credit), net of tax of $721, $645 and $1,425 in 2018, 2017 and 2016,respectively 2,173 1,013 2,506
Reclassification of postretirement liability adjustment from regulatory asset, netof tax of $0, $(876) and $0 in 2018, 2017 and 2016, respectively —(1,143)—
Postretirement liability adjustment 6,614 (1,942)1,036
Foreign currency translation adjustment:
Foreign currency translation adjustment recognized during the period, net of taxof $(14), $(3) and $31 in 2018, 2017 and 2016, respectively (61)(6)51
Reclassification adjustment for foreign currency translation adjustment includedin net income (loss), net of tax of $75, $0 and $0 in 2018, 2017 and 2016,respectively 249 ——
Foreign currency translation adjustment 188 (6)51
Net unrealized loss on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period,net of tax of $(38), $(75) and $(98) in 2018, 2017 and 2016, respectively (144)(139)(182)
Reclassification adjustment for loss on available-for-sale investments included innet income (loss), net of tax of $35, $65 and $77 in 2018, 2017 and 2016,respectively 131 120 143
Net unrealized loss on available-for-sale investments (13)(19)(39)
Other comprehensive income (loss)6,951 (1,601)1,415
Comprehensive income (loss)279,269 279,602 (65,843)
Comprehensive loss from discontinued operations attributable to noncontrollinginterest ——(131,691)
Comprehensive income attributable to common stockholders $279,269 $279,602 $65,848
The accompanying notes are an integral part of these consolidated financial statements.
Part II
MDU Resources Group, Inc. Form 10-K 59
Consolidated Balance Sheets
December 31,2018 2017
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents $53,948 $34,599
Receivables, net 722,945 727,030
Inventories 287,309 226,583
Prepayments and other current assets 119,500 81,304
Current assets held for sale 430 479
Total current assets 1,184,132 1,069,995
Investments 138,620 137,613
Property, plant and equipment (Note 1)7,397,321 6,770,829
Less accumulated depreciation, depletion and amortization 2,818,644 2,691,641
Net property, plant and equipment 4,578,677 4,079,188
Deferred charges and other assets:
Goodwill (Note 5)664,922 631,791
Other intangible assets, net (Note 5)10,815 3,837
Other 408,857 407,850
Noncurrent assets held for sale 2,087 4,392
Total deferred charges and other assets 1,086,681 1,047,870
Total assets $6,988,110 $6,334,666
Liabilities and Stockholders' Equity
Current liabilities:
Long-term debt due within one year $251,854 $148,499
Accounts payable 358,505 312,327
Taxes payable 41,929 42,537
Dividends payable 39,695 38,573
Accrued compensation 69,007 72,919
Other accrued liabilities 221,059 186,010
Current liabilities held for sale 4,001 11,993
Total current liabilities 986,050 812,858
Long-term debt (Note 8)1,856,841 1,566,354
Deferred credits and other liabilities:
Deferred income taxes 430,085 347,271
Other 1,148,359 1,179,140
Total deferred credits and other liabilities 1,578,444 1,526,411
Commitments and contingencies (Notes 16, 18 and 19)
Stockholders' equity:
Common stock (Note 11)
Authorized - 500,000,000 shares, $1.00 par valueIssued - 196,564,907 shares in 2018 and 195,843,297 shares in 2017 196,565 195,843
Other paid-in capital 1,248,576 1,233,412
Retained earnings 1,163,602 1,040,748
Accumulated other comprehensive loss (38,342)(37,334)
Treasury stock at cost - 538,921 shares (3,626)(3,626)
Total stockholders' equity 2,566,775 2,429,043
Total liabilities and stockholders' equity $6,988,110 $6,334,666
The accompanying notes are an integral part of these consolidated financial statements.
Part II
60 MDU Resources Group, Inc. Form 10-K
Consolidated Statements of Equity
Years ended December 31, 2018, 2017 and 2016
OtherPaid-inCapital RetainedEarnings
Accumu-latedOtherCompre-hensiveLoss
Noncon-trollingInterest
Preferred Stock Common Stock Treasury Stock
Shares Amount Shares Amount Shares Amount Total
(In thousands, except shares)
At December 31, 2015 150,000 $15,000 195,804,665 $195,805 $1,230,119 $996,355 $(37,148)(538,921)$(3,626)$124,043 $2,520,548
Net income (loss)—————64,433 ———(131,691)(67,258)
Other comprehensiveincome ——————1,415 ———1,415
Dividends declared onpreferred stocks —————(685)————(685)
Dividends declared oncommon stock —————(147,821)————(147,821)
Stock-basedcompensation ————4,383 —————4,383
Net tax deficit on stock-based compensation ————(1,663)—————(1,663)
Issuance of commonstock upon vesting ofstock-basedcompensation,net of shares used fortax withholdings ——38,632 38 (361)—————(323)
Contribution from non-controlling interest —————————7,648 7,648
At December 31, 2016 150,000 15,000 195,843,297 195,843 1,232,478 912,282 (35,733)(538,921)(3,626)—2,316,244
Net income —————281,203 ————281,203
Other comprehensive loss ——————(1,601)———(1,601)
Dividends declared onpreferred stocks —————(171)————(171)
Dividends declared oncommon stock —————(151,966)————(151,966)
Stock-basedcompensation ————3,375 —————3,375
Repurchase of commonstock ———————(64,384)(1,684)(1,684)
Issuance of commonstock upon vesting ofstock-basedcompensation,net of shares used fortax withholdings ————(2,441)——64,384 1,684 —(757)
Redemption of preferredstock (150,000)(15,000)———(600)————(15,600)
At December 31, 2017 ——195,843,297 195,843 1,233,412 1,040,748 (37,334)(538,921)(3,626)—2,429,043
Cumulative effect ofadoption of ASU2014-09 —————(970)————(970)
Adjusted balance atJanuary 1, 2018 ——195,843,297 195,843 1,233,412 1,039,778 (37,334)(538,921)(3,626)—2,428,073
Net income —————272,318 ————272,318
Other comprehensiveincome ——————6,951 ———6,951
Reclassification of certainprior period tax effectsfrom accumulated othercomprehensive loss —————7,959 (7,959)————
Dividends declared oncommon stock —————(156,453)————(156,453)
Stock-basedcompensation ————5,060 —————5,060
Repurchase of commonstock ———————(182,424)(5,020)—(5,020)
Issuance of commonstock upon vesting ofstock-basedcompensation,net of shares used fortax withholdings ————(7,350)——182,424 5,020 —(2,330)
Issuance of commonstock ——721,610 722 17,454 —————18,176
At December 31, 2018 —$—196,564,907 $196,565 $1,248,576 $1,163,602 $(38,342)(538,921)$(3,626)$—$2,566,775
The accompanying notes are an integral part of these consolidated financial statements.
Part II
MDU Resources Group, Inc. Form 10-K 61
Consolidated Statements of Cash Flows
Years ended December 31,2018 2017 2016
(In thousands)
Operating activities:
Net income (loss)$272,318 $281,203 $(67,258)
Income (loss) from discontinued operations, net of tax 2,932 (3,783)(300,354)
Income from continuing operations 269,386 284,986 233,096
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 220,205 207,486 216,318
Deferred income taxes 59,735 (25,423)(2,049)
Changes in current assets and liabilities, net of acquisitions:
Receivables 28,234 (108,255)(25,641)
Inventories (46,796)9,135 2,433
Other current assets (31,814)(30,588)(17,925)
Accounts payable 21,109 26,013 7,039
Other current liabilities 22,285 4,648 36,146
Other noncurrent changes (38,521)(18,790)(26,459)
Net cash provided by continuing operations 503,823 349,212 422,958
Net cash provided by (used in) discontinued operations (3,942)98,799 39,251
Net cash provided by operating activities 499,881 448,011 462,209
Investing activities:
Capital expenditures (568,230)(341,382)(388,183)
Acquisitions, net of cash acquired (167,692)——
Net proceeds from sale or disposition of property and other 26,100 126,588 44,826
Investments (2,321)(1,608)(1,396)
Net cash used in continuing operations (712,143)(216,402)(344,753)
Net cash provided by discontinued operations 1,236 2,234 39,658
Net cash used in investing activities (710,907)(214,168)(305,095)
Financing activities:
Issuance of long-term debt 566,829 140,812 309,064
Repayment of long-term debt (174,520)(217,394)(315,647)
Payments of stock issuance costs (10)——
Dividends paid (154,573)(150,727)(147,156)
Redemption of preferred stock —(15,600)—
Repurchase of common stock (5,020)(1,684)—
Tax withholding on stock-based compensation (2,330)(757)(323)
Net cash provided by (used in) continuing operations 230,376 (245,350)(154,062)
Net cash used in discontinued operations ——(40,852)
Net cash provided by (used in) financing activities 230,376 (245,350)(194,914)
Effect of exchange rate changes on cash and cash equivalents (1)(1)4
Increase (decrease) in cash and cash equivalents 19,349 (11,508)(37,796)
Cash and cash equivalents - beginning of year 34,599 46,107 83,903
Cash and cash equivalents - end of year $53,948 $34,599 $46,107
The accompanying notes are an integral part of these consolidated financial statements.
Part II
62 MDU Resources Group, Inc. Form 10-K
Notes to Consolidated Financial Statements
Part II
MDU Resources Group, Inc. Form 10-K 63
Note 1 - Summary of Significant Accounting Policies
Basis of presentation
The abbreviations and acronyms used throughout are defined following the Notes to Consolidated Financial Statements. The consolidated
financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline and
midstream, construction materials and contracting, construction services and other. The electric and natural gas distribution businesses, as
well as a portion of the pipeline and midstream business, are regulated. Construction materials and contracting, construction services and
the other businesses, as well as a portion of the pipeline and midstream business, are nonregulated. For further descriptions of the
Company's businesses, see Note 15. Intercompany balances and transactions have been eliminated in consolidation, except for certain
transactions related to the Company's regulated operations in accordance with GAAP. The statements also include the ownership interests in
the assets, liabilities and expenses of jointly owned electric generating facilities.
The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these
businesses are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from
those used by the Company's nonregulated businesses.
The Company's regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which
requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or
income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items
generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized
consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for
more information regarding the nature and amounts of these regulatory deferrals.
Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is
excluded from the other line items within operating expenses.
On January 2, 2019, the Company announced the completion of the Holding Company Reorganization, which resulted in Montana-Dakota
and Great Plains becoming a subsidiary of the Company. The purpose of the reorganization was to make the public utility divisions into a
subsidiary of the holding company, just as the other operating companies are wholly owned subsidiaries. Unless otherwise indicated, the
amounts presented in the accompanying notes to the consolidated financial statements relate to the Company's corporate structure prior to
the Holding Company Reorganization.
On December 22, 2017, President Trump signed into law the TCJA which includes lower corporate tax rates, repealing the domestic
production deduction, disallowance of immediate expensing for regulated utility property and modifying or repealing many other business
deductions and credits. The reduction in the corporate tax rate was effective on January 1, 2018. The effects of the change in tax laws or
rates must be accounted for in the period of enactment, which resulted in the Company making reasonable estimates of the impact of the
reduction in corporate tax rate on the Company's net deferred tax liabilities during the fourth quarter of 2017. The SEC issued rules that
allowed for a measurement period of up to one year after the enactment date of the TCJA to finalize the recording of the related tax impacts.
At December 31, 2018, the Company finalized the estimates from the fourth quarter of 2017 and no material adjustments were recorded to
income from continuing operations during the twelve months ended December 31, 2018.
Due to the enactment of the TCJA, the regulated jurisdictions in which the Company's regulated businesses provide service requested the
Company furnish plans for the effect of the reduced corporate tax rate, which impacted the Company's rates to customers. Therefore, the
Company reserved for such impacts as an offset to revenue or passed back to customers through lower rates in certain jurisdictions. For
more information on the details and statuses of the open requests, see Note 18.
Effective January 1, 2018, the Company adopted the requirements of the accounting standard update on revenue from contracts with
customers following the modified retrospective method, as further discussed in this note, as well as in Note 2. As such, results for reporting
periods beginning January 1, 2018, are presented under the new guidance, while prior period amounts are not adjusted and continue to be
reported in accordance with the historic accounting for revenue recognition. Based on the Company's analysis, the Company did not identify
a significant change in the timing of revenue recognition under the new guidance as compared to the historic accounting for revenue
recognition.
Certain prior year amounts have been reclassified to conform to the current year presentation in the consolidated financial statements
related to the retrospective adoption of the accounting standard update to improve the presentation of net periodic pension and net periodic
postretirement benefit costs, which was effective on January 1, 2018. The components of net periodic pension and postretirement costs,
other than service costs, were reclassified from operating expenses to other income on the Consolidated Statements of Income, as further
discussed in this note.
The assets and liabilities for the Company's discontinued operations have been classified as held for sale and the results of operations are
shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not
meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation,
depletion and amortization expense was no longer recorded. Unless otherwise indicated, the amounts presented in the accompanying notes
to the consolidated financial statements relate to the Company's continuing operations. For more information on the Company's
discontinued operations, see Note 4.
Management has also evaluated the impact of events occurring after December 31, 2018, up to the date of issuance of these consolidated
financial statements.
Cash and cash equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Accounts receivable and allowance for doubtful accounts
Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount
net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. For more
information, see Note 2. The total balance of receivables past due 90 days or more was $30.0 million and $34.7 million at December 31,
2018 and 2017, respectively.
The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances
are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at
December 31, 2018 and 2017, was $8.9 million and $8.1 million, respectively.
Accounts receivable also consists of accrued unbilled revenue representing revenues recognized in excess of amounts billed. Accrued
unbilled revenue at Montana-Dakota, Cascade and Intermountain was $96.2 million and $112.7 million at December 31, 2018 and 2017,
respectively.
Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31 were as follows:
2018 2017
(In thousands)
Short-term retainage*$56,228 $57,134
Long-term retainage**4,152 1,410
Total retainage $60,380 $58,544
*Expected to be paid within one year or less and included in receivables, net.
**Included in deferred charges and other assets - other.
Inventories and natural gas in storage
Natural gas in storage for the Company's regulated operations is generally carried at lower of cost or net realizable value, or cost using the
last-in, first-out method. All other inventories are stated at the lower of cost or net realizable value. The portion of the cost of natural gas in
storage expected to be used within one year was included in inventories. Inventories at December 31 consisted of:
2018 2017
(In thousands)
Aggregates held for resale $139,681 $115,268
Asphalt oil 54,741 30,360
Materials and supplies 23,611 18,650
Merchandise for resale 22,552 14,905
Natural gas in storage (current)22,117 20,950
Other 24,607 26,450
Total $287,309 $226,583
Part II
64 MDU Resources Group, Inc. Form 10-K
The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating
purposes, was included in deferred charges and other assets - other and was $48.5 million and $49.3 million at December 31, 2018 and
2017, respectively.
Investments
The Company's investments include the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities
and U.S. Treasury securities. The Company measures its investment in the insurance contract at fair value with any unrealized gains and
losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed
securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated
other comprehensive income (loss). For more information, see Notes 7 and 16.
Property, plant and equipment
Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary
course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all
other assets, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize AFUDC on
regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the
Company capitalizes interest, when applicable, on certain construction projects associated with its other operations. The amount of AFUDC
for the years ended December 31 were as follows:
2018 2017 2016
(In thousands)
AFUDC - borrowed $2,290 $966 $914
AFUDC - equity $1,897 $909 $565
Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for
depletable aggregate reserves, which are depleted based on the units-of-production method. The Company collects removal costs for plant
assets in regulated utility rates. These amounts are recorded as regulatory liabilities, which are included in deferred credits and other
liabilities - other.
Part II
MDU Resources Group, Inc. Form 10-K 65
Property, plant and equipment at December 31 was as follows:
2018 2017
WeightedAverageDepreciableLife in Years
(Dollars in thousands, where applicable)
Regulated:
Electric:
Generation $1,131,484 $1,034,765 49
Distribution 430,750 415,543 46
Transmission 302,315 296,941 64
Construction in progress 161,893 117,906 —
Other 122,127 117,109 13
Natural gas distribution:
Distribution 1,981,356 1,831,795 47
Construction in progress 21,028 19,823 —
Other 496,708 468,227 16
Pipeline and midstream:
Transmission 585,594 516,932 54
Gathering 37,829 37,837 20
Storage 49,101 45,629 61
Construction in progress 5,915 17,488 —
Other 45,763 41,054 33
Nonregulated:
Pipeline and midstream:
Gathering and processing 31,094 31,678 19
Construction in progress 86 17 —
Other 9,577 9,649 10
Construction materials and contracting:
Land 109,541 95,745 —
Buildings and improvements 114,905 102,435 20
Machinery, vehicles and equipment 1,090,790 947,979 12
Construction in progress 22,507 7,750 —
Aggregate reserves 430,263 406,139 *
Construction services:
Land 5,216 5,216 —
Buildings and improvements 29,795 27,351 25
Machinery, vehicles and equipment 145,859 137,924 6
Other 7,716 6,774 3
Other:
Land 2,648 2,837 —
Other 25,461 28,286 14
Less accumulated depreciation, depletion and amortization 2,818,644 2,691,641
Net property, plant and equipment $4,578,677 $4,079,188
*Depleted on the units-of-production method based on recoverable aggregate reserves.
Impairment of long-lived assets
The Company reviews the carrying values of its long-lived assets, excluding goodwill and assets held for sale, whenever events or changes in
circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is
based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If
impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a
loss if the carrying value is greater than the fair value. The impairments are recorded in operation and maintenance expense on the
Consolidated Statements of Income.
No significant impairment losses were recorded in 2018, 2017 or 2016, other than those related to the Company's assets held for sale and
discontinued operations recorded in 2016. For more information regarding these impairments, see Note 4.
Part II
66 MDU Resources Group, Inc. Form 10-K
Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a
business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more
frequently if events or changes in circumstances indicate that goodwill may be impaired.
The goodwill impairment test is a two-step process performed at the reporting unit level. The Company has determined that the reporting
units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for
which discrete financial information is available and for which segment management regularly reviews the operating results. For more
information on the Company's operating segments, see Note 15. The first step of the impairment test involves comparing the fair value of
each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no
impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the
amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the
carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the
years ended December 31, 2018, 2017 and 2016, there were no impairment losses recorded. At December 31, 2018, the fair value
substantially exceeded the carrying value at all reporting units.
Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the
Company's future revenue, profitability and cash flows, amount and timing of estimated capital expenditures, inflation rates, risk adjusted
cost of capital, operational plans, and current and future economic conditions, among others. The fair value of each reporting unit is
determined using a weighted combination of income and market approaches. The Company uses a discounted cash flow methodology for its
income approach. Under the income approach, the discounted cash flow model determines fair value based on the present value of
projected cash flows over a specified period and a residual value related to future cash flows beyond the projection period. Both values are
discounted using a rate which reflects the best estimate of the risk adjusted cost of capital at each reporting unit. The risk adjusted cost of
capital, which varies by reporting unit and is in the range of 5 percent to 9 percent, and a long-term growth rate projection of approximately
3 percent were utilized in the goodwill impairment test performed in the fourth quarter of 2018. Under the market approach, the Company
estimates fair value using multiples derived from enterprise value to EBITDA for comparative peer companies for each respective reporting
unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company
adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that
would be received in a sale in an orderly transaction between market participants. The Company believes that the estimates and
assumptions used in its impairment assessments are reasonable and based on available market information.
Revenue recognition
Revenue is recognized when a performance obligation is satisfied by transferring control over a product or service to a customer. Revenue is
measured based on consideration specified in a contract with a customer, and excludes any sales incentives and amounts collected on
behalf of third parties. The Company is considered an agent for certain taxes collected from customers. As such, the Company presents
revenues net of these taxes at the time of sale to be remitted to governmental authorities, including sales and use taxes.
The electric and natural gas distribution segments generate revenue from the sales of electric and natural gas products and services, which
includes retail and transportation services. These segments establish a customer's retail or transportation service account based on the
customer's application/contract for service, which indicates approval of a contract for service. The contract identifies an obligation to provide
service in exchange for delivering or standing ready to deliver the identified commodity; and the customer is obligated to pay for the service
as provided in the applicable tariff. The product sales are based on a fixed rate that includes a base and per-unit rate, which are included in
approved tariffs as determined by state or federal regulatory agencies. The quantity of the commodity consumed or transported determines
the total per-unit revenue. The service provided, along with the product consumed or transported, are a single performance obligation
because both are required in combination to successfully transfer the contracted product or service to the customer. Revenues are
recognized over time as customers receive and consume the products and services. The method of measuring progress toward the
completion of the single performance obligation is on a per-unit output method basis, with revenue recognized based on the direct
measurement of the value to the customer of the goods or services transferred to date. For contracts governed by the Company’s utility
tariffs, amounts are billed monthly with the amount due between 15 and 22 days of receipt of the invoice depending on the applicable
state’s tariff. For other contracts not governed by tariff, payment terms are net 30 days. At this time, the segment has no material
obligations for returns, refunds or other similar obligations.
The pipeline and midstream segment generates revenue from providing natural gas transportation, gathering and underground storage
services, as well as other energy-related services to both third parties and internal customers, largely the natural gas distribution segment.
The pipeline and midstream segment establishes a contract with a customer based upon the customer’s request for firm or interruptible
Part II
MDU Resources Group, Inc. Form 10-K 67
natural gas transportation, storage or gathering service(s). The contract identifies an obligation for the segment to provide the requested
service(s) in exchange for consideration from the customer over a specified term. Depending on the type of service(s) requested and
contracted, the service provided may include transporting, gathering or storing an identified quantity of natural gas and/or standing ready to
deliver or store an identified quantity of natural gas. Natural gas transportation, gathering and storage revenues are based on fixed rates,
which may include reservation fees and/or per-unit commodity rates. The services provided by the segment are generally treated as single
performance obligations satisfied over time simultaneous to when the service is provided and revenue is recognized. Rates for the segment’s
regulated services are based on its FERC approved tariff or customer negotiated rates on special projects, and rates for its non-regulated
services are negotiated with its customers and set forth in the contract. For contracts governed by the company’s tariff, amounts are billed
on or before the ninth business day of the following month and the amount is due within 12 days of receipt of the invoice. For gathering
contracts not governed by the tariff, amounts are due within twenty days of invoice receipt. For other contracts not governed by the tariff,
payment terms are net 30 days. At this time, the segment has no material obligations for returns, refunds or other similar obligations.
The construction materials and contracting segment generates revenue from contracting services and construction materials sales. This
segment focuses on the vertical integration of its contracting services with its construction materials to support the aggregate based product
lines. This segment provides contracting services to a customer when a contract has been signed by both the customer and a representative
of the segment obligating a service to be provided in exchange for the consideration identified in the contract. The nature of the services
this segment provides generally includes integrating a set of services and related construction materials into a single project to create a
distinct bundle of goods and services, which the Company evaluates to determine whether a separate performance obligation exists. The
transaction price is the original contract price plus any subsequent change orders and variable consideration. Examples of variable
consideration that exist in this segment's contracts include liquidated damages; performance bonuses or incentives and penalties; claims;
unapproved/unpriced change orders; and index pricing. The variable amounts usually arise upon achievement of certain performance metrics
or change in project scope. The Company estimates the amount of revenue to be recognized on variable consideration using estimation
methods that best predict the most likely amount of consideration the Company expects to be entitled to or expects to incur. The Company
includes variable consideration in the estimated transaction price to the extent it is probable that a significant reversal of cumulative
revenue recognized will not occur or when the uncertainty associated with the variable consideration is resolved. Changes in circumstances
could impact management's estimates made in determining the value of variable consideration recorded. The Company updates its estimate
of the transaction price each reporting period and the effect of variable consideration on the transaction price is recognized as an
adjustment to revenue on a cumulative catch-up basis. Revenue is recognized over time using the input method based on the measurement
of progress on a project. The input method is the preferred method of measuring revenue because the costs incurred have been determined
to represent the best indication of the overall progress toward the transfer of such goods or services promised to a customer. This segment
also sells construction materials to third parties and internal customers. The contract for material sales is the use of a sales order or an
invoice, which includes the pricing and payment terms. All material contracts contain a single performance obligation for the delivery of a
single distinct product or a distinct separately identifiable bundle of products and services. Revenue is recognized at a point in time when
the performance obligation has been satisfied with the delivery of the products or services. The warranties associated with the sales are
those consistent with a standard warranty that the product meets certain specifications for quality or those required by law. For most
contracts, amounts billed to customers are due within 30 days of receipt. There are no material obligations for returns, refunds or other
similar obligations.
The construction services segment generates revenue from specialty contracting services which also includes the sale of construction
equipment and other supplies. This segment provides specialty contracting services to a customer when a contract has been signed by both
the customer and a representative of the segment obligating a service to be provided in exchange for the consideration identified in the
contract. The nature of the services this segment provides generally includes multiple promised goods and services in a single project to
create a distinct bundle of goods and services, which the Company evaluates to determine whether a separate performance obligation exists.
The transaction price is the original contract price plus any subsequent change orders and variable consideration. Examples of variable
consideration that exist in this segment's contracts include claims, unapproved/unpriced change orders, bonuses, incentives, penalties and
liquidated damages. The variable amounts usually arise upon achievement of certain performance metrics or change in project scope. The
Company estimates the amount of revenue to be recognized on variable consideration using estimation methods that best predict the most
likely amount of consideration the Company expects to be entitled to or expects to incur. The Company includes variable consideration in
the estimated transaction price to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur or
when the uncertainty associated with the variable consideration is resolved. Changes in circumstances could impact management's
estimates made in determining the value of variable consideration recorded. The Company updates its estimate of the transaction price each
reporting period and the effect of variable consideration on the transaction price is recognized as an adjustment to revenue on a cumulative
catch-up basis. Revenue is recognized over time using the input method based on the measurement of progress on a project. The input
method is the preferred method of measuring revenue because the costs incurred have been determined to represent the best indication of
the overall progress toward the transfer of such goods or services promised to a customer. This segment also sells construction equipment
and other supplies to third parties and internal customers. The contract for these sales is the use of a sales order or invoice, which includes
the pricing and payment terms. All such contracts include a single performance obligation for the delivery of a single distinct product or a
Part II
68 MDU Resources Group, Inc. Form 10-K
distinct separately identifiable bundle of products and services. Revenue is recognized at a point in time when the performance obligation
has been satisfied with the delivery of the products or services. The warranties associated with the sales are those consistent with a standard
warranty that the product meets certain specifications for quality or those required by law. For most contracts, amounts billed to customers
are due within 30 days of receipt. There are no material obligations for returns, refunds or other similar obligations.
The Company recognizes all other revenues when services are rendered or goods are delivered. For more information on revenue from
contracts with customers, see Note 2.
Asset retirement obligations
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is
initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is
accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of
the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its nonregulated operations or
incurs a regulatory asset or liability at its regulated operations. For more information on asset retirement obligations, see Note 9.
Legal costs
The Company expenses external legal fees as they are incurred.
Natural gas costs recoverable or refundable through rate adjustments
Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity,
transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such
orders generally provide that these amounts are recoverable or refundable through rate adjustments which are filed annually. Natural gas
costs refundable through rate adjustments were $30.0 million and $28.5 million at December 31, 2018 and 2017, respectively, which is
included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $42.7 million and $14.5 million at
December 31, 2018 and 2017, respectively, which is included in prepayments and other current assets.
Stock-based compensation
The Company determines compensation expense for stock-based awards based on the estimated fair values at the grant date and recognizes
the related compensation expense over the vesting period. The Company uses the straight-line amortization method to recognize
compensation expense related to restricted stock, which only has a service condition. This method recognizes stock compensation expense
on a straight-line basis over the requisite service period for the entire award. The Company recognizes compensation expense related to
performance awards that vest based on performance metrics and service conditions on a straight-line basis over the service period.
Inception-to-date expense is adjusted based upon the determination of the potential achievement of the performance target at each
reporting date. The Company recognizes compensation expense related to performance awards with market-based performance metrics on a
straight-line basis over the requisite service period.
The Company records the compensation expense for performance share awards using an estimated forfeiture rate. The estimated forfeiture
rate is calculated based on an average of actual historical forfeitures. The Company also preforms an analysis of any known factors at the
time of the calculation to identify any necessary adjustments to the average historical forfeiture rate. At the time actual forfeitures become
more than estimated forfeitures, the Company records compensation expense using actual forfeitures.
Income taxes
The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the
Company's assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect
of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. Excess
deferred income tax balances associated with the Company's rate-regulated activities have been recorded as a regulatory liability and are
included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in
accordance with applicable regulatory procedures.
The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural
gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service
commissions.
The Company records uncertain tax positions in accordance with accounting guidance on accounting for income taxes on the basis of a two-
step process in which (1) the Company determines whether it is more-likely-than-not that the tax position will be sustained on the basis of
the technical merits of the position and (2) for those tax positions that meet the more-likely than-not recognition threshold, the Company
recognizes the largest amount of the tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related
Part II
MDU Resources Group, Inc. Form 10-K 69
tax authority. Tax positions that do not meet the more-likely-than-not criteria are reflected as a tax liability. The Company recognizes interest
and penalties accrued related to unrecognized tax benefits in income taxes.
Earnings per common share
Basic earnings per common share were computed by dividing earnings on common stock by the weighted average number of shares of
common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by
the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of nonvested performance
share awards and restricted stock units. Common stock outstanding includes issued shares less shares held in treasury. Earnings on
common stock was the same for both the basic and diluted earnings per share calculations. A reconciliation of the weighted average
common shares outstanding used in the basic and diluted earnings per share calculation was as follows:
2018 2017 2016
(In thousands)
Weighted average common shares outstanding - basic 195,720 195,304 195,299
Effect of dilutive performance share awards 430 383 319
Weighted average common shares outstanding - diluted 196,150 195,687 195,618
Shares excluded from the calculation of diluted earnings per share 10 ——
Use of estimates
The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the
reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, as well
as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as long-lived assets and
goodwill; fair values of acquired assets and liabilities under the acquisition method of accounting; aggregate reserves; property depreciable
lives; tax provisions; revenue recognized using the cost-to-cost measure of progress for contracts; uncollectible accounts; environmental and
other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues;
actuarially determined benefit costs; asset retirement obligations; and the valuation of stock-based compensation. As additional information
becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected
by revisions to prior accounting estimates.
New accounting standards
Recently adopted accounting standards
ASU 2014-09 - Revenue from Contracts with Customers In May 2014, the FASB issued guidance on accounting for revenue from contracts with
customers. The guidance provides for a single comprehensive model for entities to use in accounting for revenue arising from contracts with
customers and supersedes most current revenue recognition guidance, including industry specific guidance. In August 2015, the FASB
issued guidance deferring the effective date of the revenue guidance and allowing entities to early adopt. With this decision, the guidance
was effective for the Company on January 1, 2018. Entities had the option of using either a full retrospective or modified retrospective
approach to adopting the guidance. Under the modified retrospective approach, an entity recognizes the cumulative effect of initially
applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.
The Company adopted the guidance on January 1, 2018, using the modified retrospective approach. The Company elected the practical
expedient to not disclose the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied (or
partially unsatisfied) as of the end of the reporting period, along with an explanation of when such revenue would be expected to be
recognized. This practical expedient was used since the performance obligations are part of contracts with an original duration of one year or
less. The Company also elected the practical expedient to recognize the incremental costs of obtaining a contract as an expense when
incurred if the amortization period of the asset that the Company otherwise would have recognized is one year or less. Upon completion of
the Company's evaluation of contracts and methods of revenue recognition under the previous accounting guidance, the Company did not
identify any material cumulative effect adjustments to be made to retained earnings. In addition, the Company has expanded revenue
disclosures, both quantitatively and qualitatively, related to the nature, amount, timing and uncertainty of revenue and cash flows arising
from contracts with customers, as discussed in Note 2. The Company reviewed its revenue streams to evaluate the impact of this guidance
and did not identify a significant change in the timing of revenue recognition, results of operations, financial position or cash flows. The
Company reviewed its internal controls related to revenue recognition and disclosures and concluded that the guidance impacted certain
business processes and controls. As such, the Company developed modifications to its internal controls for certain topics under the
guidance as they apply to the Company and such modifications were not deemed to be significant. Results for reporting periods beginning
after December 31, 2017, are presented under the new guidance, while prior period amounts are not adjusted and continue to be reported
in accordance with historic accounting for revenue recognition.
Part II
70 MDU Resources Group, Inc. Form 10-K
Under the modified retrospective approach, the guidance was applied only to contracts that were not completed as of January 1, 2018.
Therefore, the Company recognized the cumulative effect of initially applying the guidance with an adjustment to the opening balance of
retained earnings at January 1, 2018. For the twelve months ended December 31, 2018, there were no material impacts to the financial
statements as a result of applying the guidance. The cumulative effect of the changes made to the Consolidated Balance Sheet were as
follows:
December 31, 2017 Adjustments January 1, 2018
(In thousands)
Liabilities and Stockholders' Equity
Current liabilities:
Other accrued liabilities $186,010 $903 $186,913
Deferred credits and other liabilities:
Deferred income taxes 347,271 (332)346,939
Other 1,179,140 399 1,179,539
Commitments and contingencies
Stockholders' equity:
Common stockholders' equity:
Retained earnings 1,040,748 (970)1,039,778
The cumulative effect adjustment is related to prepaid natural gas transportation to storage contracts where a separate performance
obligation existed and has not yet been satisfied. As such, these contracts were still open and met the criteria for a cumulative effect
adjustment.
ASU 2016-15 - Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued guidance to clarify the
classification of certain cash receipts and payments in the statement of cash flows. The guidance is intended to standardize the
presentation and classification of certain transactions, including cash payments for debt prepayment or extinguishment, proceeds from
insurance claim settlements and distributions from equity method investments. In addition, the guidance clarifies how to classify
transactions that have characteristics of more than one class of cash flows. The Company adopted the guidance on January 1, 2018, on a
prospective basis. The guidance did not have a material effect on the Company's statement of cash flows.
ASU 2017-01 - Clarifying the Definition of a Business In January 2017, the FASB issued guidance to assist entities with evaluating whether
transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when
an integrated set of assets and activities is not a business. The guidance also affects other aspects of accounting, such as determining
reporting units for goodwill testing and whether an entity has acquired or sold a business. The Company adopted the guidance on January 1,
2018, on a prospective basis. The guidance did not have a material effect on the Company's results of operations, financial position, cash
flows or disclosures.
ASU 2017-07 - Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB
issued guidance to improve the presentation of net periodic pension and net periodic postretirement benefit costs. The guidance required
the service cost component to be presented in the income statement in the same line item or items as other compensation costs arising
from services performed during the period. Other components of net periodic benefit cost shall be presented in the income statement
separately from the service cost component and outside a subtotal of income from operations. The guidance also only allows the service cost
component to be capitalized.
The Company adopted the guidance on January 1, 2018, on a retrospective basis. The guidance required the reclassification of all
components of net periodic benefit costs, except for the service cost component, from operating expenses to other income on the
Consolidated Statements of Income with no impact to earnings. As a result of the retrospective application of this change in accounting
guidance, the Company reclassified $6.2 million and $4.5 million from operation and maintenance expense to other income on the
Consolidated Statements of Income for the years ended December 31, 2017 and 2016, respectively. The Company also reclassified
unrealized gains on investments used to satisfy obligations under the defined benefit plans of $10.8 million and $4.7 million for the years
ended December 31, 2017 and 2016, respectively, which were included in operation and maintenance expense, to other income on the
Consolidated Statements of Income. The guidance did not have a material effect on the Company's results of operations, cash flows or
disclosures.
ASU 2018-02 - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued
guidance that allows an entity to reclassify the stranded tax effects resulting from the newly enacted federal corporate income tax rate from
accumulated other comprehensive income (loss) to retained earnings. The guidance is effective for the Company on January 1, 2019,
Part II
MDU Resources Group, Inc. Form 10-K 71
including interim periods, with early adoption permitted. The guidance can be applied using one of two methods. One method is to record
the reclassification of the stranded income taxes at the beginning of the period of adoption. The other method is to apply the guidance
retrospectively to each period in which the income tax effects of the TCJA are recognized in accumulated other comprehensive income
(loss). The Company early adopted the guidance on January 1, 2018, and elected to reclassify the stranded income taxes at the beginning
of the period. During the first quarter of 2018, the Company reclassified $7.9 million of stranded tax expense from accumulated other
comprehensive loss to retained earnings. The guidance did not have a material effect on the Company's results of operations, cash flows or
disclosures.
SEC File Number S7-15-16 - Disclosure Update and Simplification In October 2018, the SEC published guidance in the Federal Register on
disclosure updates and simplifications. The guidance removed disclosures that are no longer considered cost beneficial, duplicative of GAAP
required disclosures, clarified the specific requirements of disclosures and added disclosure requirements identified as relevant. The
amendments were intended to facilitate disclosure of information to investors and simplify the compliance without significantly altering the
total mix of information provided to investors. The guidance was effective for the Company on November 5, 2018, including interim periods.
The Company adopted the guidance in the Annual Report on Form 10-K for the year ended December 31, 2018, which required minimal
disclosure updates. The guidance was applied on a prospective basis and did not have a material effect on the Company's disclosures or
certain sections of the Annual Report on Form 10-K.
Recently issued accounting standards not yet adopted
ASU 2016-02 - Leases In February 2016, the FASB issued guidance regarding leases. The guidance requires lessees to recognize a lease
liability and a right-of-use asset on the balance sheet for operating and financing leases. The guidance remains largely the same for lessors,
although some changes were made to better align lessor accounting with the new lessee accounting and to align with the revenue
recognition standard. The guidance also requires additional disclosures, both quantitative and qualitative, related to operating and finance
leases for the lessee and sales-type, direct financing and operating leases for the lessor. The Company adopted the standard on January 1,
2019.
In July 2018, the FASB issued ASU 2018-11 - Leases: Targeted Improvements, an accounting standard update to ASU 2016-02. This ASU
provides an entity the option to adopt the guidance using one of two modified retrospective approaches. An entity can adopt the guidance
using the modified retrospective transition approach beginning in the earliest year presented in the financial statements. This method of
adoption would require the restatement of prior periods reported and the presentation of lease disclosures under the new guidance for all
periods reported. The additional transition method of adoption introduced by ASU 2018-11, allows entities the option to apply the guidance
on the date of adoption by recognizing a cumulative effect adjustment to retained earnings during the period of adoption and does not
require prior comparative periods to be restated. The Company adopted the standard on January 1, 2019, utilizing the practical expedient
that allows the Company to not reassess whether an expired or existing contract contains a lease, the classification of leases or initial direct
costs, as well as the additional transition method of adoption applied on the date of adoption. The Company also adopted a short-term
leasing policy as the lessee where leases with a term of 12 months or less will not be included on the Consolidated Balance Sheet.
In January 2018, the FASB issued a practical expedient for land easements under the new lease guidance. The practical expedient permits
an entity to elect the option to not evaluate land easements under the new guidance if they existed or expired before the adoption of the new
lease guidance and were not previously accounted for as leases under the previous lease guidance. Once an entity adopts the new guidance,
the entity should apply the new guidance on a prospective basis to all new or modified land easements. The Company has adopted this
practical expedient. The Company will evaluate any new or modified agreements that fall within the scope of the standard. The Company
continues to monitor other industry-specific issues as it relates to its regulated businesses but does not expect these issues to have a
material impact on the Company's results of operations, financial position or disclosures.
The Company formed a lease implementation team to review and assess existing contracts to identify and evaluate those containing leases.
Additionally, the team has implemented new and revised existing software to meet the reporting and disclosure requirements of the
standard. The Company also has assessed the impact the standard will have on its processes and internal controls and has identified new
and updated existing internal controls and processes to ensure compliance with the new lease standard; such modifications were not
deemed to be significant. During the assessment phase, the Company used various surveys, reconciliations and analytic methodologies to
ensure the completeness of the lease inventory. The Company determined that most of the current operating leases are subject to the
guidance and will be recognized as operating lease liabilities and right-of-use assets on the Consolidated Balance Sheets upon adoption.
The Company expects the impact of the lessee guidance to be approximately $105 million to $125 million of an increase to assets and
liabilities on January 1, 2019. In addition, the Company has evaluated the impact the new guidance will have on lease contracts where the
Company is the lessor and does not anticipate a significant impact.
ASU 2017-04 - Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued guidance on simplifying the test for goodwill
impairment by eliminating Step 2, which required an entity to measure the amount of impairment loss by comparing the implied fair value
of reporting unit goodwill with the carrying amount of such goodwill. This guidance requires entities to perform a quantitative impairment
Part II
72 MDU Resources Group, Inc. Form 10-K
test, previously Step 1, to identify both the existence of impairment and the amount of impairment loss by comparing the fair value of a
reporting unit to its carrying amount. Entities will continue to have the option of performing a qualitative assessment to determine if the
quantitative impairment test is necessary. The guidance also requires additional disclosures if an entity has one or more reporting units with
zero or negative carrying amounts of net assets. The guidance will be effective for the Company on January 1, 2020, and must be applied
on a prospective basis with early adoption permitted. The Company does not expect the guidance to have a material impact on its results of
operations, financial position, cash flows and disclosures.
ASU 2018-13 - Changes to the Disclosure Requirements for Fair Value Measurement In August 2018, the FASB issued guidance on modifying
the disclosure requirements on fair value measurements as part of the disclosure framework project. The guidance modifies, among other
things, the disclosures required for Level 3 fair value measurements, including the range and weighted average of significant unobservable
inputs. The guidance removes, among other things, the disclosure requirement to disclose transfers between Levels 1 and 2. The guidance
will be effective for the Company on January 1, 2020, including interim periods, with early adoption permitted. Level 3 fair value
measurement disclosures should be applied prospectively while all other amendments should be applied retrospectively. The Company is
evaluating the effects the adoption of the new guidance will have on its disclosures.
ASU 2018-14 - Changes to the Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued guidance on modifying the
disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans as part of the disclosure
framework project. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of
disclosures and adds disclosure requirements identified as relevant. The guidance adds, among other things, the requirement to include an
explanation for significant gains and losses related to changes in benefit obligations for the period. The guidance removes, among other
things, the disclosure requirement to disclose the amount of net periodic benefit costs to be amortized over the next fiscal year from
accumulated other comprehensive income (loss) and the effects a one percentage point change in assumed health care cost trend rates will
have on certain benefit components. The guidance will be effective for the Company on January 1, 2021, and must be applied on a
retrospective basis with early adoption permitted. The Company is evaluating the effects the adoption of the new guidance will have on the
its disclosures.
ASU 2018-15 - Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract In
August 2018, the FASB issued guidance on the accounting for implementation costs of a hosting arrangement that is a service contract.
The guidance aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract
similar to the costs incurred to develop or obtain internal-use software and such capitalized costs to be expensed over the term of the
hosting arrangement. Costs incurred during the preliminary and postimplementation stages should continue to be expensed as activities are
performed. The capitalized costs are required to be presented on the balance sheet in the same line the prepayment for the fees associated
with the hosting arrangement would be presented. In addition, the expense related to the capitalized implementation costs should be
presented in the same line on the income statement as the fees associated with the hosting element of the arrangements. The guidance will
be effective for the Company on January 1, 2020, including interim periods, and may be applied on a retrospective or a prospective basis
with early adoption permitted. The Company adopted the guidance effective January 1, 2019, on a prospective basis. The adoption of the
guidance will not have a material impact on its results of operations, financial position, cash flows and disclosures.
ASU 2018-18 - Clarifying the Interaction between Topic 808 and Topic 606 In November 2018, the FASB issued guidance on whether certain
transactions between collaborative arrangement participants should be accounted for within revenue under Topic 606 in order to provide for
better comparability among entities. The guidance clarifies which transactions should be accounted for as revenue under Topic 606 and
provides unit-of-account guidance in Topic 808 to align with the guidance in Topic 606 regarding distinct goods or services. The guidance
also specifies that transactions with a collaborative arrangement not directly related to sales to third parties may not be presented together
with revenue recognized under Topic 606. The guidance will be effective for the Company on January 1, 2020, including interim periods,
and must be applied retrospectively to January 1, 2018, the date in which the Company adopted Topic 606. An entity may apply the
guidance to either all contracts or to only contracts that are not completed as of the date of the initial application of Topic 606. The
Company is evaluating the effects the adoption of the new guidance will have on the its results of operations, financial position, cash flows
and disclosures.
SEC Final Rulemaking Release Number 33-10570 - Modernization of Property Disclosures for Mining Registrants In November 2018, the SEC
published guidance in the Federal Register on the modernization of property disclosures for mining registrants. The guidance requires
additional disclosures related to activities under material mining operations to be included as an exhibit, including a technical report
summary by a qualified person about an organization's mineral resources or mineral reserves; an overview of mining properties and
operations; a summary of all mineral resources and mineral reserves as of the most recently completed fiscal year; a description of each
material property, including the proposed program of exploration and development, stage of the development or production, and current
production activities, among other things; and a description of the organization's internal controls surrounding mineral resource and reserve
estimates. The guidance will be effective on a prospective basis for the Company on January 1, 2021, including interim periods, with early
Part II
MDU Resources Group, Inc. Form 10-K 73
adoption permitted. The Company is evaluating the effects the adoption of the guidance will have on its disclosures in the Annual Report on
Form 10-K.
Variable interest entities
The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the
primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities,
noncontrolling interest and results of activities of a VIE in its consolidated financial statements.
A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has
the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could
be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the
primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and
subsequently account for the VIE as if it were consolidated.
The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions
and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company
has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement.
Comprehensive income (loss)
Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other
comprehensive income (loss) resulted from losses on derivative instruments qualifying as hedges, postretirement liability adjustments,
foreign currency translation adjustments and loss on available-for-sale investments.
The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2018, 2017 and 2016, were as
follows:
NetUnrealizedGain (Loss) onDerivative Instruments Qualifyingas Hedges
Post-retirement LiabilityAdjustment
ForeignCurrency Translation Adjustment
NetUnrealizedGain (Loss) onAvailable-for-saleInvestments
TotalAccumulated OtherComprehensive Loss
(In thousands)
Balance at December 31, 2016 $(2,300)$(33,221)$(149)$(63)$(35,733)
Other comprehensive loss before reclassifications —(1,812)(6)(139)(1,957)
Amounts reclassified from accumulated othercomprehensive loss 366 1,013 —120 1,499
Amounts reclassified to accumulated othercomprehensive loss from a regulatory asset —(1,143)——(1,143)
Net current-period other comprehensive income (loss)366 (1,942)(6)(19)(1,601)
Balance at December 31, 2017 (1,934)(35,163)(155)(82)(37,334)
Other comprehensive income (loss) beforereclassifications —4,441 (61)(144)4,236
Amounts reclassified from accumulated othercomprehensive loss 162 2,173 249 131 2,715
Net current-period other comprehensive income (loss)162 6,614 188 (13)6,951
Reclassification adjustment of prior period tax effectsrelated to TCJA included in accumulated othercomprehensive loss (389)(7,520)(33)(17)(7,959)
Balance at December 31, 2018 $(2,161)$(36,069)$—$(112)$(38,342)
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74 MDU Resources Group, Inc. Form 10-K
The following amounts were reclassified out of accumulated other comprehensive loss into net income. The amounts presented in
parenthesis indicate a decrease to net income on the Consolidated Statements of Income. The reclassifications for the years ended
December 31 were as follows:
2018 2017 Location on ConsolidatedStatements of Income
(In thousands)
Reclassification adjustment for loss on derivative instrumentsincluded in net income $(591)$(590)Interest expense
429 224 Income taxes
(162)(366)
Amortization of postretirement liability losses includedin net periodic benefit cost (credit)(2,894)(1,658)Other income
721 645 Income taxes
(2,173)(1,013)
Reclassification adjustment for loss on foreign currencytranslation adjustment included in net income (324)—Other income
75 —Income taxes
(249)—
Reclassification adjustment for loss on available-for-saleinvestments included in net income (166)(185)Other income
35 65 Income taxes
(131)(120)
Total reclassifications $(2,715)$(1,499)
Part II
MDU Resources Group, Inc. Form 10-K 75
Note 2 - Revenue from Contracts with Customers
Disaggregation
In the following table, revenue is disaggregated by the type of customer or service provided. The Company believes this level of
disaggregation best depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors. The
table also includes a reconciliation of the disaggregated revenue by reportable segments. For more information on the Company's business
segments, see Note 15.
Year ended December 31, 2018 Electric Natural gasdistribution Pipeline andmidstream
Constructionmaterials andcontracting Constructionservices Other Total
(In thousands)
Residential utility sales $121,477 $457,959 $—$—$—$—$579,436
Commercial utility sales 136,236 276,716 ————412,952
Industrial utility sales 34,353 24,603 ————58,956
Other utility sales 7,556 —————7,556
Natural gas transportation —43,238 89,159 ———132,397
Natural gas gathering ——9,159 ———9,159
Natural gas storage ——11,543 ———11,543
Contracting services ———968,755 ——968,755
Construction materials ———1,423,068 ——1,423,068
Intrasegment eliminations*———(465,969)——(465,969)
Inside specialty contracting ————926,875 —926,875
Outside specialty contracting ————392,544 —392,544
Other 31,568 14,579 18,865 —525 11,259 76,796
Intersegment eliminations ——(50,905)(669)(1,681)(11,052)(64,307)
Revenues from contracts withcustomers 331,190 817,095 77,821 1,925,185 1,318,263 207 4,469,761
Revenues out of scope 3,933 6,152 197 —51,509 —61,791
Total external operating revenues $335,123 $823,247 $78,018 $1,925,185 $1,369,772 $207 $4,531,552
*Intrasegment revenues are presented within the construction materials and contracting segment to highlight the focus on vertical integration as this segment sells
materials to both third parties and internal customers. Due to consolidation requirements, these revenues must be eliminated against construction materials to arrive
at the external operating revenue total for the segment.
Contract balances
The timing of revenue recognition may differ from the timing of invoicing to customers. The timing of invoicing to customers does not
necessarily correlate with the timing of revenues being recognized under the cost‐to‐cost method of accounting. Contracts from contracting
services are billed as work progresses in accordance with agreed upon contractual terms. Generally, billing to the customer occurs
contemporaneous to revenue recognition. A variance in timing of the billings may result in a contract asset or a contract liability. A contract
asset occurs when revenues are recognized under the cost-to-cost measure of progress, which exceeds amounts billed on uncompleted
contracts. Such amounts will be billed as standard contract terms allow, usually based on various measures of performance or achievement.
A contract liability occurs when there are billings in excess of revenues recognized under the cost-to-cost measure of progress on
uncompleted contracts. Contract liabilities decrease as revenue is recognized from the satisfaction of the related performance obligation.
The changes in contract assets and liabilities were as follows:
December 31,2018 December 31,2017 Change Location on Consolidated Balance Sheets
(In thousands)
Contract assets $104,239 $109,540 $(5,301)Receivables, net
Contract liabilities - current (93,901)(84,123)(9,778)Accounts payable
Contract liabilities - noncurrent (135)—(135)Deferred credits and other liabilities - other
Net contract assets $10,203 $25,417 $(15,214)
At December 31, 2018, the Company's net contract assets decreased $15.2 million compared to December 31, 2017. Included in the
change of total net contract assets was a decrease in contract assets due to revenue recognized in excess of billings on contracts and an
increase in contract liabilities due to billings on contracts in excess of revenues recognized. The Company recognized $78.6 million in
revenue for the year ended December 31, 2018, which was previously included in contract liabilities at December 31, 2017.
Part II
76 MDU Resources Group, Inc. Form 10-K
The Company recognized a net increase in revenues of $36.7 million for the year ended December 31, 2018, from performance obligations
satisfied in prior periods.
Part II
MDU Resources Group, Inc. Form 10-K 77
Note 3 - Acquisitions
During 2018, the Company completed four acquisitions. The results of the acquired businesses have been included in the Company's
construction materials and contracting segment and Consolidated Financial Statements beginning on the acquisition dates. Pro forma
financial amounts reflecting the effects of the above acquisitions are not presented, as such acquisitions were not material, both individually
and in the aggregate, to the Company's financial position or results of operations. The following is a listing of the acquisitions made during
2018:
•In April 2018, the Company acquired Teevin & Fischer Quarry, LLC, an aggregate producer that provides crushed rock and gravel
to construction and retail customers in Oregon.
•In June 2018, the Company acquired Tri-City Paving, Inc., a general contractor and aggregate, asphalt and ready-mixed concrete
supplier in Minnesota.
•In July 2018, the Company acquired Molalla Redi-Mix and Rock Products, Inc., a producer of ready-mixed concrete in Oregon.
•In October 2018, the Company acquired Sweetman Construction Company, a provider of aggregates, asphalt and ready-mixed
concrete in South Dakota.
As of December 31, 2018, the gross aggregate consideration for these acquisitions, which were all accounted for as business combinations,
was $168.1 million in cash, subject to certain adjustments, and 721,610 shares of common stock with a market value of $20.3 million as
of the respective acquisition date. Due to the holding period restriction on the common stock, the share consideration has been discounted
to a fair value of approximately $18.2 million, as reflected in the Company's financial statements. In addition to the issuance of the
Company's equity securities, the Company issued debt to finance these acquisitions. As of December 31, 2018, costs incurred for
acquisitions were $1.5 million and included in operation and maintenance expense on the Consolidated Statements of Income. The
acquisitions are subject to customary adjustments based on, among other things, the amount of cash, debt and working capital in the
businesses as of the closing dates.
The Company preliminarily allocated the purchase price of the acquisitions to the assets acquired and liabilities assumed based on their
estimated fair values as of the acquisition dates and are considered provisional until final fair values are determined or the measurement
period has passed. The Company expects to record adjustments as it accumulates the information needed to estimate the fair value of
assets acquired and liabilities assumed, including working capital balances, estimated fair value of identifiable intangible assets, property,
plant and equipment, total consideration and goodwill. The excess of the purchase price over the aggregate fair values was recorded as
goodwill. The Company calculated the fair value of the assets acquired using the market or cost approach (or a combination of both). Fair
values for some of the assets were determined based on Level 3 inputs including estimated future cash flows, discount rates, growth rates,
sales projections, retention rates and terminal values, all of which require significant management judgment and are susceptible to change.
The final fair value of the net assets acquired may result in adjustments to the assets and liabilities, including goodwill, and will be made as
soon as practical, but no later than one year from the respective acquisition dates. However, any subsequent measurement period
adjustments are not expected to have a material impact on the Company's results of operations. The discount rate used in calculating the
fair value of the common stock issued was determined by a Black-Scholes-Merton model. The model used Level 2 inputs including risk-free
interest rate, volatility range and dividend yield.
The aggregate total consideration for the acquisitions and the preliminary amounts allocated to the assets acquired and liabilities assumed
based on the estimated fair values as of the respective acquisition dates were as follows:
2018 Acquisitions
(In thousands)
Assets
Current assets:
Receivables, net $18,984
Inventories 10,329
Other current assets 515
Total current assets 29,828
Property, plant and equipment 131,766
Deferred charges and other assets:
Goodwill 33,131
Other intangible assets, net 8,227
Other 927
Total deferred charges and other assets 42,285
Total assets acquired $203,879
Liabilities
Current liabilities $11,122
Deferred credits and other liabilities:
Asset retirement obligation 914
Deferred income taxes 5,565
Total deferred credits and other liabilities 6,479
Total liabilities assumed $17,601
Total consideration (fair value)$186,278
Part II
78 MDU Resources Group, Inc. Form 10-K
Note 4 - Discontinued Operations
The assets and liabilities of the Company's discontinued operations have been classified as held for sale and the results of operations are
shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not
meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation,
depletion and amortization expense was no longer recorded.
Dakota Prairie Refining On June 24, 2016, WBI Energy entered into a membership interest purchase agreement with Tesoro to sell all of the
outstanding membership interests in Dakota Prairie Refining to Tesoro. WBI Energy and Calumet each previously owned 50 percent of the
Dakota Prairie Refining membership interests and were equal members in building and operating Dakota Prairie Refinery. To effectuate the
sale, WBI Energy acquired Calumet's 50 percent membership interest in Dakota Prairie Refining on June 27, 2016. The sale of the
membership interests to Tesoro closed on June 27, 2016. The sale of Dakota Prairie Refining reduced the Company's risk by decreasing
exposure to commodity prices.
In connection with the sale of Dakota Prairie Refining, Centennial guaranteed certain debt obligations of Dakota Prairie Refining and Tesoro
agreed to indemnify Centennial for any losses and litigation expenses arising for the guarantee. On October 17, 2018, Centennial was
released of any further liabilities or obligations under this guarantee. For more information related to the guarantee, see Note 19.
The carrying amounts of the major classes of assets and liabilities classified as held for sale, related to the operations of and activity
associated with Dakota Prairie Refining, on the Company's Consolidated Balance Sheets at December 31 were as follows:
2018 2017
(In thousands)
Assets
Current assets:
Income taxes receivable*$—$1,778
Total current assets held for sale —1,778
Total assets held for sale $—$1,778
Liabilities
Deferred credits and other liabilities:
Deferred income taxes**$—$37
Total noncurrent liabilities held for sale —37
Total liabilities held for sale $—$37
*On the Company's Consolidated Balance Sheets, these amounts were reclassified to
taxes payable and are reflected in current liabilities held for sale.
**On the Company's Consolidated Balance Sheets, these amounts were reclassified todeferred charges and other assets - deferred income taxes and are reflected in
noncurrent assets held for sale.
The Company retained certain liabilities of Dakota Prairie Refining which were reflected in current liabilities held for sale on the
Consolidated Balance Sheet at December 31, 2016. In the first quarter of 2017, the Company recorded a reversal of a previously accrued
liability of $7.0 million ($4.3 million after tax) due to the resolution of a legal matter. As of December 31, 2018, Dakota Prairie Refining
incurred no material exit and disposal costs, and does not expect to incur any future material exit and disposal costs.
The Company performed a fair value assessment of the assets and liabilities classified as held for sale. In the second quarter of 2016, the
fair value assessment was determined using the market approach based on the sale transaction to Tesoro. The fair value assessment
indicated an impairment based on the carrying value exceeding the fair value, which resulted in the Company recording an impairment of
$251.9 million ($156.7 million after tax) in the quarter ended June 30, 2016. The impairment was included in operating expenses from
discontinued operations. The fair value of Dakota Prairie Refining's assets have been categorized as Level 3 in the fair value hierarchy.
Fidelity In the second quarter of 2015, the Company began the marketing and sale process of Fidelity with an anticipated sale to occur
within one year. Between September 2015 and March 2016, the Company entered into purchase and sale agreements to sell substantially
all of Fidelity's oil and natural gas assets. The completion of these sales occurred between October 2015 and April 2016. In July 2018, the
Company completed the sale of a majority of the remaining property, plant and equipment. The sale of Fidelity was part of the Company's
strategic plan to grow its capital investments in the remaining business segments and to focus on creating a greater long-term value.
Part II
MDU Resources Group, Inc. Form 10-K 79
The carrying amounts of the major classes of assets and liabilities classified as held for sale, related to the operations of Fidelity, on the
Company's Consolidated Balance Sheets at December 31 were as follows:
2018 2017
(In thousands)
Assets
Current assets:
Receivables, net $430 $479
Total current assets held for sale 430 479
Noncurrent assets:
Net property, plant and equipment —1,631
Deferred income taxes 1,926 2,637
Other 161 161
Total noncurrent assets held for sale 2,087 4,429
Total assets held for sale $2,517 $4,908
Liabilities
Current liabilities:
Accounts payable $80 $30
Taxes payable 1,451 10,857
Other accrued liabilities 2,470 2,884
Total current liabilities held for sale 4,001 13,771
Total liabilities held for sale $4,001 $13,771
At December 31, 2018 and 2017, the Company’s deferred tax assets included in assets held for sale were largely comprised of $1.9 million
and $2.6 million, respectively, of federal and state net operating loss carryforwards and state alternative minimum tax credits. The Company
realized substantially all of the outstanding net operating loss carryforwards from prior periods in 2017.
At December 31, 2017, the Company had federal income tax net operating loss carryforwards and various state income tax net operating
loss carryforwards of $4.4 million and $13.8 million, respectively. At December 31, 2018, the Company had no federal or state income tax
net operating loss carryforwards.
The Company performed a fair value assessment of the assets and liabilities classified as held for sale. In the first quarter of 2016, the fair
value assessment was determined using the market approach largely based on a purchase and sale agreement. The estimated fair value
exceeded the carrying value and the Company recorded an impairment reversal of $1.4 million ($900,000 after tax) in the first quarter of
2016. In the second quarter of 2016, the fair value assessment was determined using the income and market approaches. The income
approach was determined by using the present value of future estimated cash flows. The market approach was based on market transactions
of similar properties. The estimated carrying value exceeded the fair value and the Company recorded an impairment of $900,000
($600,000 after tax) in the second quarter of 2016.
The Company has incurred $10.5 million of exit and disposal costs to date and has incurred no exit or disposal costs in 2018. The
Company does not expect to incur any additional material exit and disposal costs in connection with Fidelity. The exit and disposal costs are
associated with severance and other related matters and exclude the office lease expiration discussed in the following paragraph.
Fidelity vacated its office space in Denver, Colorado in 2016. The Company incurred lease payments of approximately $900,000 in 2016.
Lease termination payments of $3.2 million were made during the second quarter of 2016. Existing office furniture and fixtures were
relinquished to the lessor in the second quarter of 2016.
Part II
80 MDU Resources Group, Inc. Form 10-K
Dakota Prairie Refining and Fidelity The reconciliation of the major classes of income and expense constituting pretax income (loss) from
discontinued operations, which includes Dakota Prairie Refining and Fidelity, to the after-tax income (loss) from discontinued operations on
the Company's Consolidated Statements of Income for the years ended December 31 were as follows:
2018 2017 2016
(In thousands)
Operating revenues $(459)$465 $123,024
Operating expenses 921 (4,607)513,813
Operating income (loss)(1,380)5,072 (390,789)
Other income (expense)12 (13)306
Interest expense 575 250 1,753
Income (loss) from discontinued operations before income taxes (1,943)4,809 (392,236)
Income taxes*(4,875)8,592 (91,882)
Income (loss) from discontinued operations 2,932 (3,783)(300,354)
Loss from discontinued operations attributable to noncontrolling interest ——(131,691)
Income (loss) from discontinued operations attributable to the Company $2,932 $(3,783)$(168,663)
*Includes eliminations for the presentation of income tax adjustments between continuing and discontinued operations.
The pretax income (loss) from discontinued operations attributable to the Company, related to the operations of and activity associated with
Dakota Prairie Refining, was $(7,000), $6.9 million and $(253.5) million for the years ended December 31, 2018, 2017 and 2016,
respectively.
Part II
MDU Resources Group, Inc. Form 10-K 81
Note 5 - Goodwill and Other Intangible Assets
The changes in the carrying amount of goodwill for the year ended December 31, 2018, were as follows:
Balance atJanuary 1, 2018 Goodwill AcquiredDuring the Year Balance atDecember 31, 2018
(In thousands)
Natural gas distribution $345,736 $—$345,736
Construction materials and contracting 176,290 33,131 209,421
Construction services 109,765 —109,765
Total $631,791 $33,131 $664,922
The changes in the carrying amount of goodwill for the year ended December 31, 2017, were as follows:
Balance atJanuary 1, 2017 Goodwill AcquiredDuring the Year Balance atDecember 31, 2017
(In thousands)
Natural gas distribution $345,736 $—$345,736
Construction materials and contracting 176,290 —176,290
Construction services 109,765 —109,765
Total $631,791 $—$631,791
During 2018, the Company completed four acquisitions and the results of the acquired businesses have been included in the Company's
construction materials and contracting segment. At December 31, 2018, the construction materials and contracting segment's goodwill
increased by $33.1 million and other intangible assets increased by $8.2 million for these acquisitions. For more information about these
acquisitions, see Note 3.
Other amortizable intangible assets at December 31 were as follows:
2018 2017
(In thousands)
Customer relationships $22,720 $15,248
Less accumulated amortization 13,535 13,382
9,185 1,866
Noncompete agreements 2,605 2,430
Less accumulated amortization 1,956 1,805
649 625
Other 6,458 6,990
Less accumulated amortization 5,477 5,644
981 1,346
Total $10,815 $3,837
Amortization expense for amortizable intangible assets for the years ended December 31, 2018, 2017 and 2016, was $1.2 million,
$2.0 million and $2.5 million, respectively. The amounts of estimated amortization expense for identifiable intangible assets as of
December 31, 2018, were:
2019 2020 2021 2022 2023 Thereafter
(In thousands)
Amortization expense $1,856 $1,486 $1,096 $1,072 $1,006 $4,299
Part II
82 MDU Resources Group, Inc. Form 10-K
Note 6 - Regulatory Assets and Liabilities
The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:
Estimated RecoveryPeriod *2018 2017
(In thousands)
Regulatory assets:
Pension and postretirement benefits (a)(e)$165,898 $163,896
Asset retirement obligations (a)Over plant lives 60,097 56,078
Natural gas costs recoverable through rate adjustments (b)Up to 1 year 42,652 14,465
Taxes recoverable from customers (a)Over plant lives 11,946 12,073
Manufactured gas plant sites remediation (a)-16,504 18,213
Long-term debt refinancing costs (a)Up to 19 years 4,898 5,563
Costs related to identifying generation development (a)Up to 8 years 2,508 2,960
Other (a) (b)Up to 20 years 35,614 27,715
Total regulatory assets 340,117 300,963
Regulatory liabilities:
Taxes refundable to customers (c)277,833 279,668
Plant removal and decommissioning costs (c)173,143 176,190
Natural gas costs refundable through rate adjustments (d)29,995 28,514
Pension and postretirement benefits (c)15,264 16,021
Other (c) (d)25,197 18,905
Total regulatory liabilities 521,432 519,298
Net regulatory position $(181,315)$(218,335)
*Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.
(a)Included in deferred charges and other assets - other on the Consolidated Balance Sheets.
(b)Included in prepayments and other current assets on the Consolidated Balance Sheets.
(c)Included in deferred credits and other liabilities - other on the Consolidated Balance Sheets.
(d)Included in other accrued liabilities on the Consolidated Balance Sheets.
(e)Recovered as expense is incurred or cash contributions are made.
The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not
earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. As of December 31, 2018
and 2017, approximately $313.5 million and $269.1 million, respectively, of regulatory assets were not earning a rate of return.
In the fourth quarter of 2017, the Company performed a one-time revaluation of the Company's regulated deferred tax assets and liabilities
for the reduction of the corporate tax rate from 35 percent to 21 percent effective January 1, 2018, as identified in the TCJA. In the fourth
quarter of 2017, the revaluation of the deferred tax assets and liabilities resulted in a decrease of $15.5 million in taxes recoverable from
customers and an increase of $270.0 million in taxes refundable to customers. The revaluation of the Company's regulatory deferred tax
assets and liabilities were deferred as the Company worked with the various regulators to plan for amounts expected to be returned to
customers. All amounts related to the TCJA are reserved or passed back to customers. The Company has tax settlements in place in most
jurisdictions, with new rates in place in 2018 or expected to be in place in the first half of 2019. TCJA filings are pending in Wyoming and
Oregon. For more information on the various rate cases, see Note 18. There were no significant changes between the preliminary estimate
and final determination of taxes refundable to or recoverable from customers. These regulatory amounts will largely be refunded over the
remaining life of the related assets.
If, for any reason, the Company's regulated businesses cease to meet the criteria for application of regulatory accounting for all or part of
their operations, the regulatory assets and liabilities relating to those portions ceasing to meet such criteria would be removed from the
balance sheet and included in the statement of income or accumulated other comprehensive income (loss) in the period in which the
discontinuance of regulatory accounting occurs.
Part II
MDU Resources Group, Inc. Form 10-K 83
Note 7 - Fair Value Measurements
The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in
income. The Company anticipates using these investments, which consist of an insurance contract, to satisfy its obligations under its
unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and
equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $73.8 million
and $77.4 million at December 31, 2018 and 2017, respectively, are classified as investments on the Consolidated Balance Sheets. The
net unrealized loss on these investments for the year ended December 31, 2018, was $3.6 million. The net unrealized gains on these
investments for the years ended December 31, 2017 and 2016, were $9.3 million and $3.4 million, respectively. The change in fair value,
which is considered part of the cost of the plan, is classified in other income on the Consolidated Statements of Income. In connection with
the adoption of ASU 2017-07, as discussed in Note 1, the Company has elected to reclassify prior period unrealized gains from operation
and maintenance expense to other income on the Consolidated Statements of Income.
The Company did not elect the fair value option, which records gains and losses in income, for its available-for-sale securities, which include
mortgage-backed securities and U.S. Treasury securities. These available-for-sale securities are recorded at fair value and are classified as
investments on the Consolidated Balance Sheets. Unrealized gains or losses are recorded in accumulated other comprehensive income
(loss). Details of available-for-sale securities were as follows:
December 31, 2018 Cost
GrossUnrealizedGains
GrossUnrealizedLosses Fair Value
(In thousands)
Mortgage-backed securities $10,473 $21 $162 $10,332
U.S. Treasury securities 179 ——179
Total $10,652 $21 $162 $10,511
December 31, 2017 Cost
GrossUnrealizedGains
GrossUnrealizedLosses Fair Value
(In thousands)
Mortgage-backed securities $10,342 $4 $129 $10,217
U.S. Treasury securities 205 —1 204
Total $10,547 $4 $130 $10,421
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction
between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the
significance of inputs. The estimated fair values of the Company's assets and liabilities measured on a recurring basis are determined using
the market approach. The Company's Level 2 money market funds are valued at the net asset value of shares held at the end of the period,
based on published market quotations on active markets, or using other known sources including pricing from outside sources. The
estimated fair value of the Company's Level 2 mortgage-backed securities and U.S. Treasury securities are based on comparable market
transactions, other observable inputs or other sources, including pricing from outside sources. The estimated fair value of the Company's
Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate
accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs
or corroborated market data.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use
of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2018 and 2017, there
were no transfers between Levels 1 and 2.
The Company's assets measured at fair value on a recurring basis were as follows:
Fair Value Measurementsat December 31, 2018, Using
Quoted Pricesin ActiveMarkets forIdenticalAssets(Level 1)
SignificantOtherObservableInputs(Level 2)
SignificantUnobservableInputs (Level 3)
Balance atDecember 31,2018
(In thousands)
Assets:
Money market funds $—$10,799 $—$10,799
Insurance contract*—73,838 —73,838
Available-for-sale securities:
Mortgage-backed securities —10,332 —10,332
U.S. Treasury securities —179 —179
Total assets measured at fair value $—$95,148 $—$95,148
*The insurance contract invests approximately 53 percent in fixed-income investments, 21 percent in common stock of large-cap companies, 11 percent in common
stock of mid-cap companies, 10 percent in common stock of small-cap companies, 3 percent in target date investments and 2 percent in cash equivalents.
Fair Value Measurementsat December 31, 2017, Using
Quoted Pricesin ActiveMarkets forIdenticalAssets (Level 1)
SignificantOtherObservableInputs(Level 2)
SignificantUnobservableInputs (Level 3)
Balance atDecember 31,2017
(In thousands)
Assets:
Money market funds $—$6,965 $—$6,965
Insurance contract*—77,388 —77,388
Available-for-sale securities:
Mortgage-backed securities —10,217 —10,217
U.S. Treasury securities —204 —204
Total assets measured at fair value $—$94,774 $—$94,774
*The insurance contract invests approximately 49 percent in fixed-income investments, 23 percent in common stock of large-cap companies, 14 percent in common
stock of mid-cap companies, 11 percent in common stock of small-cap companies, 2 percent in target date investments and 1 percent in cash equivalents.
The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including
long-lived asset impairments. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments only
in certain circumstances. The Company reviews the carrying value of its long-lived assets, excluding goodwill, whenever events or changes in
circumstances indicate that such carrying amounts may not be recoverable.
The Company performed a fair value assessment of the assets acquired and liabilities assumed in the business combinations that occurred
during 2018. For more information on these Level 2 and Level 3 fair value measurements, see Note 3.
The Company performed a fair value assessment of the assets and liabilities classified as held for sale. For more information on these
Level 3 nonrecurring fair value measurements, see Note 4.
Part II
84 MDU Resources Group, Inc. Form 10-K
The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for
disclosure purposes only. The fair value was based on discounted future cash flows using current market interest rates. The estimated fair
value of the Company's Level 2 long-term debt at December 31 was as follows:
2018 2017
CarryingAmount FairValue CarryingAmount FairValue
(In thousands)
Long-term debt $2,108,695 $2,183,819 $1,714,853 $1,826,256
The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their
fair values.
Part II
MDU Resources Group, Inc. Form 10-K 85
Note 8 - Debt
Certain debt instruments of the Company and its subsidiaries, including those discussed later, contain restrictive covenants and cross-
default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in compliance with
the applicable covenants and certain other conditions. At December 31, 2018, the Company and its subsidiaries, as applicable, complied
with all applicable financial covenants and restrictions. In the event the Company and its subsidiaries do not comply with the applicable
covenants and other conditions, alternative sources of funding may need to be pursued.
The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries:
Company Facility FacilityLimit
AmountOutstanding atDecember 31,2018
AmountOutstanding atDecember 31, 2017
Letters ofCredit atDecember 31,2018 ExpirationDate
(In millions)
MDU ResourcesGroup, Inc.Commercial paper/Revolvingcredit agreement (a)$175.0 $48.5 $73.8 (b)$—6/8/23
Cascade NaturalGas Corporation Revolving credit agreement $75.0 (c)$53.8 $17.3 $2.2 (d)4/24/20
Intermountain GasCompany Revolving credit agreement $85.0 (e)$56.3 $40.0 $—4/24/20
Centennial EnergyHoldings, Inc.Commercial paper/Revolvingcredit agreement (f)$500.0 $289.6 (b)$14.6 (b)$—9/23/21
(a)The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of the
Company on stated conditions, up to a maximum of $225.0 million). The amount outstanding under the revolving credit agreement was $48.5 million.
(b)Amount outstanding under commercial paper program.(c)Certain provisions allow for increased borrowings, up to a maximum of $100.0 million.
(d)Outstanding letter(s) of credit reduce the amount available under the credit agreement.
(e)Certain provisions allow for increased borrowings, up to a maximum of $110.0 million.
(f)The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Centennial
on stated conditions, up to a maximum of $600.0 million). There were no amounts outstanding under the revolving credit agreement.
The Company's and Centennial's respective commercial paper programs are supported by revolving credit agreements. While the amount of
commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, the Company and
Centennial do not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreements. The
commercial paper borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the
seasonality of the construction businesses.
The following includes information related to the preceding table.
Long-term debt
MDU Resources Group, Inc. The Company's revolving credit agreement supports its commercial paper program. Commercial paper borrowings
under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued
commercial paper borrowings.
The credit agreement contains customary covenants and provisions, including covenants of the Company not to permit, as of the end of any
fiscal quarter, (A) the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent or
(B) the ratio of funded debt to capitalization (determined with respect to the Company alone, excluding its subsidiaries) to be greater than
65 percent. The Company's ratio of funded debt to total capitalization at December 31, 2018, was 45 percent. Other covenants include
limitations on the sale of certain assets and on the making of certain loans and investments.
There are no credit facilities that contain cross-default provisions between the Company and any of its subsidiaries.
On January 1, 2019, the Company's revolving credit agreement and commercial paper program became Montana-Dakota's revolving credit
agreement and commercial paper program as a result of the Holding Company Reorganization. The outstanding balance of the revolving
credit agreement was also transferred to Montana-Dakota. All of the related terms and covenants of the credit agreements remained the
same. For more information on the reorganization, see Note 1.
Cascade Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on a
long-term basis through continued borrowings.
The credit agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any time, the ratio of
total debt to total capitalization to be greater than 65 percent. Cascade's ratio of total debt to total capitalization at December 31, 2018,
was 51 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain
investments.
Cascade's credit agreement also contains cross-default provisions. These provisions state that if Cascade fails to make any payment with
respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness
to be due prior to its stated maturity or the contingent obligation to become payable, Cascade will be in default under the revolving credit
agreement.
Intermountain Any borrowings under the revolving credit agreement are classified as long-term debt as they are intended to be refinanced on
a long-term basis through continued borrowings.
The credit agreement contains customary covenants and provisions, including a covenant of Intermountain not to permit, at any time, the
ratio of total debt to total capitalization to be greater than 65 percent. Intermountain's ratio of total debt to total capitalization at
December 31, 2018, was 49 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the
making of certain investments.
Intermountain's credit agreement also contains cross-default provisions. These provisions state that if Intermountain fails to make any
payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such
indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, or certain conditions result in an early
termination date under any swap contract that is in excess of a specified amount, then Intermountain will be in default under the revolving
credit agreement.
Centennial Centennial's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this
agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper
borrowings.
Centennial's revolving credit agreement contains customary covenants and provisions, including a covenant of Centennial, not to permit, as
of the end of any fiscal quarter, the ratio of total consolidated debt to total consolidated capitalization to be greater than 65 percent.
Centennial's ratio of total debt to total capitalization at December 31, 2018, was 38 percent. Other covenants include restricted payments,
restrictions on the sale of certain assets, limitations on subsidiary indebtedness, minimum consolidated net worth, limitations on priority
debt and the making of certain loans and investments.
Certain of Centennial's financing agreements contain cross-default provisions. These provisions state that if Centennial or any subsidiary of
Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any
agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the
applicable agreements will be in default.
WBI Energy Transmission WBI Energy Transmission has a $200.0 million uncommitted note purchase and private shelf agreement with an
expiration date of May 16, 2019. WBI Energy Transmission had $140.0 million of notes outstanding at December 31, 2018, which reduced
the remaining capacity under this uncommitted private shelf agreement to $60.0 million. This agreement contains customary covenants and
provisions, including a covenant of WBI Energy Transmission not to permit, as of the end of any fiscal quarter, the ratio of total debt to total
capitalization to be greater than 55 percent. WBI Energy Transmission's total debt to total capitalization at December 31, 2018, was
Part II
86 MDU Resources Group, Inc. Form 10-K
40 percent. Other covenants include a limitation on priority debt and restrictions on the sale of certain assets and the making of certain
investments.
Long-term Debt Outstanding Long-term debt outstanding was as follows:
Weighted AverageInterest Rate atDecember 31, 2018 2018 2017
(In thousands)
Senior Notes due on dates ranging from July 1, 2019 to January 15, 2055 4.57%$1,381,000 $1,499,916
Commercial paper supported by revolving credit agreements 3.10%338,100 88,350
Term Loan Agreements due on dates ranging from October 17, 2019 toSeptember 3, 2032 2.75%209,800 —
Credit agreements due on April 24, 2020 4.40%110,100 57,300
Medium-Term Notes due on dates ranging from September 1, 2020 toMarch 16, 2029 6.68%50,000 50,000
Other notes due on dates ranging from July 1, 2019 to November 30, 2038 5.22%25,229 24,982
Less unamortized debt issuance costs 5,207 5,694
Less discount 327 1
Total long-term debt 2,108,695 1,714,853
Less current maturities 251,854 148,499
Net long-term debt $1,856,841 $1,566,354
Schedule of Debt Maturities Long-term debt maturities, which excludes unamortized debt issuance costs and discount, for the five years and
thereafter following December 31, 2018, were as follows:
2019 2020 2021 2022 2023 Thereafter
(In thousands)
Long-term debt maturities $251,854 $125,912 $290,413 $147,314 $125,714 $1,173,022
Part II
MDU Resources Group, Inc. Form 10-K 87
Note 9 - Asset Retirement Obligations
The Company records obligations related to retirement costs of natural gas distribution mains and lines, natural gas transmission lines,
storage facilities, decommissioning of certain electric generating facilities, reclamation of certain aggregate properties, special handling and
disposal of hazardous materials at certain electric generating facilities, natural gas distribution facilities and buildings, and certain other
obligations as asset retirement obligations.
A reconciliation of the Company's liability, which is included in other accrued liabilities and deferred credits and other liabilities - other on
the Consolidated Balance Sheets, for the years ended December 31 was as follows:
2018 2017
(In thousands)
Balance at beginning of year $341,969 $314,970
Liabilities incurred 13,424 15,110
Liabilities acquired 1,002 —
Liabilities settled (3,699)(4,981)
Accretion expense*18,242 16,839
Revisions in estimates 4,615 31
Balance at end of year $375,553 $341,969
*Includes $16.8 million and $15.6 million in 2018 and 2017, respectively, related to regulatory assets.
The Company believes that largely all expenses related to asset retirement obligations at the Company's regulated operations will be
recovered in rates over time and, accordingly, defers such expenses as regulatory assets. For more information on the Company's regulatory
assets and liabilities, see Note 6.
Note 10 - Preferred Stocks
The Company currently has 500,000 shares of preferred stock authorized to be issued with a $100 par value; 1,000,000 shares of
preferred stock A authorized to be issued with no par value; and 500,000 shares of preference stock authorized to be issued with no par
value. At December 31, 2018, there were no shares outstanding. At December 31, 2017, there were no shares outstanding. In 2016,
dividends declared on the 4.50% Series and 4.70% Series preferred stocks were $4.50 and $4.70 per share, respectively. On April 1,
2017, the Company redeemed all outstanding 4.50% Series and 4.70% Series preferred stocks at $105 per share and $102 per share,
respectively, for a repurchase price of approximately $15.6 million and $300,000 of redeemable preferred stock classified as long-term
debt.
Part II
88 MDU Resources Group, Inc. Form 10-K
Note 11 - Common Stock
For the years 2018, 2017 and 2016, dividends declared on common stock were $.7950, $.7750 and $.7550 per common share,
respectively.
The Stock Purchase Plan provided interested investors the opportunity to make optional cash investments and to reinvest all or a percentage
of their cash dividends in shares of the Company's common stock. The K-Plan provides participants the option to invest in the Company's
common stock. For the years ended December 31, 2018, 2017 and 2016, the K-Plan purchased shares of common stock on the open
market. At December 31, 2018, there were 7.8 million shares of common stock reserved for original issuance under the K-Plan. From
January 2016 through December 4, 2016, the Stock Purchase Plan purchased shares of common stock on the open market. On
December 5, 2016, the Stock Purchase Plan was terminated and all remaining shares reserved for original issuance under the plan were de-
registered.
The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. The Company has paid quarterly
dividends for more than 80 consecutive years with an increase in the payout amount for the last 28 consecutive years. The declaration and
payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by the Company's credit agreements,
federal and state laws, and applicable regulatory limitations. In addition, the Company and Centennial are generally restricted to paying
dividends out of capital accounts or net assets. The following discusses the most restrictive limitations.
Pursuant to a covenant under a credit agreement, Centennial may only declare or pay distributions if as of the last day of any fiscal quarter,
the ratio of Centennial's average consolidated indebtedness as of the last day of such fiscal quarter and each of the preceding three fiscal
quarters to Centennial's Consolidated EBITDA does not exceed 3 to 1. Intermountain has regulatory limitations on the amount of dividends
it can pay. Based on these limitations, approximately $1.1 billion of the net assets of the Company's subsidiaries were restricted from being
used to transfer funds to the Company at December 31, 2018. In addition, the Company's credit agreement also contains restrictions on
dividend payments. The most restrictive limitation requires the Company not to permit the ratio of funded debt to capitalization (determined
with respect to the Company alone, excluding its subsidiaries) to be greater than 65 percent. Based on this limitation, approximately
$424 million of the Company's (excluding its subsidiaries) net assets, which represents common stockholders' equity including retained
earnings, would be restricted from use for dividend payments at December 31, 2018. In addition, state regulatory commissions may require
the Company to maintain certain capitalization ratios. These requirements are not expected to affect the Company's ability to pay dividends
in the near term.
Note 12 - Stock-Based Compensation
The Company has stock-based compensation plans under which it is currently authorized to grant restricted stock and other stock awards.
As of December 31, 2018, there were 5.0 million remaining shares available to grant under these plans. The Company either purchases
shares on the open market or issues new shares of common stock to satisfy the vesting of stock based awards.
Total stock-based compensation expense (after tax) was $4.6 million, $2.7 million and $3.3 million in 2018, 2017 and 2016, respectively.
As of December 31, 2018, total remaining unrecognized compensation expense related to stock-based compensation was approximately
$7.2 million (before income taxes) which will be amortized over a weighted average period of 1.7 years.
Stock awards
Non-employee directors receive shares of common stock in addition to and in lieu of cash payment for directors' fees. Shares of common
stock were issued under the non-employee director stock compensation plan or the non-employee director long-term incentive compensation
plan. There were 38,605 shares with a fair value of $1.0 million, 40,572 shares with a fair value of $1.1 million and 37,218 shares with a
fair value of $1.1 million issued to non-employee directors during the years ended December 31, 2018, 2017 and 2016, respectively.
Restricted stock awards
In February 2018, the Company began granting restricted stock awards under the long-term performance-based incentive plan to certain key
employees. The restricted stock awards granted will vest after three years. The grant-date fair value is the market price of the Company's
stock on the grant date. At December 31, 2018, the total nonvested shares were 22,838 with a weighted average grant-date fair value of
$27.48 per share.
Performance share awards
Since 2003, key employees of the Company have been granted performance share awards each year under the long-term performance-based
incentive plan. Entitlement to performance shares is established by either the market condition or the performance metrics and service
condition relative to the designated award.
Target grants of performance shares outstanding at December 31, 2018, were as follows:
Grant Date PerformancePeriod Target Grantof Shares
February 2016 2016-2018 255,773
March 2016 2016-2018 2,151
February 2017 2017-2019 164,558
February 2018 2018-2020 246,309
Under the market condition for these performance share awards, participants may earn from zero to 200 percent of the apportioned target
grant of shares based on the Company's total shareholder return relative to that of the selected peer group. Compensation expense is based
on the grant-date fair value as determined by Monte Carlo simulation. The blended volatility term structure ranges are comprised of
50 percent historical volatility and 50 percent implied volatility. Risk-free interest rates were based on U.S. Treasury security rates in effect
as of the grant date. Assumptions used for grants applicable to the market condition for certain performance shares issued in 2018, 2017
and 2016 were:
2018 2017 2016
Weighted average grant-date fair value $34.55 $24.31 $14.60
Blended volatility range 17.87%–22.14%22.70%–25.56%29.25%–32.51%
Risk-free interest rate range 1.86%–2.46%.69%–1.61%.47%–.92%
Weighted average discounted dividends per share $2.46 $1.70 $1.56
Under the performance conditions for these performance share awards, participants may earn from zero to 200 percent of the apportioned
target grant of shares. The performance conditions are based on the Company's compound annual growth rate in earnings from continuing
operations before interest, taxes, depreciation, depletion and amortization and the Company's compound annual growth rate in earnings
from continuing operations. The performance shares applicable to these performance conditions have a weighted average grant-date fair
value of $27.48 per share.
There were no performance shares that vested in 2018. The fair value of the performance shares that vested during the years ended
December 31, 2017 and 2016, was $9.6 million and $953,000, respectively.
A summary of the status of the performance share awards for the year ended December 31, 2018, was as follows:
Number ofShares
WeightedAverageGrant-DateFair Value
Nonvested at beginning of period 425,534 $18.35
Granted 246,309 31.02
Less:
Forfeited 3,052 14.60
Nonvested at end of period 668,791 $23.03
Part II
MDU Resources Group, Inc. Form 10-K 89
Note 13 - Income Taxes
The components of income before income taxes from continuing operations for each of the years ended December 31 were as follows:
2018 2017 2016
(In thousands)
United States $317,655 $350,064 $326,252
Foreign (784)(37)(24)
Income before income taxes from continuing operations $316,871 $350,027 $326,228
Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows:
2018 2017 2016
(In thousands)
Current:
Federal $(15,901)$74,272 $81,989
State 3,651 16,192 13,190
Foreign ——2
(12,250)90,464 95,181
Deferred:
Income taxes:
Federal 50,755 (24,497)(2,102)
State 7,206 (864)1,184
Investment tax credit - net 1,774 (62)(1,131)
59,735 (25,423)(2,049)
Total income tax expense $47,485 $65,041 $93,132
In accordance with the accounting guidance on accounting for income taxes, the tax effects of the change in tax laws or rates are to be
recorded in the period of enactment. The TCJA was enacted on December 22, 2017, as discussed in Note 1. Therefore, the reduction in the
corporate tax rate from 35 percent to 21 percent required the Company to prepare a one-time revaluation of the Company's deferred tax
assets and liabilities in the fourth quarter of 2017, the period of enactment. The deferred taxes were revalued at the new tax rate because
deferred taxes should reflect what the Company expects to pay or receive in future periods under the applicable tax rate. As a result of the
revaluation, the Company reduced the value of these assets and liabilities and recorded a tax benefit from continuing operations of
$39.5 million on the Consolidated Statements of Income for the year ended December 31, 2017. Included in the tax benefit from
continuing operations was income tax expense of $7.7 million related to amounts in accumulated other comprehensive loss and
$1.0 million related to the Company's assets held for sale.
The Company's regulated operations prepared a one-time revaluation of the Company's regulatory deferred tax assets and liabilities in the
fourth quarter of 2017 related to the enactment of the TCJA. The revaluation is being deferred under regulatory accounting as the Company
works with the various regulators to plan for amounts expected to be returned to customers, as discussed in Notes 6 and 18. The revaluation
of the deferred tax assets and liabilities resulted in a net decrease of $285.5 million in the fourth quarter of 2017. In the third quarter of
2018, the Company reversed a regulatory liability recorded in 2017 based on a FERC final accounting order being issued, which resulted in
a $4.2 million tax benefit. These regulatory amounts will largely be refunded over the remaining life of the related assets.
The changes included in the TCJA were broad and complex. The SEC issued rules that allowed for a measurement period of up to one year
after the enactment date of the TCJA to finalize the recording of the related tax impacts. The Company has reviewed the impacts of the
TCJA and completed its assessment of the transitional impacts during the period ending December 31, 2018, of which there were no such
material adjustments.
Part II
90 MDU Resources Group, Inc. Form 10-K
Components of deferred tax assets and deferred tax liabilities at December 31 were as follows:
2018 2017
(In thousands)
Deferred tax assets:
Postretirement $51,930 $55,736
Compensation-related 29,885 16,298
Alternative minimum tax credit carryforward 13,404 37,683
Federal renewable energy credit 8,015 19,367
Customer advances 7,734 8,712
Asset retirement obligations 7,083 6,380
Legal and environmental contingencies 6,729 7,363
Other 37,347 35,738
Total deferred tax assets 162,127 187,277
Deferred tax liabilities:
Depreciation and basis differences on property, plant and equipment 476,832 429,577
Postretirement 44,432 43,505
Intangible asset amortization 17,752 16,979
Other 39,712 32,591
Total deferred tax liabilities 578,728 522,652
Valuation allowance 13,484 11,896
Net deferred income tax liability $430,085 $347,271
As of December 31, 2018 and 2017, the Company had various state income tax net operating loss carryforwards of $153.2 million and
$130.1 million, respectively, and federal and state income tax credit carryforwards, excluding alternative minimum tax credit carryforwards,
of $43.5 million and $52.5 million, respectively. Included in the state credits are various regulatory investment tax credits of approximately
$32.2 million and $28.0 million at December 31, 2018 and 2017, respectively. The federal income tax credit carryforwards expire in 2037
and 2038 if not utilized and state income tax credit carryforwards are due to expire between 2020 and 2046. Changes in tax regulations or
assumptions regarding current and future taxable income could require additional valuation allowances in the future. The alternative
minimum tax credit carryforwards are refundable. For information regarding net operating loss carryforwards and valuation allowances
related to discontinued operations, see Note 4.
The following table reconciles the change in the net deferred income tax liability from December 31, 2017, to December 31, 2018, to
deferred income tax expense:
2018
(In thousands)
Change in net deferred income tax liability from the preceding table $82,814
Deferred taxes associated with other comprehensive income (2,679)
Deferred taxes associated with TCJA enactment for regulated activities (13,776)
Deferred taxes associated with acquisitions (5,565)
Other (1,059)
Deferred income tax expense for the period $59,735
Part II
MDU Resources Group, Inc. Form 10-K 91
Total income tax expense differs from the amount computed by applying the statutory federal income tax rate to income before taxes. The
reasons for this difference were as follows:
Years ended December 31,2018 2017 2016
Amount %Amount %Amount %
(Dollars in thousands)
Computed tax at federal statutory rate $66,543 21.0 $122,509 35.0 $114,179 35.0
Increases (reductions) resulting from:
State income taxes, net of federal income tax 12,190 3.8 10,724 3.1 9,027 2.8
Federal renewable energy credit (11,759)(3.7)(13,958)(4.0)(13,544)(4.2)
Tax compliance and uncertain tax positions (2,725)(.9)(643)(.2)(3,028)(.9)
Domestic production deduction ——(6,849)(2.0)(6,251)(1.9)
Excess deferred income tax amortization (9,319)(2.9)(397)—(828)(.2)
TCJA revaluation (5,947)(1.9)(47,242)(13.5)——
TCJA revaluation related to accumulated other comprehensive loss balance (42)—7,735 2.2 ——
Other (1,456)(.4)(6,838)(2.0)(6,423)(2.1)
Total income tax expense $47,485 15.0 $65,041 18.6 $93,132 28.5
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state, local and foreign jurisdictions.
The Company is no longer subject to U.S. federal or non-U.S. income tax examinations by tax authorities for years ending prior to 2015.
With few exceptions, as of December 31, 2018, the Company is no longer subject to state and local income tax examinations by tax
authorities for years ending prior to 2014.
A reconciliation of unrecognized tax benefits (excluding interest) for the years ended December 31 was as follows:
2018 2017 2016
(In thousands)
Balance at beginning of year $—$—$—
Additions based on tax positions related to current year 120 ——
Additions for tax positions of prior years 262 ——
Balance at end of year $382 $—$—
Included in income tax expense is interest on uncertain tax positions. For the years ended December 31, 2018, 2017 and 2016, the
Company recognized approximately $31,000, $99,000 and $92,000, respectively, of interest income in income tax expense. At
December 31, 2018, the Company had no accrued receivables for interest. At December 31, 2017, the Company had accrued receivables
of approximately $46,000, for interest.
Part II
92 MDU Resources Group, Inc. Form 10-K
Note 14 - Cash Flow Information
Cash expenditures for interest and income taxes for the years ended December 31 were as follows:
2018 2017 2016
(In thousands)
Interest, net*$83,009 $79,638 $87,920
Income taxes paid, net**$16,041 $112,137 $105,908
*AFUDC - borrowed was $2.3 million, $966,000 and $914,000 for the years ended December 31, 2018, 2017and 2016, respectively.
**Income taxes paid, net of discontinued operations, were $5.5 million, $9.7 million and $1.3 million for the yearsended December 31, 2018, 2017 and 2016, respectively.
Noncash investing transactions at December 31 were as follows:
2018 2017 2016
(In thousands)
Property, plant and equipment additions in accounts payable $42,355 $29,263 $22,712
Issuance of common stock in connection with acquisition $18,186 $—$—
Note 15 - Business Segment Data
The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the
strategic business units due to differences in products, services and regulation. The internal reporting of these operating segments is
defined based on the reporting and review process used by the Company's chief executive officer. The vast majority of the Company's
operations are located within the United States.
The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas
distribution segment distributes natural gas in those states, as well as in Idaho, Minnesota, Oregon and Washington. These operations also
supply related value-added services.
The pipeline and midstream segment provides natural gas transportation, underground storage and gathering services through regulated and
nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also
provides cathodic protection and other energy-related services.
The construction materials and contracting segment operations mine, process and sell construction aggregates (crushed stone, sand and
gravel); produce and sell asphalt mix; and supply ready-mixed concrete. This segment focuses on vertical integration of its contracting
services with its construction materials to support the aggregate based product lines including aggregate placement, asphalt and concrete
paving, and site development and grading. Although not common to all locations, other products include the sale of cement, liquid asphalt
for various commercial and roadway applications, various finished concrete products and other building materials and related contracting
services. This segment operates in the central, southern and western United States and Alaska and Hawaii.
The construction services segment provides inside and outside specialty contracting services. Its outside services include design,
construction and maintenance of overhead and underground electrical distribution and transmission lines, substations, external lighting,
traffic signalization, and gas pipelines, as well as utility excavation and the manufacture and distribution of transmission line construction
equipment. Its inside services include design, construction and maintenance of electrical and communication wiring and infrastructure, fire
suppression systems, and mechanical piping and services. This segment also constructs and maintains renewable energy projects. These
specialty contracting services are provided to utilities and large manufacturing, commercial, industrial, institutional and government
customers.
The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the
Company's subsidiaries. The function of the captive insurer is to fund the self-insured layers of the insured Company's general liability,
automobile liability, pollution liability and other coverages. Centennial Capital also owns certain real and personal property. The Other
category also includes certain general and administrative costs (reflected in operation and maintenance expense) and interest expense which
were previously allocated to the refining business and Fidelity and do not meet the criteria for income (loss) from discontinued operations.
The Other category also includes Centennial Resources' former investment in Brazil.
Discontinued operations includes the results and supporting activities of Dakota Prairie Refining and Fidelity other than certain general and
administrative costs and interest expense as described above. For more information on discontinued operations, see Note 4.
Part II
MDU Resources Group, Inc. Form 10-K 93
The information below follows the same accounting policies as described in Note 1. Information on the Company's segments as of
December 31 and for the years then ended was as follows:
2018 2017 2016
(In thousands)
External operating revenues:
Regulated operations:
Electric $335,123 $342,805 $322,356
Natural gas distribution 823,247 848,388 766,115
Pipeline and midstream 54,857 53,566 52,983
1,213,227 1,244,759 1,141,454
Nonregulated operations:
Pipeline and midstream 23,161 19,602 39,602
Construction materials and contracting 1,925,185 1,811,964 1,873,696
Construction services 1,369,772 1,366,317 1,072,663
Other 207 709 1,413
3,318,325 3,198,592 2,987,374
Total external operating revenues $4,531,552 $4,443,351 $4,128,828
Intersegment operating revenues:
Regulated operations:
Electric $—$—$—
Natural gas distribution ———
Pipeline and midstream 50,580 48,867 48,794
50,580 48,867 48,794
Nonregulated operations:
Pipeline and midstream 325 178 223
Construction materials and contracting 669 565 574
Construction services 1,681 1,285 609
Other 11,052 7,165 7,230
13,727 9,193 8,636
Intersegment eliminations (64,307)(58,060)(57,430)
Total intersegment operating revenues $—$—$—
Depreciation, depletion and amortization:
Electric $50,982 $47,715 $50,220
Natural gas distribution 72,486 69,381 65,426
Pipeline and midstream 17,896 16,788 24,885
Construction materials and contracting 61,158 55,862 58,413
Construction services 15,728 15,739 15,307
Other 1,955 2,001 2,067
Total depreciation, depletion and amortization $220,205 $207,486 $216,318
Operating income (loss):
Electric $65,148 $79,902 $67,929
Natural gas distribution 72,336 84,239 66,166
Pipeline and midstream 36,128 36,004 42,864
Construction materials and contracting 141,426 143,230 178,753
Construction services 86,764 81,292 53,546
Other (79)(619)(349)
Total operating income $401,723 $424,048 $408,909
Part II
94 MDU Resources Group, Inc. Form 10-K
2018 2017 2016
(In thousands)
Interest expense:
Electric $25,860 $25,377 $24,982
Natural gas distribution 30,768 31,234 30,405
Pipeline and midstream 5,964 4,990 7,903
Construction materials and contracting 17,290 14,778 15,265
Construction services 3,551 3,742 4,059
Other 2,762 3,564 5,854
Intersegment eliminations (1,581)(897)(620)
Total interest expense $84,614 $82,788 $87,848
Income taxes:
Electric $(6,482)$7,699 $1,449
Natural gas distribution 4,075 22,756 9,181
Pipeline and midstream 2,677 12,281 12,408
Construction materials and contracting 28,357 5,405 60,625
Construction services 20,000 25,558 17,748
Other (1,142)(1,809)(2,028)
Intersegment eliminations —(6,849)(6,251)
Total income taxes $47,485 $65,041 $93,132
Earnings on common stock:
Regulated operations:
Electric $47,000 $49,366 $42,222
Natural gas distribution 37,732 32,225 27,102
Pipeline and midstream 26,905 20,620 22,060
111,637 102,211 91,384
Nonregulated operations:
Pipeline and midstream 1,554 (127)1,375
Construction materials and contracting 92,647 123,398 102,687
Construction services 64,309 53,306 33,945
Other (761)(1,422)(3,231)
157,749 175,155 134,776
Intersegment eliminations (a)—6,849 6,251
Earnings on common stock before income (loss) from discontinued operations 269,386 284,215 232,411
Income (loss) from discontinued operations, net of tax (a)2,932 (3,783)(300,354)
Loss from discontinued operations attributable to noncontrolling interest ——(131,691)
Earnings on common stock $272,318 $280,432 $63,748
Capital expenditures:
Electric $186,105 $109,107 $111,134
Natural gas distribution 205,896 146,981 126,272
Pipeline and midstream 70,057 31,054 34,467
Construction materials and contracting 280,396 44,302 37,845
Construction services 25,081 18,630 60,344
Other 1,768 1,850 2,358
Total capital expenditures (b)$769,303 $351,924 $372,420
Part II
MDU Resources Group, Inc. Form 10-K 95
(a)Includes eliminations for the presentation of income tax adjustments between continuing and discontinued operations.
(b)Capital expenditures for 2018, 2017 and 2016 include noncash transactions such as the issuance of the Company's equity securities in connection with
acquisitions, capital expenditure-related accounts payable and AFUDC, totaling $33.4 million, $10.5 million and $(15.8) million, respectively.(c)Includes allocations of common utility property.
(d)Includes assets not directly assignable to a business (i.e. cash and cash equivalents, certain accounts receivable, certain investments and other miscellaneous current
and deferred assets).
2018 2017 2016
(In thousands)
Assets:
Electric (c)$1,613,822 $1,470,922 $1,406,694
Natural gas distribution (c)2,375,871 2,201,081 2,099,296
Pipeline and midstream 616,959 566,295 550,615
Construction materials and contracting 1,508,032 1,238,696 1,220,459
Construction services 604,798 591,382 513,093
Other (d)266,111 261,419 283,255
Assets held for sale 2,517 4,871 211,055
Total assets $6,988,110 $6,334,666 $6,284,467
Property, plant and equipment:
Electric (c)$2,148,569 $1,982,264 $1,888,613
Natural gas distribution (c)2,499,093 2,319,845 2,179,413
Pipeline and midstream 764,959 700,284 672,199
Construction materials and contracting 1,768,006 1,560,048 1,549,375
Construction services 188,586 177,265 171,361
Other 28,108 31,123 49,268
Less accumulated depreciation, depletion and amortization 2,818,644 2,691,641 2,578,902
Net property, plant and equipment $4,578,677 $4,079,188 $3,931,327
Part II
96 MDU Resources Group, Inc. Form 10-K
Note 16 - Employee Benefit Plans
Pension and other postretirement benefit plans
The Company has noncontributory qualified defined benefit pension plans and other postretirement benefit plans for certain eligible
employees. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans.
Prior to 2013, defined benefit pension plan benefits and accruals for all nonunion and certain union plans were frozen and on June 30,
2015, the remaining union plan was frozen. These employees were eligible to receive additional defined contribution plan benefits. In
October 2018, the Company transferred the liability of certain participants in the defined benefit pension plan, who are currently receiving
benefits, to an annuity company. The transfer of the benefit payments for these participants reduces the Company's liability and future
premiums.
Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company's businesses. Employees
who had attained age 55 with 10 years of continuous service by December 31, 2010, will be provided the current retiree medical insurance
benefits or can elect the new benefit, if desired, regardless of when they retire. All other current employees must meet the new eligibility
criteria of age 60 and 10 years of continuous service at the time they retire. These employees will be eligible for a specified company
funded Retiree Reimbursement Account. Employees hired after December 31, 2009, will not be eligible for retiree medical benefits at
certain of the Company's businesses.
In 2012, the Company modified health care coverage for certain retirees. Effective January 1, 2013, post-65 coverage was replaced by a
fixed-dollar subsidy for retirees and spouses to be used to purchase individual insurance through an exchange.
Changes in benefit obligation and plan assets for the years ended December 31, 2018 and 2017, and amounts recognized in the
Consolidated Balance Sheets at December 31, 2018 and 2017, were as follows:
Pension Benefits OtherPostretirement Benefits
2018 2017 2018 2017
(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year $445,923 $436,307 $91,206 $89,304
Service cost ——1,494 1,508
Interest cost 14,591 16,207 2,899 3,265
Plan participants' contributions ——1,282 1,368
Actuarial (gain) loss (32,637)19,119 (10,115)1,781
Benefits paid (36,275)(25,710)(5,565)(6,020)
Benefit obligation at end of year 391,602 445,923 81,201 91,206
Change in net plan assets:
Fair value of plan assets at beginning of year 354,384 333,509 88,739 82,846
Actual gain (loss) on plan assets (21,138)45,473 (2,781)9,612
Employer contribution 10,838 1,112 842 933
Plan participants' contributions ——1,281 1,368
Benefits paid (36,275)(25,710)(5,565)(6,020)
Fair value of net plan assets at end of year 307,809 354,384 82,516 88,739
Funded status - over (under)$(83,793)$(91,539)$1,315 $(2,467)
Amounts recognized in the ConsolidatedBalance Sheets at December 31:
Deferred charges and other assets - other $—$—$20,843 19,114
Other accrued liabilities ——660 612
Deferred credits and other liabilities - other 83,793 91,539 18,868 20,969
Benefit obligation assets (liabilities) - net amount recognized $(83,793)$(91,539)$1,315 $(2,467)
Amounts recognized in accumulated other comprehensive (income) loss orregulatory assets (liabilities) consist of:
Actuarial loss $188,735 $186,486 $10,316 $13,423
Prior service credit ——(10,238)(11,632)
Total $188,735 $186,486 $78 $1,791
Employer contributions and benefits paid in the preceding table include only those amounts contributed directly to, or paid directly from,
plan assets. Accumulated other comprehensive (income) loss in the table above includes amounts related to regulated operations, which are
recorded as regulatory assets (liabilities) and are expected to be reflected in rates charged to customers over time. For more information on
regulatory assets (liabilities), see Note 6.
Unrecognized pension actuarial losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value
of assets are amortized over the average life expectancy of plan participants for frozen plans. The market-related value of assets is
determined using a five-year average of assets.
The pension plans all have accumulated benefit obligations in excess of plan assets. The projected benefit obligation, accumulated benefit
obligation and fair value of plan assets for these plans at December 31 were as follows:
2018 2017
(In thousands)
Projected benefit obligation $391,602 $445,923
Accumulated benefit obligation $391,602 $445,923
Fair value of plan assets $307,809 $354,384
Part II
MDU Resources Group, Inc. Form 10-K 97
Components of net periodic benefit cost (credit) for the Company's pension and other postretirement benefit plans for the years ended
December 31 were as follows:
Pension Benefits OtherPostretirement Benefits
2018 2017 2016 2018 2017 2016
(In thousands)
Components of net periodic benefit cost (credit):
Service cost $—$—$—$1,494 $1,508 $1,647
Interest cost 14,591 16,207 17,218 2,899 3,265 3,688
Expected return on assets (20,753)(20,528)(20,924)(4,866)(4,641)(4,533)
Amortization of prior service credit ———(1,394)(1,371)(1,371)
Recognized net actuarial loss 7,005 6,355 6,215 640 857 1,491
Net periodic benefit cost (credit), including amount capitalized 843 2,034 2,509 (1,227)(382)922
Less amount capitalized —310 381 153 (370)(52)
Net periodic benefit cost (credit)843 1,724 2,128 (1,380)(12)974
Other changes in plan assets and benefit obligations recognizedin accumulated comprehensive (income) loss or regulatoryassets (liabilities):
Net (gain) loss 9,254 (5,827)(3,789)(2,467)(3,190)(3,523)
Amortization of actuarial loss (7,005)(6,355)(6,215)(640)(857)(1,491)
Amortization of prior service credit ———1,394 1,371 1,371
Total recognized in accumulated other comprehensive (income)loss or regulatory assets (liabilities)2,249 (12,182)(10,004)(1,713)(2,676)(3,643)
Total recognized in net periodic benefit cost (credit),accumulated other comprehensive (income) loss andregulatory assets (liabilities)$3,092 $(10,458)$(7,876)$(3,093)$(2,688)$(2,669)
The estimated net loss for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss and
regulatory assets into net periodic benefit cost in 2019 is $5.6 million. The estimated net loss and prior service credit for the other
postretirement benefit plans that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic
benefit cost (credit) in 2019 are $500,000 and $1.4 million, respectively. Prior service cost is amortized on a straight line basis over the
average remaining service period of active participants.
Weighted average assumptions used to determine benefit obligations at December 31 were as follows:
Pension Benefits OtherPostretirement Benefits
2018 2017 2018 2017
Discount rate 4.03%3.38%4.05%3.41%
Expected return on plan assets 6.75%6.75%5.75%5.75%
Rate of compensation increase N/A N/A 3.00%3.00%
Weighted average assumptions used to determine net periodic benefit cost (credit) for the years ended December 31 were as follows:
Pension Benefits OtherPostretirement Benefits
2018 2017 2018 2017
Discount rate 3.38%3.83%3.41%3.86%
Expected return on plan assets 6.75%6.75%5.75%5.75%
Rate of compensation increase N/A N/A 3.00%3.00%
The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan.
As of December 31, 2018, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 40 percent
to 50 percent equity securities and 50 percent to 60 percent fixed-income securities and the expected rate of return from these asset
categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 25 percent to
30 percent equity securities and 70 percent to 75 percent fixed-income securities and the expected rate of return from these asset
categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.
Part II
98 MDU Resources Group, Inc. Form 10-K
Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:
2018 2017
Health care trend rate assumed for next year 7.5%–8.1%7.5%–8.5%
Health care cost trend rate - ultimate 4.5%4.5%
Year in which ultimate trend rate achieved 2024 2024
The Company's other postretirement benefit plans include health care and life insurance benefits for certain retirees. The plans underlying
these benefits may require contributions by the retiree depending on such retiree's age and years of service at retirement or the date of
retirement. The accounting for the health care plans anticipates future cost-sharing changes that are consistent with the Company's
expressed intent to generally increase retiree contributions each year by the excess of the expected health care cost trend rate over
six percent.
Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one percentage
point change in the assumed health care cost trend rates would have had the following effects at December 31, 2018:
1 Percentage Point Increase 1 PercentagePoint Decrease
(In thousands)
Effect on total of service and interest cost components $223 $(184)
Effect on postretirement benefit obligation $4,296 $(3,622)
Outside investment managers manage the Company's pension and postretirement assets. The Company's investment policy with respect to
pension and other postretirement assets is to make investments solely in the interest of the participants and beneficiaries of the plans and
for the exclusive purpose of providing benefits accrued and defraying the reasonable expenses of administration. The Company strives to
maintain investment diversification to assist in minimizing the risk of large losses. The Company's policy guidelines allow for investment of
funds in cash equivalents, fixed-income securities and equity securities. The guidelines prohibit investment in commodities and futures
contracts, equity private placement, employer securities, leveraged or derivative securities, options, direct real estate investments, precious
metals, venture capital and limited partnerships. The guidelines also prohibit short selling and margin transactions. The Company's practice
is to periodically review and rebalance asset categories based on its targeted asset allocation percentage policy.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction
between market participants at the measurement date. The fair value ASC establishes a hierarchy for grouping assets and liabilities, based
on the significance of inputs. The estimated fair values of the Company's pension plans' assets are determined using the market approach.
The carrying value of the pension plans' Level 2 cash equivalents approximates fair value and is determined using observable inputs in
active markets or the net asset value of shares held at year end, which is determined using other observable inputs including pricing from
outside sources.
The estimated fair value of the pension plans' Level 1 equity securities is based on the closing price reported on the active market on which
the individual securities are traded. The estimated fair value of the pension plans' Level 1 and Level 2 collective and mutual funds are
based on the net asset value of shares held at year end, based on either published market quotations on active markets or other known
sources including pricing from outside sources. The estimated fair value of the pension plans' Level 2 corporate and municipal bonds is
determined using other observable inputs, including benchmark yields, reported trades, broker/dealer quotes, bids, offers, future cash flows
and other reference data. The estimated fair value of the pension plans' Level 1 U.S. Government securities are valued based on quoted
prices on an active market.
The estimated fair value of the pension plans' Level 2 U.S. Government securities are valued mainly using other observable inputs,
including benchmark yields, reported trades, broker/dealer quotes, bids, offers, to be announced prices, future cash flows and other
reference data. Some of these securities are valued using pricing from outside sources.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use
of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2018 and 2017, there
were no transfers between Levels 1 and 2.
Part II
MDU Resources Group, Inc. Form 10-K 99
The fair value of the Company's pension plans' assets (excluding cash) by class were as follows:
Fair Value Measurements at December 31, 2018, Using
Quoted Pricesin ActiveMarkets forIdenticalAssets (Level 1)
SignificantOtherObservableInputs (Level 2)
SignificantUnobservable Inputs (Level 3)
Balance atDecember 31,2018
(In thousands)
Assets:
Cash equivalents $—$4,930 $—$4,930
Equity securities:
U.S. companies 11,038 ——11,038
International companies —967 —967
Collective and mutual funds*145,960 51,600 —197,560
Corporate bonds —73,110 —73,110
Municipal bonds —10,624 —10,624
U.S. Government securities 479 5,896 —6,375
Total assets measured at fair value $157,477 $147,127 $—$304,604
*Collective and mutual funds invest approximately 27 percent in common stock of international companies, 31 percent in corporate bonds, 18 percent in common stock
of large-cap U.S. companies, 5 percent in cash equivalents and 19 percent in other investments.
Fair Value Measurements at December 31, 2017, Using
Quoted Pricesin ActiveMarkets forIdenticalAssets (Level 1)
SignificantOtherObservableInputs (Level 2)
SignificantUnobservable Inputs (Level 3)
Balance atDecember 31,2017
(In thousands)
Assets:
Cash equivalents $—$3,814 $—$3,814
Equity securities:
U.S. companies 13,345 ——13,345
International companies 1,766 ——1,766
Collective and mutual funds*171,822 67,749 —239,571
Corporate bonds —74,956 —74,956
Municipal bonds —8,546 —8,546
U.S. Government securities 1,038 8,293 —9,331
Total assets measured at fair value $187,971 $163,358 $—$351,329
*Collective and mutual funds invest approximately 31 percent in common stock of international companies, 28 percent in corporate bonds, 19 percent in common stock
of large-cap U.S. companies, 7 percent in cash equivalents, 1 percent in U.S. Government securities and 14 percent in other investments.
The estimated fair values of the Company's other postretirement benefit plans' assets are determined using the market approach.
The estimated fair value of the other postretirement benefit plans' Level 2 cash equivalents is valued at the net asset value of shares held at
year end, based on published market quotations on active markets, or using other known sources including pricing from outside sources.
The estimated fair value of the other postretirement benefit plans' Level 1 equity securities is based on the closing price reported on the
active market on which the individual securities are traded. The estimated fair value of the other postretirement benefit plans' Level 2
insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate
accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs
or corroborated market data.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use
of other methods or assumptions could result in a different estimate of fair value. For the years ended December 31, 2018 and 2017, there
were no transfers between Levels 1 and 2.
Part II
100 MDU Resources Group, Inc. Form 10-K
The fair value of the Company's other postretirement benefit plans' assets (excluding cash) by asset class were as follows:
Fair Value Measurements at December 31, 2018, Using
Quoted Pricesin ActiveMarkets forIdenticalAssets (Level 1)
SignificantOtherObservableInputs (Level 2)
SignificantUnobservable Inputs (Level 3)
Balance atDecember 31,2018
(In thousands)
Assets:
Cash equivalents $—$3,866 $—$3,866
Equity securities:
U.S. companies 1,767 ——1,767
International companies —2 —2
Insurance contract*1 76,880 —76,881
Total assets measured at fair value $1,768 $80,748 $—$82,516
*The insurance contract invests approximately 51 percent in corporate bonds, 23 percent in common stock of large-cap U.S. companies, 7 percent in U.S. Government
securities, 7 percent in common stock of small-cap U.S. companies and 12 percent in other investments.
Fair Value Measurements at December 31, 2017, Using
Quoted Pricesin ActiveMarkets forIdenticalAssets (Level 1)
SignificantOtherObservableInputs (Level 2)
SignificantUnobservable Inputs (Level 3)
Balance atDecember 31,2017
(In thousands)
Assets:
Cash equivalents $—$4,815 $—$4,815
Equity securities:
U.S. companies 2,316 ——2,316
International companies 4 ——4
Insurance contract*3 81,601 —81,604
Total assets measured at fair value $2,323 $86,416 $—$88,739
*The insurance contract invests approximately 38 percent in corporate bonds, 23 percent in common stock of large-cap U.S. companies, 21 percent in U.S.
Government securities, 9 percent in mortgage-backed securities and 9 percent in other investments.
The Company expects to contribute approximately $4.0 million to its defined benefit pension plans and approximately $700,000 to its
postretirement benefit plans in 2019.
The following benefit payments, which reflect future service, as appropriate, and expected Medicare Part D subsidies at December 31,
2018, are as follows:
Years PensionBenefits
OtherPostretirementBenefits
ExpectedMedicarePart D Subsidy
(In thousands)
2019 $24,026 $5,332 $117
2020 24,287 5,232 112
2021 24,633 5,201 105
2022 24,929 5,259 98
2023 25,173 5,270 90
2024 - 2028 124,688 25,851 320
Part II
MDU Resources Group, Inc. Form 10-K 101
Nonqualified benefit plans
In addition to the qualified defined benefit pension plans reflected in the table at the beginning of this note, the Company also has
unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined
benefit payments at age 65 following the employee's retirement or, upon death, to their beneficiaries for a 15-year period. In February
2016, the Company froze the unfunded, nonqualified defined benefit plans to new participants and eliminated benefit increases. Vesting for
participants not fully vested was retained.
The projected benefit obligation and accumulated benefit obligation for these plans at December 31 were as follows:
2018 2017
(In thousands)
Projected benefit obligation $93,988 $102,484
Accumulated benefit obligation $93,988 $102,484
Components of net periodic benefit cost for the Company's nonqualified benefit plans for the years ended December 31 were as follows:
2018 2017 2016
(In thousands)
Components of net periodic benefit cost:
Service cost $185 $289 $493
Interest cost 3,157 3,494 3,742
Amortization of prior service cost ——(80)
Recognized net actuarial loss 1,047 883 952
Curtailment gain ——(3,292)
Net periodic benefit cost $4,389 $4,666 $1,815
Weighted average assumptions used at December 31 were as follows:
2018 2017
Benefit obligation discount rate 3.86%3.20%
Benefit obligation rate of compensation increase N/A N/A
Net periodic benefit cost discount rate 3.20%3.56%
Net periodic benefit cost rate of compensation increase N/A N/A
The amount of future benefit payments for the unfunded, nonqualified benefit plans at December 31, 2018, are expected to aggregate as
follows:
2019 2020 2021 2022 2023 Thereafter
(In thousands)
Nonqualified benefits $7,350 $7,766 $7,787 $7,018 $7,213 $36,885
In 2012, the Company established a nonqualified defined contribution plan for certain key management employees. Expenses incurred
under this plan for 2018, 2017 and 2016 were $597,000, $736,000 and $395,000, respectively.
The amount of investments that the Company anticipates using to satisfy obligations under these plans at December 31 was as follows:
2018 2017
(In thousands)
Investments
Insurance contract*$73,838 $77,388
Life insurance**37,274 38,568
Other 10,818 6,971
Total investments $121,930 $122,927
*For more information on the insurance contract, see Note 7.
**Investments of life insurance are carried on plan participants (payable upon the employee's
death).
Defined contribution plans
The Company sponsors various defined contribution plans for eligible employees and the costs incurred under these plans were
$42.4 million in 2018, $41.2 million in 2017 and $40.9 million in 2016.
Part II
102 MDU Resources Group, Inc. Form 10-K
Multiemployer plans
The Company contributes to a number of MEPPs under the terms of collective-bargaining agreements that cover its union-represented
employees. The risks of participating in these multiemployer plans are different from single-employer plans in the following aspects:
•Assets contributed to the MEPP by one employer may be used to provide benefits to employees of other participating employers
•If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining
participating employers
•If the Company chooses to stop participating in some of its MEPPs, the Company may be required to pay those plans an amount based on
the underfunded status of the plan, referred to as a withdrawal liability
The Company's participation in these plans is outlined in the following table. Unless otherwise noted, the most recent Pension Protection
Act zone status available in 2018 and 2017 is for the plan's year-end at December 31, 2017, and December 31, 2016, respectively. The
zone status is based on information that the Company received from the plan and is certified by the plan's actuary. Among other factors,
plans in the red zone are generally less than 65 percent funded, plans in the yellow zone are between 65 percent and 80 percent funded,
and plans in the green zone are at least 80 percent funded.
EIN/PensionPlan Number
Pension Protection ActZone Status FIP/RP StatusPending/Implemented
Contributions SurchargeImposed
Expiration Dateof CollectiveBargainingAgreementPension Fund 2018 2017 2018 2017 2016
(In thousands)
Alaska Laborers-EmployersRetirement Fund 91-6028298-001 Yellow as of6/30/2018 Yellow as of6/30/2017 Implemented $732 $690 $766 No 12/31/2018 *
Construction Industryand Laborers JointPension Trust for SoNevada, Plan A 88-0135695-001 Red Red Implemented 346 377 523 No 6/30/2019
Edison Pension Plan 93-6061681-001 Green Green No 12,111 12,725 6,242 No 6/30/2019
IBEW Local 212Pension Trust 31-6127280-001 Green as of4/30/2018 Green as of4/30/2017 No 1,341 1,312 1,146 No 6/2/2019
IBEW Local 357Pension Plan A 88-6023284-001 Green Green No 3,460 3,286 3,016 No 5/31/2021
IBEW Local 648Pension Plan 31-6134845-001 Yellow as of2/28/2018 Red as of2/28/2017 Implemented 2,175 2,254 773 No 8/29/2021
IBEW Local 82Pension Plan 31-6127268-001 Green as of6/30/2018 Green as of6/30/2017 No 1,569 1,757 2,560 No 12/1/2019
Idaho Plumbers andPipefitters PensionPlan 82-6010346-001 Green as of5/31/2018 Green as of5/31/2017 No 1,247 1,156 1,221 No 9/30/2019
Minnesota TeamstersConstruction DivisionPension Fund 41-6187751-001 Green as of11/30/2017 Green as of11/30/2016 No 740 826 690 No 4/30/2019
National AutomaticSprinkler IndustryPension Fund 52-6054620-001 Red Red Implemented 738 718 775 No 3/31/2021-7/31/2024
National ElectricalBenefit Fund 53-0181657-001 Green Green No 8,468 8,891 6,366 No 1/31/2018-5/31/2022
Pension Trust Fund forOperating Engineers 94-6090764-001 Yellow Red Implemented 2,403 2,391 2,069 No 6/15/2019-6/30/2020
Sheet Metal WorkersPension Plan ofSouthern CA, AZ, andNV 95-6052257-001 Yellow Yellow Implemented 1,774 1,016 1,087 No 6/30/2019
Southwest MarinePension Trust 95-6123404-001 Red Red Implemented 81 48 50 No 1/31/2019 *
Other funds 21,537 19,298 17,243
Total contributions $58,722 $56,745 $44,527
*Plan includes contributions required by collective bargaining agreements which have expired, but contain provisions automatically renewing their terms in the absence
of a subsequent negotiated agreement.
Part II
MDU Resources Group, Inc. Form 10-K 103
The Company was listed in the plans' Forms 5500 as providing more than 5 percent of the total contributions for the following plans and
plan years:
Pension Fund Year Contributions to Plan Exceeded More Than 5 Percentof Total Contributions (as of December 31 of the Plan's Year-End)
Edison Pension Plan 2017 and 2016
IBEW Local 82 Pension Plan 2017 and 2016
IBEW Local 124 Pension Trust Fund 2017 and 2016
IBEW Local 212 Pension Trust Fund 2017 and 2016
IBEW Local 357 Pension Plan A 2017 and 2016
IBEW Local 648 Pension Plan 2017 and 2016
Idaho Plumbers and Pipefitters Pension Plan 2017 and 2016
International Union of Operating Engineers Local 701 Pension Trust Fund 2017 and 2016
Minnesota Teamsters Construction Division Pension Fund 2017 and 2016
Pension and Retirement Plan of Plumbers and Pipefitters Local 525 2017 and 2016
On September 24, 2014, Knife River provided notice to the Operating Engineers Local 800 & WY Contractors Association, Inc. Pension
Plan for Wyoming that it was withdrawing from the plan effective October 26, 2014. In the fourth quarter of 2016, Knife River and the plan
entered into a settlement agreement whereby the plan administrator assessed Knife River’s final withdrawal liability with quarterly payments
of approximately $42,000 until all benefits are satisfied. Knife River discounted the expected future payments. Based on this calculation,
Knife River adjusted its liability accrual from $16.4 million to $5.2 million in the fourth quarter of 2016.
The Company also contributes to a number of multiemployer other postretirement plans under the terms of collective-bargaining agreements
that cover its union-represented employees. These plans provide benefits such as health insurance, disability insurance and life insurance to
retired union employees. Many of the multiemployer other postretirement plans are combined with active multiemployer health and welfare
plans. The Company's total contributions to its multiemployer other postretirement plans, which also includes contributions to active
multiemployer health and welfare plans, were $53.3 million, $52.2 million and $36.1 million for the years ended December 31, 2018,
2017 and 2016, respectively.
Amounts contributed in 2018, 2017 and 2016 to defined contribution multiemployer plans were $31.1 million, $32.2 million and
$23.8 million, respectively.
Part II
104 MDU Resources Group, Inc. Form 10-K
Note 17 - Jointly Owned Facilities
The consolidated financial statements include the Company's ownership interests in the assets, liabilities and expenses of Big Stone
Station, Coyote Station and Wygen III. Each owner of the stations is responsible for financing its investment in the jointly owned facilities.
The Company has an ownership interest of 22.7 percent in Big Stone Station, 25 percent in Coyote Station and 25 percent in Wygen III.
The Company's share of the stations operating expenses was reflected in the appropriate categories of operating expenses (electric fuel and
purchased power; operation and maintenance; and taxes, other than income) in the Consolidated Statements of Income.
At December 31, the Company's share of the cost of utility plant in service and related accumulated depreciation for the stations was as
follows:
2018 2017
(In thousands)
Big Stone Station:
Utility plant in service $156,534 $158,084
Less accumulated depreciation 49,345 51,740
$107,189 $106,344
Coyote Station:
Utility plant in service $155,236 $155,287
Less accumulated depreciation 105,565 103,897
$49,671 $51,390
Wygen III:
Utility plant in service $65,382 $65,065
Less accumulated depreciation 9,174 7,652
$56,208 $57,413
Note 18 - Regulatory Matters
The Company regularly reviews the need for electric and natural gas rate changes in each of the jurisdictions in which service is provided.
The Company files for rate adjustments to seek recovery of operating costs and capital investments, as well as reasonable returns as allowed
by regulators. The Company's most recent cases by jurisdiction are discussed in the following paragraphs. The jurisdictions in which the
Company provides service have requested the Company furnish plans for the effect of the reduced corporate tax rate due to the enactment
of the TCJA which may impact the Company's rates. The following paragraphs include additional details and statuses of each open request.
MNPUC
On December 29, 2017, the MNPUC issued a notice of investigation related to tax changes with the enactment of the TCJA. On January 19,
2018, the MNPUC issued a notice of request for information, commission planning meeting and subsequent comment period. Pursuant to
the notice, Great Plains provided preliminary impacts of the TCJA on January 30, 2018. On March 2, 2018, Great Plains submitted its
initial filing addressing the impacts of the TCJA advocating existing rates are reasonable and a reduction in rates is not warranted. On
August 9, 2018, the MNPUC ruled that Great Plains reduce rates to reflect TCJA impacts and to also provide a one-time refund that
captures the TCJA impacts from January 1, 2018 through the implementation date of new rates. On December 5, 2018, the MNPUC issued
an order requiring Great Plains reduce its rates by $400,000 on an annual basis and provide a one-time refund of approximately $400,000,
as previously mentioned, within 90 days after the rates are implemented through credits to customers' bills. The required compliance filing
was submitted to the MNPUC on January 4, 2019.
MTPSC
On December 27, 2017, the MTPSC requested Montana-Dakota identify a plan for the impacts of the TCJA and to file a proposal for the
impacts on the electric segment by March 31, 2018. On April 2, 2018, Montana-Dakota submitted its plan requesting the MTPSC
recognize the identified need for additional rate relief and to consider the effects of the TCJA in a general electric rate case to be submitted
by September 30, 2018. Montana-Dakota submitted the general electric rate case on September 28, 2018, as discussed below. On
November 30, 2018, Montana-Dakota and interveners of the case submitted a stipulation and settlement agreement reflecting a one-time
refund of approximately $1.5 million to account for all TCJA related impacts from January 1, 2018 through the date new rates are effective
in the rate case noted below. A hearing was held on December 4, 2018, and the MTPSC issued an order accepting the stipulation and
settlement agreement on December 21, 2018, requiring a one-time bill credit to occur in April 2019.
On September 28, 2018, Montana-Dakota filed an application with the MTPSC for an electric rate increase of approximately $11.9 million
annually or approximately 18.9 percent above current rates. The requested increase is primarily to recover investments in facilities to
enhance safety and reliability and the depreciation and taxes associated with the increase in investment. The increase was offset by tax
savings related to the TCJA. This matter is pending before the MTPSC.
NDPSC
On July 21, 2017, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase of approximately $5.9 million
annually or approximately 5.4 percent above current rates. The requested increase is primarily to recover the increased investment in
distribution facilities to enhance system safety and reliability and the depreciation and taxes associated with the increase in investment.
Montana-Dakota also introduced a SSIP and the proposed adjustment mechanism required to fund the SSIP. Montana-Dakota requested an
interim increase of approximately $4.6 million or approximately 4.2 percent, subject to refund. On September 6, 2017, the NDPSC
approved the request for interim rates effective with service rendered on or after September 19, 2017. On February 14, 2018, Montana-
Dakota filed a revised interim increase request of approximately $2.7 million, subject to refund, incorporating the estimated impacts of the
TCJA reduction in the federal corporate income tax rate. On March 1, 2018, the updated interim rates were implemented. The impact of the
TCJA was submitted as part of a rebuttal testimony identifying a reduction of the adjusted revenue requirement to approximately
$3.6 million. On July 19, 2018, a settlement was filed reflecting a revised annual revenue increase of approximately $2.5 million or
approximately 2.3 percent. The proposed adjustment mechanism to fund the SSIP was not included in the settlement and will be decided
on separately by the NDPSC. On September 26, 2018, the NDPSC issued an order approving the settlement as filed but did not approve the
SSIP recovery mechanism. On October 5, 2018, Montana-Dakota submitted a compliance filing, which included a plan for the one-time
refund to be available March 1, 2019, for the interim amount to be refunded to customers. The NDPSC approved the compliance rates and
were effective with service rendered on and after December 1, 2018.
On January 10, 2018, the NDPSC issued a general order initiating the investigation into the effects of the TCJA. The order required
regulatory deferral accounting on the impacts of the TCJA and for companies to file comments and the expected impacts. On February 15,
2018, Montana-Dakota filed a summary of the primary impacts of the TCJA on the electric and natural gas utilities. On March 9, 2018,
Montana-Dakota submitted a request to decrease its electric rates by $7.2 million or 3.9 percent annually. On August 10, 2018, a
settlement agreement was filed requesting a decrease in rates of approximately $8.4 million. On September 26, 2018, the NDPSC issued
an order approving the settlement along with requiring an additional adjustment to the rates to return 100 percent of the tax-effective 2018
excess deferred income taxes. On October 10, 2018, Montana-Dakota submitted a compliance filing, which included a refund plan for the
Part II
MDU Resources Group, Inc. Form 10-K 105
interim amount to be refunded to customers. On November 20, 2018, the NDPSC approved the compliance rates which were effective with
service rendered on and after December 1, 2018. The NDPSC also approved a one-time refund of approximately $7.9 million to be credited
to customers' bills by March 15, 2019, based on 4.7 percent of the revenues collected between January 1, 2018 through November 30,
2018.
On October 19, 2018, Great Plains and the NDPSC advocacy staff filed a settlement agreement to resolve all outstanding issues in the
NDPSC's investigation into the TCJA and a revenue neutral tariff filing submitted by Great Plains. The settlement agreement provides for
miscellaneous tariff changes and a reduction in annual revenues of $168,000. On January 9, 2019, the NDPSC issued an order approving
the settlement agreement and a refund requirement for the period from January 1, 2018 through the month preceding the effective date of
the rate change. On January 23, 2019, the NDPSC approved the compliance rates to be effective February 1, 2019, along with the refund
plan that provides for approximately $200,000 in refunds to be credited to customers' bills by April 15, 2019.
OPUC
On December 29, 2017, Cascade filed a request with the OPUC to use deferral accounting for the 2018 net benefits associated with the
implementation of the TCJA. The deferral request was renewed on December 28, 2018. This matter is pending before the OPUC.
On May 31, 2018, Cascade filed a general rate case with the OPUC requesting an overall increase of approximately $2.3 million or
approximately 3.5 percent on an annual basis, which incorporates the impact of the TCJA. On January 22, 2019, Cascade filed a stipulation
with the OPUC for an annual increase in revenues of $1.7 million with a $500,000 reduction for excess deferred income taxes, for a net
increase of $1.2 million. This matter is pending before the OPUC.
SDPUC
On December 29, 2017, the SDPUC issued an order initiating the investigation into the effects of the TCJA. The order required Montana-
Dakota to provide comments by February 1, 2018, regarding the general effects of the TCJA on the cost of service in South Dakota and
possible mechanisms for adjusting rates. The order also stated that all rates impacted by the federal income tax shall be adjusted effective
January 1, 2018, subject to refund. On May 4, 2018 and June 2, 2018, Montana-Dakota submitted detailed plans to address the TCJA
impacts on the natural gas and electric utilities, respectively, to the SDPUC staff. On September 28, 2018, a settlement agreement was
submitted to the SDPUC reflecting a proposal to refund approximately $600,000 to electric customers and approximately $1.3 million to
natural gas customers. These refunds reflect the impact of the TCJA on 2018. On October 23, 2018, an order was issued by the SDPUC
approving the settlement agreement with the refunds being credited to customers' bills beginning on February 15, 2019. On December 3,
2018, Montana-Dakota submitted proposed rate changes to reflect 2018 pro forma results and the TCJA impacts. On December 28, 2018,
the SDPUC approved an annual decrease in revenues of approximately $300,000 for the natural gas operations and approximately
$100,000 for the electric operations. The decrease in revenues was effective January 1, 2019.
WUTC
On June 1, 2018, Cascade filed its annual pipeline cost recovery mechanism requesting an increase in annual revenue of $2.3 million or
approximately 1.1 percent. On October 11, 2018, Cascade filed a revised increase in annual revenue of $2.1 million or approximately
1.0 percent. The increase was effective November 1, 2018.
WYPSC
On December 29, 2017, the WYPSC issued a general order requiring regulatory deferral accounting on the impacts of the TCJA. A technical
conference was held on February 6, 2018, to discuss the implications of the TCJA. On March 23, 2018, the WYPSC issued an order
requiring all public utilities to submit an initial assessment of the overall effects on the TCJA on their rates by March 30, 2018. On
March 30, 2018, Montana-Dakota submitted its initial assessment indicating a rate reduction for its electric rates in the amount of
approximately $1.1 million annually or approximately 4.2 percent. Revised electric rates reflecting this reduction were submitted to the
WYPSC on June 13, 2018. Montana-Dakota reported its natural gas earnings do not support a decrease in rates and requested the WYPSC
allow the impacts of the TCJA be addressed in a natural gas rate case to be submitted by June 1, 2019. Both matters are pending before
the WYPSC.
FERC
Montana-Dakota and certain MISO Transmission Owners with projected rates submitted a filing to the FERC on February 1, 2018,
requesting the FERC to waive certain provisions of the MISO tariff in order for Montana-Dakota and certain MISO Transmission Owners with
projected rates to revise their rates to reflect the reduction in the corporate tax rate. Under the MISO tariff, rates are to be changed only on
an annual basis with any changes reflected in subsequent true-ups. On March 15, 2018, the FERC approved the waiver request and new
rates reflecting the effects of the TCJA were implemented by MISO on March 1, 2018. MISO also retroactively re-billed the January and
February 2018 services to reflect the new rates. On September 4, 2018, Montana-Dakota filed an update to its transmission formula rate
under the MISO tariff for the multivalue project for $12.5 million, which is effective January 1, 2019.
Part II
106 MDU Resources Group, Inc. Form 10-K
On July 18, 2018, the FERC issued a final rule on Rate Changes Relating to Federal Income Tax Rate reductions resulting from the TCJA
which requires natural gas pipeline companies to make a one-time informational filing to evaluate the impact of the lower corporate income
tax rate and also select one of four options presented by the FERC to address the impact. In accordance with WBI Energy Transmission’s
offer of settlement and stipulation and agreement with the FERC dated June 4, 2014, the Company is to make a filing with new proposed
rates to be effective no later than May 1, 2019. On October 31, 2018, the Company filed a rate case with the FERC. Due to the timing of
the rate case filing, the Company was exempt from the one-time informational filing required by the FERC’s final rule. On November 30,
2018, the FERC issued an order accepting and suspending tariff records, subject to refund, and establishing hearing procedures. The FERC
order accepted the Company's rate case filing and suspended the associated tariff records to be effective May 1, 2019, subject to refund
and the outcome of a hearing.
Part II
MDU Resources Group, Inc. Form 10-K 107
Note 19 - Commitments and Contingencies
The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries, which may include, but are
not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. The
Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated.
If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the
minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is
probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For
contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of
the contingency and, in some circumstances, an estimate of the possible loss. Accruals are based on the best information available, but in
certain situations management is unable to estimate an amount or range of a reasonably possible loss including, but not limited to when:
(1) the damages are unsubstantiated or indeterminate, (2) the proceedings are in the early stages, (3) numerous parties are involved, or (4)
the matter involves novel or unsettled legal theories.
The Company has accrued liabilities of $30.4 million and $35.4 million, which have not been discounted, including liabilities held for sale,
for contingencies, including litigation, production taxes, royalty claims and environmental matters at December 31, 2018 and 2017,
respectively. This includes amounts that have been accrued for matters discussed in Environmental matters within this note. The Company
will continue to monitor each matter and adjust accruals as might be warranted based on new information and further developments.
Management believes that the outcomes with respect to probable and reasonably possible losses in excess of the amounts accrued, net of
insurance recoveries, while uncertain, either cannot be estimated or will not have a material effect upon the Company's financial position,
results of operations or cash flows. Unless otherwise required by GAAP, legal costs are expensed as they are incurred.
Environmental matters
Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a
riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. in 1999. The
riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment
contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being
recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include Knife
River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $100 million. On January 6, 2017,
Region 10 of the EPA issued an ROD with its selected remedy for cleanup of the in-river portion of the site. Implementation of the remedy is
expected to take up to 13 years with a present value cost estimate of approximately $1 billion. Corrective action will not be taken until
remedial design/remedial action plans are approved by the EPA. Knife River - Northwest also received notice in January 2008 that the
Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of
hazardous substances at the Harbor Superfund Site. The Portland Harbor Natural Resource Trustee Council indicates the injury
determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to
estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.
Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, Knife
River - Northwest does not believe it is a responsible party. In addition, Knife River - Northwest has notified Georgia-Pacific West, Inc., that
it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement. Knife
River - Northwest has entered into an agreement tolling the statute of limitations in connection with the LWG's potential claim for
contribution to the costs of the remedial investigation and feasibility study. By letter in March 2009, LWG stated its intent to file suit
against Knife River - Northwest and others to recover LWG's investigation costs to the extent Knife River - Northwest cannot demonstrate its
non-liability for the contamination or is unwilling to participate in an alternative dispute resolution process that has been established to
address the matter. At this time, Knife River - Northwest has agreed to participate in the alternative dispute resolution process.
The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above
referenced matter.
Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant
sites operated by Cascade's predecessors. The accruals related to these claims are reflected in regulatory assets. For more information, see
Note 6.
The first claim is for contamination at a site in Eugene, Oregon, which was received in 1995. The Oregon DEQ released an ROD in January
2015 that selected a remediation alternative for the site as recommended in an earlier staff report. The total estimated cost for the selected
remediation, including long-term maintenance, is approximately $3.5 million of which $400,000 has been incurred. Cascade and other
PRPs will share in the cleanup costs with Cascade expecting to pay approximately 50 percent of the remediation and maintenance costs.
Cascade has an accrual balance of $1.5 million for remediation of this site. In January 2013, the OPUC approved Cascade's application to
defer environmental remediation costs at the Eugene site for a period of 12 months starting November 30, 2012. Cascade received orders
reauthorizing the deferred accounting for the 12-month periods starting November 30, 2013, December 1, 2014, December 1, 2015,
December 1, 2016, December 1, 2017 and December 1, 2018.
The second claim is for contamination at the Bremerton Gasworks Superfund Site in Bremerton, Washington which was received in 1997. A
preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. The
EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August
2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port
Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to
$6.4 million. In April 2010, the Washington DOE issued notice it considered Cascade a PRP for hazardous substances at the site. In May
2012, the EPA added the site to the National Priorities List of Superfund sites. Cascade has entered into an administrative settlement
agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site.
Current estimates for the cost to complete the remedial investigation and feasibility study are approximately $7.6 million of which
$3.1 million has been incurred. Cascade has accrued $4.5 million for the remedial investigation and feasibility study, as well as
$6.4 million for remediation of this site; however, the accrual for remediation costs will be reviewed and adjusted, if necessary, after
completion of the remedial investigation and feasibility study. In April 2010, Cascade filed a petition with the WUTC for authority to defer
the costs incurred in relation to the environmental remediation of this site. The WUTC approved the petition in September 2010, subject to
conditions set forth in the order.
The third claim is for contamination at a site in Bellingham, Washington. Cascade received notice from a party in May 2008 that Cascade
may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade and its predecessor from about
1946 to 1962. Other PRPs reached an agreed order and work plan with the Washington DOE for completion of a remedial investigation and
feasibility study for the site. A feasibility study prepared in March 2018 identifies five cleanup action alternatives for the site with estimated
costs ranging from $8.0 million to $20.4 million with a selected preferred alternative having an estimated total cost of $9.3 million.
Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from
coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, it converted the plant to a
propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas.
Cascade has recorded an accrual for this site for an amount that is not material.
Cascade has received notices from and entered into agreement with certain of its insurance carriers that they will participate in defense of
Cascade for certain of the contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. To
the extent these claims are not covered by insurance, Cascade intends to seek recovery through the OPUC and WUTC of remediation costs in
its natural gas rates charged to customers.
Operating leases
The Company leases certain equipment, facilities and land under operating lease agreements. The amounts of annual minimum lease
payments due under these leases as of December 31, 2018, were:
2019 2020 2021 2022 2023 Thereafter
(In thousands)
Operating leases $37,740 $26,255 $17,868 $11,647 $7,278 $49,098
Rent expense was $74.6 million, $73.7 million and $65.0 million for the years ended December 31, 2018, 2017 and 2016, respectively.
Part II
108 MDU Resources Group, Inc. Form 10-K
Purchase commitments
The Company has entered into various commitments, largely construction, natural gas and coal supply, purchased power, natural gas
transportation and storage, and service, shipping and construction materials supply contracts, some of which are subject to variability in
volume and price. The commitment terms vary in length, up to 42 years. The commitments under these contracts as of December 31,
2018, were:
2019 2020 2021 2022 2023 Thereafter
(In thousands)
Purchase commitments $418,106 $215,069 $169,716 $115,884 $84,268 $622,383
These commitments were not reflected in the Company's consolidated financial statements. Amounts purchased under various commitments
for the years ended December 31, 2018, 2017 and 2016, were $548.0 million, $516.1 million and $539.3 million, respectively.
Guarantees
In June 2016, WBI Energy sold all of the outstanding membership interests in Dakota Prairie Refining. In connection with the sale,
Centennial agreed to continue to guarantee certain debt obligations of Dakota Prairie Refining which were expected to mature in 2023.
Tesoro agreed to indemnify Centennial for any losses and litigation expenses arising from the guarantee. Continuation of the guarantee was
required as a condition to the sale of Dakota Prairie Refining. On October 17, 2018, Centennial was released from this guarantee of certain
debt obligations of Dakota Prairie Refining.
In 2009, multiple sale agreements were signed to sell the Company's ownership interests in the Brazilian Transmission Lines. In connection
with the sale, Centennial agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned
subsidiaries who were the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The
guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines.
Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the
Company. These guarantees are related to construction contracts, insurance deductibles and loss limits, and certain other guarantees. At
December 31, 2018, the fixed maximum amounts guaranteed under these agreements aggregated $196.3 million. The amounts of
scheduled expiration of the maximum amounts guaranteed under these agreements aggregate to $85.3 million in 2019; $104.0 million in
2020; $500,000 in 2021; $500,000 in 2022; $500,000 in 2023; $1.5 million thereafter; and $4.0 million, which has no scheduled
maturity date. There were no amounts outstanding under the above guarantees at December 31, 2018. In the event of default under these
guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its
guarantee.
Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are
guaranteed by other subsidiaries of the Company. At December 31, 2018, the fixed maximum amounts guaranteed under these letters of
credit aggregated $30.0 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these letters of credit
aggregate to $6.7 million in 2019 and $23.3 million in 2020. There were no amounts outstanding under the above letters of credit at
December 31, 2018. In the event of default under these letter of credit obligations, the subsidiary guaranteeing the letter of credit would be
obligated for reimbursement of payments made under the letter of credit.
In addition, Centennial, Knife River and MDU Construction Services have issued guarantees to third parties related to the routine purchase
of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no
scheduled maturity date. In the event a subsidiary of the Company defaults under these obligations, Centennial, Knife River or MDU
Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the
Company were reflected on the Consolidated Balance Sheet at December 31, 2018.
In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its
subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond
company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next
12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. At December 31, 2018,
approximately $697.9 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.
Variable interest entities
The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the
primary beneficiary.
Part II
MDU Resources Group, Inc. Form 10-K 109
Fuel Contract Coyote Station entered into a coal supply agreement with Coyote Creek that provides for the purchase of coal necessary to
supply the coal requirements of the Coyote Station for the period May 2016 through December 2040. Coal purchased under the coal supply
agreement is reflected in inventories on the Company's Consolidated Balance Sheets and is recovered from customers as a component of
electric fuel and purchased power.
The coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote
Station owners, as the agreement is structured so that the price of the coal will cover all costs of operations, as well as future reclamation
costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy
the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value
of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the
Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek
because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station, with no primary
beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements.
At December 31, 2018, the Company's exposure to loss as a result of the Company's involvement with the VIE, based on the Company's
ownership percentage was $38.5 million.
Part II
110 MDU Resources Group, Inc. Form 10-K
Note 20 - Subsequent Event
On February 19, 2019, the Company announced that it intends to retire three aging coal-fired electric generation units within the next three
years due to the fact that the plants are no longer expected to be cost competitive. The retirements are expected to be in late 2020 in
Sidney, Montana, and in late 2021 in Mandan, North Dakota. A plan is in place to maintain staff until the plant retirements. These dates
may be impacted by the Company's coal supplier's pending bankruptcy proceeding. In addition, the Company announced that it intends to
construct a new simple-cycle natural gas combustion turbine peaking unit at the existing plant site in Mandan, North Dakota.
Supplementary Financial Information
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter for the years 2018 and 2017:
FirstQuarter SecondQuarter ThirdQuarter FourthQuarter
(In thousands, except per share amounts)
2018
Operating revenues $976,293 $1,064,597 $1,280,787 $1,209,875
Operating expenses 906,917 990,605 1,140,783 1,091,524
Operating income 69,376 73,992 140,004 118,351
Income from continuing operations 41,960 44,075 107,369 75,982
Income (loss) from discontinued operations, net of tax 477 (273)(118)2,846
Net income 42,437 43,802 107,251 78,828
Earnings per common share - basic:
Earnings before discontinued operations .22 .22 .55 .39
Discontinued operations, net of tax ———.01
Earnings per common share - basic .22 .22 .55 .40
Earnings per common share - diluted:
Earnings before discontinued operations .22 .22 .55 .39
Discontinued operations, net of tax ———.01
Earnings per common share - diluted .22 .22 .55 .40
Weighted average common shares outstanding:
Basic 195,304 195,524 196,018 196,023
Diluted 195,982 196,169 196,265 196,385
2017
Operating revenues $937,925 $1,067,639 $1,272,548 $1,165,239
Operating expenses 872,139 988,979 1,117,228 1,040,957
Operating income 65,786 78,660 155,320 124,282
Income from continuing operations 35,638 44,405 89,549 115,394
Income (loss) from discontinued operations, net of tax 1,687 (3,190)(2,198)(82)
Net income 37,325 41,215 87,351 115,312
Earnings per common share - basic:
Earnings before discontinued operations .18 .22 .46 .59
Discontinued operations, net of tax .01 (.01)(.01)—
Earnings per common share - basic .19 .21 .45 .59
Earnings per common share - diluted:
Earnings before discontinued operations .18 .22 .46 .59
Discontinued operations, net of tax .01 (.01)(.01)—
Earnings per common share - diluted .19 .21 .45 .59
Weighted average common shares outstanding:
Basic 195,304 195,304 195,304 195,304
Diluted 196,023 195,973 195,783 195,617
Notes:
•Fourth quarter 2017 reflects an income tax benefit of $39.5 million related to the TCJA. For more information, see Note 13.
Certain operations of the Company are highly seasonal and revenues from and certain expenses for such operations may fluctuate
significantly among quarterly periods. Accordingly, quarterly financial information may not be indicative of results for a full year.
Part II
MDU Resources Group, Inc. Form 10-K 111
Definitions
The following abbreviations and acronyms used in Notes to Consolidated Financial Statements are defined below:
Abbreviation or Acronym
AFUDC Allowance for funds used during construction
ASC FASB Accounting Standards Codification
ASU FASB Accounting Standards Update
Big Stone Station 475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percentownership)
Brazilian Transmission Lines Company's former investment in companies owning three electric transmission lines in Brazil
Calumet Calumet Specialty Products Partners, L.P.
Cascade Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
Centennial Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial's Consolidated EBITDA Centennial's consolidated net income from continuing operations plus the related interestexpense, taxes, depreciation, depletion, amortization of intangibles and any non-cash chargerelating to asset impairment for the preceding 12-month period
Centennial Resources Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
Company MDU Resources Group, Inc. (formerly known as MDUR Newco), which, as the context requires,refers to the previous MDU Resources Group, Inc. prior to January 1, 2019, and the new holdingcompany of the same name after January 1, 2019
Coyote Creek Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station 427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
Dakota Prairie Refinery 20,000-barrel-per-day diesel topping plant built by Dakota Prairie Refining in southwestern
North Dakota
Dakota Prairie Refining Dakota Prairie Refining, LLC, a limited liability company previously owned by WBI Energy and
Calumet (previously included in the Company's refining segment)
EBITDA Earnings before interest, taxes, depreciation, depletion and amortization
EIN Employer Identification Number
EPA United States Environmental Protection Agency
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Fidelity Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings(previously referred to as the Company's exploration and production segment)
FIP Funding improvement plan
GAAP Accounting principles generally accepted in the United States of America
Great Plains Great Plains Natural Gas Co., a public utility division of the Company prior to the closing of theHolding Company Reorganization and a public utility division of Montana-Dakota as of January 1,2019
Holding Company Reorganization The internal holding company reorganization completed on January 1, 2019, pursuant to theagreement and plan of merger, dated as of December 31, 2018, by and among Montana-Dakota,the Company and MDUR Newco Sub, which resulted in the Company becoming a holdingcompany and owning all of the outstanding capital stock of Montana-Dakota.
IBEW International Brotherhood of Electrical Workers
Intermountain Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
Knife River Knife River Corporation, a direct wholly owned subsidiary of Centennial
Knife River - Northwest Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River
K-Plan Company's 401(k) Retirement Plan
LWG Lower Willamette Group
MDU Construction Services MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial
MDU Energy Capital MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
MDUR Newco MDUR Newco, Inc., a public holding company created by implementing the Holding CompanyReorganization, now known as the Company
MDUR Newco Sub MDUR Newco Sub, Inc., a direct, wholly owned subsidiary of MDUR Newco, which was mergedwith and into Montana–Dakota in the Holding Company Reorganization
MEPP Multiemployer pension plan
MISO Midcontinent Independent System Operator, Inc.
Part II
112 MDU Resources Group, Inc. Form 10-K
MNPUC Minnesota Public Utilities Commission
Montana-Dakota Montana-Dakota Utilities Co. (formerly known as MDU Resources Group, Inc.), a public utilitydivision of the Company prior to the closing of the Holding Company Reorganization and a directwholly owned subsidiary of MDU Energy Capital as of January 1, 2019
MTPSC Montana Public Service Commission
MW Megawatt
NDPSC North Dakota Public Service Commission
Oil Includes crude oil and condensate
OPUC Oregon Public Utility Commission
Oregon DEQ Oregon State Department of Environmental Quality
PRP Potentially Responsible Party
ROD Record of Decision
RP Rehabilitation plan
SDPUC South Dakota Public Utilities Commission
SEC United States Securities and Exchange Commission
SSIP System Safety and Integrity Program
Stock Purchase Plan Company's Dividend Reinvestment and Direct Stock Purchase Plan which was terminatedeffective December 5, 2016
TCJA Tax Cuts and Jobs Act
Tesoro Tesoro Refining & Marketing Company LLC
VIE Variable interest entity
Washington DOE Washington State Department of Ecology
WBI Energy WBI Energy, Inc., a direct wholly owned subsidiary of WBI Holdings
WBI Energy Transmission WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Holdings WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
WUTC Washington Utilities and Transportation Commission
Wygen III 100-MW coal-fired electric generating facility near Gillette, Wyoming (25 percent ownership)
WYPSC Wyoming Public Service Commission
Part II
MDU Resources Group, Inc. Form 10-K 113
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Part II
114 MDU Resources Group, Inc. Form 10-K
Item 9A. Controls and Procedures
The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the
chief financial officer, along with any significant changes in internal controls of the Company.
Evaluation of Disclosure Controls and Procedures
The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. The Company's
disclosure controls and other procedures are designed to provide reasonable assurance that information required to be disclosed in the
reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms. The Company's disclosure controls and procedures include controls and procedures designed to
provide reasonable assurance that information required to be disclosed is accumulated and communicated to management, including the
Company's chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company's
management, with the participation of the Company's chief executive officer and chief financial officer, has evaluated the effectiveness of
the Company's disclosure controls and procedures. Based upon that evaluation, the chief executive officer and the chief financial officer
have concluded that, as of the end of the period covered by this report, such controls and procedures were effective at a reasonable
assurance level.
Changes in Internal Controls
No change in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act)
occurred during the three months ended December 31, 2018, that has materially affected, or is reasonably likely to materially affect, the
Company's internal control over financial reporting.
Management's Annual Report on Internal Control Over Financial Reporting
The information required by this item is included in this Form 10-K at Item 8 - Management's Report on Internal Control Over Financial
Reporting.
Attestation Report of the Registered Public Accounting Firm
The information required by this item is included in this Form 10-K at Item 8 - Report of Independent Registered Public Accounting Firm.
Item 9B. Other Information
None.
Part III
MDU Resources Group, Inc. Form 10-K 115
Item 10. Directors, Executive Officers and Corporate Governance
Information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.
Item 11. Executive Compensation
Information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Equity Compensation Plan Information
The following table includes information as of December 31, 2018, with respect to the Company's equity compensation plans:
Plan Category
(a)Number of securities tobe issued upon exerciseof outstanding options,warrants and rights
(b)Weighted averageexercise price ofoutstanding options,warrants and rights
(c)Number of securitiesremaining available forfuture issuance underequity compensationplans (excludingsecurities reflected incolumn (a))
Equity compensation plans approved by stockholders (1)691,629 (2)$—(3)4,357,330 (4)(5)
Equity compensation plans not approved by stockholders N/A N/A N/A
Total 691,629 $—4,357,330
(1)Consists of the Non-Employee Director Long-Term Incentive Compensation Plan and the Long-Term Performance-Based Incentive Plan.(2)Consists of performance shares and restricted stock awards.
(3)No weighted average exercise price is shown for the performance shares or restricted stock awards because such awards have no exercise price.
(4)This amount includes 4,041,479 shares available for future issuance under the Long-Term Performance-Based Incentive Plan in connection with grants ofrestricted stock, performance units, performance shares or other equity-based awards.
(5)This amount includes 315,851 shares available for future issuance under the Non-Employee Director Long-Term Incentive Compensation Plan.
The remaining information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by
reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
Information required by this item will be included in the Company's Proxy Statement, which is incorporated herein by reference.
Part IV
116 MDU Resources Group, Inc. Form 10-K
Item 15. Exhibits, Financial Statement Schedules
(a) Financial Statements, Financial Statement Schedules and Exhibits
Index to Financial Statements and Financial Statement Schedules
1. Financial Statements
The following consolidated financial statements required under this item areincluded under Item 8 - Financial Statements and Supplementary Data.Page
Consolidated Statements of Income for each of the three years in the period endedDecember 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .58
Consolidated Statements of Comprehensive Income for each of the three years inthe period ended December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59
Consolidated Balance Sheets at December 31, 2018 and 2017 . . . . . . . . . . . . . . .60
Consolidated Statements of Equity for each of the three years in the period endedDecember 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .61
Consolidated Statements of Cash Flows for each of the three years in the periodended December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .62
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . .63
2. Financial Statement Schedules
The following financial statement schedules are included in Part IV of this report.Page
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Statements of Income and Comprehensive Income for each of the threeyears in the period ended December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . .117
Condensed Balance Sheets at December 31, 2018 and 2017 . . . . . . . . . . . . . . . .118
Condensed Statements of Cash Flows for each of the three years in the period endedDecember 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .119
Notes to Condensed Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .119
Schedule II - Consolidated Valuation and Qualifying Accounts. . . . . . . . . . . . . . . . .120
MDU RESOURCES GROUP, INC.
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Statements of Income and Comprehensive Income
Years ended December 31,2018 2017 2016
(In thousands)
Operating revenues $628,331 $623,693 $561,266
Operating expenses 540,125 520,069 469,853
Operating income 88,206 103,624 91,413
Other income 1,504 4,876 2,282
Interest expense 32,761 31,997 31,519
Income before income taxes 56,949 76,503 62,176
Income taxes (4,259)13,800 6,355
Equity in earnings of subsidiaries from continuing operations 208,177 222,283 177,275
Net income from continuing operations 269,385 284,986 233,096
Equity in earnings (loss) of subsidiaries from discontinued operationsattributable to the Company 2,933 (3,783)(168,663)
Loss on redemption of preferred stocks —600 —
Dividends declared on preferred stocks —171 685
Earnings on common stock $272,318 $280,432 $63,748
Comprehensive income $279,269 $279,602 $65,848
The accompanying notes are an integral part of these condensed financial statements.
Part IV
MDU Resources Group, Inc. Form 10-K 117
MDU RESOURCES GROUP, INC.
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Balance Sheets
December 31,2018 2017
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents $2,271 $843
Receivables, net 92,724 83,453
Accounts receivable from subsidiaries 36,015 34,029
Inventories 13,293 13,864
Prepayments and other current assets 14,488 34,400
Total current assets 158,791 166,589
Investments 76,202 76,779
Investment in subsidiaries 1,790,886 1,704,908
Property, plant and equipment 2,846,715 2,631,161
Less accumulated depreciation, depletion and amortization 836,735 797,130
Net property, plant and equipment 2,009,980 1,834,031
Deferred charges and other assets:
Goodwill 4,812 4,812
Other 180,473 175,599
Total deferred charges and other assets 185,285 180,411
Total assets $4,221,144 $3,962,718
Liabilities and Stockholders' Equity
Current liabilities:
Long-term debt due within one year $200,711 $100,011
Accounts payable 50,051 47,000
Accounts payable to subsidiaries 12,438 7,234
Taxes payable 24,704 13,717
Dividends payable 39,695 38,573
Accrued compensation 14,346 20,017
Other accrued liabilities 54,099 36,881
Total current liabilities 396,044 263,433
Long-term debt 586,012 612,493
Deferred credits and other liabilities:
Deferred income taxes 165,122 147,847
Other 507,191 509,902
Total deferred credits and other liabilities 672,313 657,749
Commitments and contingencies
Stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value
Issued - 196,564,907 shares in 2018 and 195,843,297 shares in 2017 196,565 195,843
Other paid-in capital 1,248,576 1,233,412
Retained earnings 1,163,602 1,040,748
Accumulated other comprehensive loss (38,342)(37,334)
Treasury stock at cost - 538,921 shares (3,626)(3,626)
Total stockholders' equity 2,566,775 2,429,043
Total liabilities and stockholders' equity $4,221,144 $3,962,718
The accompanying notes are an integral part of these condensed financial statements.
Part IV
118 MDU Resources Group, Inc. Form 10-K
MDU RESOURCES GROUP, INC.
Schedule I - Condensed Financial Information of Registrant (Unconsolidated)
Condensed Statements of Cash Flows
Years ended December 31,2018 2017 2016
(In thousands)
Net cash provided by operating activities $294,379 $284,075 $238,125
Investing activities:
Capital expenditures (242,692)(146,370)(159,570)
Net proceeds from sale or disposition of property and other 5,032 (5,665)3,784
Investments in and advances to subsidiaries (40,000)(40,000)(5,000)
Advances from subsidiaries 70,000 40,000 15,000
Investments (528)(468)(129)
Net cash used in investing activities (208,188)(152,503)(145,915)
Financing activities:
Issuance of long-term debt 199,422 70,080 106,420
Repayment of long-term debt (125,961)(37,569)(50,010)
Payments of stock issuance costs (10)——
Dividends paid (154,573)(150,727)(147,156)
Redemption of preferred stock —(15,600)—
Repurchase of common stock (1,920)(564)—
Tax withholding on stock-based compensation (1,721)(508)(226)
Net cash used in financing activities (84,763)(134,888)(90,972)
Increase (decrease) in cash and cash equivalents 1,428 (3,316)1,238
Cash and cash equivalents - beginning of year 843 4,159 2,921
Cash and cash equivalents - end of year $2,271 $843 $4,159
The accompanying notes are an integral part of these condensed financial statements.
Part IV
MDU Resources Group, Inc. Form 10-K 119
Notes to Condensed Financial Statements
Note 1 - Summary of Significant Accounting Policies
Basis of presentation The condensed financial information reported in Schedule I is being presented to comply with Rule 12-04 of
Regulation S-X. The information is unconsolidated and is presented for the parent company only, which is comprised of MDU Resources
Group, Inc. (the Company) and Montana-Dakota and Great Plains, public utility divisions of the Company as of December 31, 2018, prior to
the Holding Company Reorganization. In Schedule I, investments in subsidiaries are presented under the equity method of accounting
where the assets and liabilities of the subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded on
the Condensed Balance Sheets. The income from subsidiaries is reported as equity in earnings of subsidiaries on the Condensed Statements
of Income. The consolidated financial statements of MDU Resources Group, Inc. reflect certain businesses as discontinued operations.
These statements should be read in conjunction with the consolidated financial statements and notes thereto of MDU Resources Group, Inc.
Earnings per common share Please refer to the Consolidated Statements of Income of the registrant for earnings per common share. In
addition, see Item 8 - Note 1 for information on the computation of earnings per common share.
Note 2 - Debt At December 31, 2018, the Company had long-term debt maturities, excluding unamortized debt issuance costs, of
$200.7 million in 2019, $700,000 in 2020, $700,000 in 2021, $700,000 in 2022, $49.2 million in 2023 and $536.7 million
scheduled to mature in years after 2023.
For more information on debt, see Item 8 - Note 8.
Note 3 - Dividends The Company depends on earnings and dividends from its subsidiaries to pay dividends on common stock. Cash dividends
paid to the Company by subsidiaries were $115.9 million, $116.1 million and $115.8 million for the years ended December 31, 2018,
2017 and 2016, respectively.
MDU RESOURCES GROUP, INC.
Schedule II - Consolidated Valuation and Qualifying Accounts
For the years ended December 31, 2018, 2017 and 2016
Additions
Description Balance atBeginning of Year Charged to Costsand Expenses Other *Deductions **Balance atEnd of Year
(In thousands)
Allowance for doubtful accounts:
2018 $8,069 $7,532 $1,121 $7,872 $8,850
2017 10,479 7,024 989 10,423 8,069
2016 9,835 8,302 851 8,509 10,479
*Recoveries.
**Uncollectible accounts written off.
All other schedules are omitted because of the absence of the conditions under which they are required, or because the information
required is included in the Company's Consolidated Financial Statements and Notes thereto.
Part IV
120 MDU Resources Group, Inc. Form 10-K
Item 16. Form 10-K Summary
None.
3. Exhibits
Incorporated by Reference
ExhibitNumber Exhibit Description FiledHerewith Form PeriodEnded Exhibit FilingDate File Number
2(a)Membership Interest Purchase Agreement, dated as ofJune 24, 2016, between WBI Energy, Inc. and TesoroRefining & Marketing Company LLC
8-K/A 2.1 7/21/16 1-03480
2(b)Purchase and Sale Agreement, dated as of June 9, 2016, byand among Calumet North Dakota, LLC, WBI Energy, Inc.,and as applicable, MDU Resources Group, Inc., CentennialEnergy Holdings, Inc., and Calumet Specialty ProductsPartners, L.P.
8-K/A 2.2 7/21/16 1-03480
2(c)Amendment No. 1 to Purchase and Sale Agreement, dated asof June 9, 2016, by and among Calumet North Dakota, LLC,WBI Energy, Inc., and as applicable, MDU Resources Group,Inc., Centennial Energy Holdings, Inc., and Calumet SpecialtyProducts Partners, L.P.
8-K/A 2.3 7/21/16 1-03480
2(d)Agreement and Plan of Merger, dated December 31, 2018, byand among MDU Resources Group, Inc., MDUR Newco, Inc.MDU Newco Sub, Inc.
8-K 2(a)1/2/19 1-03480
3(a)Certificate of Merger, dated December 31, 2018 8-K 3(a)1/2/19 1-03480
3(b)Amended and Restated Certificate of Incorporation of MDUResources Group, Inc.8-K 3(a)1/2/19 1-03480
3(c)Amended and Restated Bylaws of MDU Resources Group, Inc. 8-K 3.1 2/15/19 1-03480
4(a)Indenture, dated as of December 15, 2003, between MDUResources Group, Inc. and The Bank of New York, as trustee S-8 4(f)1/21/04 333-112035
4(b)First Supplemental Indenture, dated as of November 17,2009, between MDU Resources Group, Inc. and the Bank ofNew York Mellon, as trustee
10-K 12/31/09 4(c)2/17/10 1-03480
4(c)Centennial Energy Holdings, Inc. Amended and RestatedMaster Shelf Agreement, effective as of April 29, 2005,among Centennial Energy Holdings, Inc., the PrudentialInsurance Company of America and certain investorsdescribed therein
10-Q 6/30/05 4(a)8/3/05 1-03480
Incorporated by Reference
ExhibitNumber Exhibit Description FiledHerewith Form PeriodEnded Exhibit FilingDate File Number
4(d)Letter Amendment No. 1 to Amended and Restated MasterShelf Agreement, dated May 17, 2006, among CentennialEnergy Holdings, Inc., the Prudential Insurance Company ofAmerica, and certain investors described in the LetterAmendment
10-Q 6/30/06 4(a)8/4/06 1-03480
4(e)Letter Amendment No. 2 to Amended and Restated MasterShelf Agreement, dated December 19, 2007, amongCentennial Energy Holdings, Inc., the Prudential InsuranceCompany of America, and certain investors described in theLetter Amendment
10-K 12/31/15 4(e)2/19/16 1-03480
4(f)Letter Amendment No. 3 to Amended and Restated MasterShelf Agreement, dated December 18, 2015, amongCentennial Energy Holdings, Inc., the Prudential InsuranceCompany of America, and certain investors described in theLetter Amendment
10-K 12/31/15 4(f)2/19/16 1-03480
4(g)MDU Resources Group, Inc. Credit Agreement, dated May 26,2011, among MDU Resources Group, Inc., Various Lenders,and Wells Fargo Bank, National Association, as AdministrativeAgent
10-K 12/31/11 4(e)2/24/12 1-03480
4(h)First Amendment to Credit Agreement, dated October 4,2012, among MDU Resources Group, Inc., Various Lenders,and Wells Fargo Bank, National Association, as AdministrativeAgent
10-Q 9/30/12 4 11/7/12 1-03480
4(i)Second Amendment to Credit Agreement, dated May 8, 2014among MDU Resources Group Inc., Various Lenders, andWells Fargo Bank, National Association, as AdministrativeAgent
10-Q 6/30/14 4(a)8/8/14 1-03480
4(j)Third Amended and Restated Credit Agreement, dated May 8,2014, among Centennial Energy Holdings Inc., U.S. BankNational Association, as Administrative Agent, and TheSeveral Financial Institutions party thereto
10-Q 6/30/14 4(b)8/8/14 1-03480
4(k)Fourth Amended and Restated Credit Agreement, dated as ofSeptember 23, 2016, among Centennial Energy Holdings,Inc., U.S. Bank National Association, as Administrative Agent,and The Several Financial Institutions party thereto
10-Q 9/30/16 4 11/7/16 1-03480
4(l)First Amendment to the Fourth Amended and Restated CreditAgreement, dated as of October 26, 2018, among CentennialEnergy Holdings, Inc., U.S. Bank National Association, asAdministrative Agent, and The Several Financial Institutionsparty thereto
X 1-03480
4(m)MDU Energy Capital, LLC Master Shelf Agreement, dated asof August 9, 2007, among MDU Energy Capital, LLC,Prudential Investment Management, Inc., the PrudentialInsurance Company of America and the holders of the notesthereunder
8-K 4 8/16/07 1-03480
4(n)Amendment No. 1 to Master Shelf Agreement, datedOctober 1, 2008, among MDU Energy Capital, LLC,Prudential Investment Management, Inc., the PrudentialInsurance Company of America, and the holders of the notesthereunder
10-Q 9/30/08 4(b)11/5/08 1-03480
4(o)Indenture dated as of August 1, 1992, between CascadeNatural Gas Corporation and The Bank of New York relating toMedium-Term Notes, filed by Cascade Natural GasCorporation
8-K 4 8/12/92 1-07196
4(p)First Supplemental Indenture dated as of October 25, 1993,between Cascade Natural Gas Corporation and The Bank ofNew York relating to Medium-Term Notes and the 7.5% Notesdue November 15, 2031, filed by Cascade Natural GasCorporation
10-Q 6/30/93 4 1-07196
4(q)Second Supplemental Indenture, dated January 25, 2005,between Cascade Natural Gas Corporation and The Bank ofNew York, as trustee, filed by Cascade Natural GasCorporation
8-K 4.1 1/26/05 1-07196
Part IV
MDU Resources Group, Inc. Form 10-K 121
Incorporated by Reference
ExhibitNumber Exhibit Description FiledHerewith Form PeriodEnded Exhibit FilingDate File Number
4(r)Third Supplemental Indenture dated as of March 8, 2007,between Cascade Natural Gas Corporation and The Bank ofNew York Trust Company, N.A., as Successor Trustee, filed byCascade Natural Gas Corporation
8-K 4.1 3/8/07 1-07196
4(s)MDU Resources Group, Inc. Credit Agreement, dated June 8,2018, among MDU Resources Group, Inc, Various Lenders,and Wells Fargo Bank, National Association, as AdministrativeAgent
10-Q 6/30/18 4(a)8/3/18 1-03480
+10(a)MDU Resources Group, Inc. Supplemental Income SecurityPlan, as amended and restated May 10, 2017 10-Q 6/30/17 10(d)8/4/17 1-03480
+10(b)MDU Resource Group, Inc. Director Compensation Policy, asamended November 15, 2018 X 1-03480
+10(c)Deferred Compensation Plan for Directors, as amendedMay 15, 2008 10-Q 6/30/08 10(a)8/7/08 1-03480
+10(d)Non-Employee Director Stock Compensation Plan, asamended May 12, 2011 10-Q 6/30/11 10(a)8/5/11 1-03480
+10(e)MDU Resources Group, Inc. Non-Employee Director Long-Term Incentive Compensation Plan, as amended May 17,2012
10-Q 6/30/12 10(a)8/7/12 1-03480
+10(f)MDU Resources Group, Inc. Long-Term Performance-BasedIncentive Plan, as amended February 11, 2016 10-K 12/31/15 10(f)2/19/16 1-03480
+10(g)MDU Resources Group, Inc. Executive IncentiveCompensation Plan, as amended May 10, 2017, and Rulesand Regulations, as amended May 9, 2017
10-Q 6/30/17 10(b)8/4/17 1-03480
+10(h)Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amendedFebruary 10, 2016
8-K 10.3 2/18/16 1-03480
+10(i)Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amendedFebruary 16, 2017
8-K 10.1 2/21/17 1-03480
+10(j)Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amendedFebruary 14, 2018
8-K 10.1 2/21/18 1-03480
+10(k)Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amendedFebruary 14, 2019
X 1-03480
+10(l)Form of Annual Incentive Award Agreement under the Long-Term Performance-Based Incentive Plan, as amendedFebruary 10, 2016
8-K 10.2 2/18/16 1-03480
+10(m)Restricted Stock Unit Award Agreement under the Long-TermPerformance-Based Incentive Plan, as amended February 14,2018
8-K 10.3 2/21/18 1-03480
+10(n)Form of MDU Resources Group, Inc. IndemnificationAgreement for Section 16 Officers and Directors, datedMay 15, 2014
8-K 10.1 5/15/14 1-03480
+10(o)Form of Amendment No. 1 to Indemnification Agreement,dated May 15, 2014 8-K 10.2 5/15/14 1-03480
+10(p)MDU Resources Group, Inc. Section 16 Officers and Directorswith Indemnification Agreements Chart, as of October 10,2017
10-Q 9/30/17 10(b)11/3/17 1-03480
+10(q)MDU Resources Group, Inc. Nonqualified DefinedContribution Plan, as amended May 10, 2017 10-Q 6/30/17 10(c)8/4/17 1-03480
+10(r)MDU Resources Group, Inc. 401(k) Retirement Plan, asrestated January 1, 2017 10-Q 3/31/17 10(a)5/8/17 1-03480
+10(s)Instrument of Amendment to the MDU Resources Group, Inc.401(k) Retirement Plan, dated March 31, 2017 10-Q 3/31/17 10(b)5/8/17 1-03480
Part IV
122 MDU Resources Group, Inc. Form 10-K
+ Management contract, compensatory plan or arrangement.
MDU Resources Group, Inc. agrees to furnish to the SEC upon request any instrument with respect to long-term debt that MDU ResourcesGroup, Inc. has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
Incorporated by Reference
ExhibitNumber Exhibit Description FiledHerewith Form PeriodEnded Exhibit FilingDate File Number
+10(t)Instrument of Amendment to the MDU Resources Group, Inc.401(k) Retirement Plan, dated April 10, 2017 10-Q 6/30/17 10(e)8/4/17 1-03480
+10(u)Instrument of Amendment to the MDU Resources Group, Inc.401(k) Retirement Plan, dated August 30, 2017 10-Q 9/30/17 10(a)11/3/17 1-03480
+10(v)Employment Letter for Jeffrey S. Thiede, dated May 16, 2013 10-K 12/31/13 10(ab)2/21/14 1-03480
+10(w)Jason L. Vollmer Offer Letter, dated March 7, 2016 8-K 10.2 3/8/16 1-03480
+10(x)Jason L. Vollmer Offer Letter, dated September 20, 2017 8-K 10.1 9/21/17 1-03480
21 Subsidiaries of MDU Resources Group, Inc.X
23 Consent of Independent Registered Public Accounting Firm X
31(a)Certification of Chief Executive Officer filed pursuant toSection 302 of the Sarbanes-Oxley Act of 2002 X
31(b)Certification of Chief Financial Officer filed pursuant toSection 302 of the Sarbanes-Oxley Act of 2002 X
32 Certification of Chief Executive Officer and Chief FinancialOfficer furnished pursuant to 18 U.S.C. Section 1350, asadopted pursuant to Section 906 of the Sarbanes-Oxley Act of2002
X
95 Mine Safety Disclosures X
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Part IV
MDU Resources Group, Inc. Form 10-K 123
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
MDU Resources Group, Inc.
Date:February 22, 2019 By:/s/ David L. Goodin
David L. Goodin
(President and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf
of the registrant in the capacities and on the date indicated.
Signature Title Date
/s/ David L. Goodin Chief Executive Officer and Director February 22, 2019
David L. Goodin
(President and Chief Executive Officer)
/s/ Jason L. Vollmer Chief Financial Officer February 22, 2019
Jason L. Vollmer
(Vice President, Chief Financial Officer and Treasurer)
/s/ Stephanie A. Barth Chief Accounting Officer February 22, 2019
Stephanie A. Barth
(Vice President, Chief Accounting Officer and Controller)
/s/ Harry J. Pearce Director February 22, 2019
Harry J. Pearce
(Chair of the Board)
/s/ Thomas Everist Director February 22, 2019
Thomas Everist
/s/ Karen B. Fagg Director February 22, 2019
Karen B. Fagg
/s/ Mark A. Hellerstein Director February 22, 2019
Mark A. Hellerstein
/s/ Dennis W. Johnson Director February 22, 2019
Dennis W. Johnson
/s/ William E. McCracken Director February 22, 2019
William E. McCracken
/s/ Patricia L. Moss Director February 22, 2019
Patricia L. Moss
/s/ Edward A. Ryan Director February 22, 2019
Edward A. Ryan
/s/ David M. Sparby Director February 22, 2019
David M. Sparby
/s/ John K. Wilson Director February 22, 2019
John K. Wilson
Part IV
124 MDU Resources Group, Inc. Form 10-K
Proxy Statement
MDU Resources Group, Inc. Proxy Statement 19
The non-employee directors meet in executive session at each regularly scheduled quarterly board of directors meeting. The chair of the
board presides at the executive session of the non-employee directors held in connection with each regularly scheduled quarterly board of
directors meeting.
The board has standing audit, compensation, and nominating and governance committees. The table below provides current committee
membership.
Name Audit
Committee
Compensation
Committee
Nominating and
Governance Committee
Thomas Everist C
Karen B. Fagg C
Mark A. Hellerstein
Dennis W. Johnson C
William E. McCracken
Patricia L. Moss
Edward A. Ryan
David M. Sparby
John K. Wilson
C - Chair
- Member
Below is a description of each standing committee of the board. The board has affirmatively determined that each of these standing
committees consists entirely of independent directors pursuant to rules established by the NYSE, rules promulgated under the Securities
and Exchange Commission (SEC), and the director independence standards established by the board. The board has also determined that
each member of the audit committee and the compensation committee is independent under the criteria established by the NYSE and the
SEC for audit committee and compensation committee members, as applicable.
Nominating and Governance Committee Met Six Times in 2018
The nominating and governance committee met six times during 2018. The committee members are Karen B. Fagg, chair, Dennis W.
Johnson, William E. McCracken, Patricia L. Moss, and Edward A. Ryan.
The nominating and governance committee provides recommendations to the board with respect to:
•board organization, membership, and function;
•committee structure and membership;
•succession planning for our executive management and directors; and
•our corporate governance guidelines.
The nominating and governance committee assists the board in overseeing the management of risks in the committee’s areas of
responsibility.
The committee identifies individuals qualified to become directors and recommends to the board the nominees for director for the next
annual meeting of stockholders. The committee also identifies and recommends to the board individuals qualified to become our principal
officers and the nominees for membership on each board committee. The committee oversees the evaluation of the board and management.
In identifying nominees for director, the committee consults with board members, management, consultants, and other individuals likely to
possess an understanding of our business and knowledge concerning suitable director candidates.
Our corporate governance guidelines include our policy on consideration of director candidates recommended to us. We will consider
candidates that our stockholders recommend in the same manner we consider other nominees. Stockholders who wish to recommend a
director candidate may submit recommendations, along with the information set forth in the guidelines, to the nominating and governance
committee chair in care of the secretary at MDU Resources Group, Inc., P.O. Box 5650, Bismarck, ND 58506-5650.
Proxy Statement
20 MDU Resources Group, Inc. Proxy Statement
Stockholders who wish to nominate persons for election to our board at an annual meeting of stockholders must follow the applicable
procedures set forth in Section 2.08 or 2.10 of our bylaws. Our bylaws are available on our website. See “Stockholder Proposals, Director
Nominations, and Other Items of Business for 2020 Annual Meeting” in the section entitled “Information about the Annual Meeting” for
further details.
In evaluating director candidates, the committee, in accordance with our corporate governance guidelines, considers an individual’s:
•background, character, and experience, including experience relative to our company’s lines of business;
•skills and experience which complement the skills and experience of current board members;
•success in the individual’s chosen field of endeavor;
•skill in the areas of accounting and financial management, banking, business management, human resources, marketing, operations,
public affairs, law, technology, risk management, governance, and operations abroad;
•background in publicly traded companies including service on other public company boards of directors;
•geographic area of residence;
•diversity of business and professional experience, skills, gender, and ethnic background, as appropriate in light of the current composition
and needs of the board;
•independence, including any affiliation or relationship with other groups, organizations, or entities; and
•compliance with applicable law and applicable corporate governance, code of conduct and ethics, conflict of interest, corporate
opportunities, confidentiality, stock ownership and trading policies, and other policies and guidelines of the company.
In addition, our bylaws contain requirements that a person must meet to qualify for service as a director.
The nominating and governance committee assesses the effectiveness of this policy annually in connection with the nomination of directors
for election at the annual meeting of stockholders. The composition of the current board and the board nominees reflects diversity in
business and professional experience, skills, ethnicity, gender, and geography.
Audit Committee Met Eight Times in 2018
The audit committee is a separately-designated committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange
Act of 1934.
The audit committee met eight times during 2018. The audit committee members are Dennis W. Johnson, chair, Mark A. Hellerstein,
Edward A. Ryan, David M. Sparby, and John K. Wilson. The board of directors has determined that Messrs. Johnson, Hellerstein, Sparby,
and Wilson are “audit committee financial experts” as defined by SEC rules and all audit committee members are financially literate within
the meaning of the listing standards of the NYSE. All members also meet the independence standard for audit committee members under
our director independence guidelines, the NYSE listing standards, and SEC rules.
The audit committee assists the board of directors in fulfilling its oversight responsibilities to the stockholders and serves as a
communication link among the board, management, the independent registered public accounting firm, and the internal auditors. The audit
committee:
•assists the board’s oversight of
the integrity of our financial statements and system of internal controls;
the company’s compliance with legal and regulatory requirements and the code of conduct;
the independent registered public accounting firm’s qualifications and independence;
the performance of our internal audit function and independent registered public accounting firm;
management of risk in the audit committee’s areas of responsibility; and
•arranges for the preparation of and approves the report that SEC rules require we include in our annual proxy statement. See the section
entitled “Audit Committee Report” for further information.
Proxy Statement
MDU Resources Group, Inc. Proxy Statement 21
Compensation Committee Met Four Times in 2018
During 2018, the compensation committee met four times. The compensation committee consists entirely of independent directors within
the meaning of the company’s corporate governance guidelines and the NYSE listing standards and who meet the definitions of non-
employee directors for purposes of Rule 16-b under the Exchange Act. Members of the compensation committee are Thomas Everist, chair,
Karen B. Fagg, William E. McCracken, and Patricia L. Moss.
The compensation committee assists the board of directors in fulfilling its responsibilities relating to the company’s compensation policy
and programs. It has the direct responsibility for determining compensation for our Section 16 officers and for overseeing the company’s
management of risk in its areas of responsibility. In addition, the compensation committee reviews and recommends any changes to director
compensation policies to the board of directors. The authority and responsibility of the compensation committee is outlined in the
compensation committee’s charter.
The compensation committee uses the analysis and recommendations from outside consultants, the chief executive officer, and the human
resources department in making its compensation decisions. The chief executive officer, the vice president-human resources, and the
general counsel regularly attend compensation committee meetings. The committee meets in executive session as needed. The processes
and procedures for consideration and determination of compensation of the Section 16 officers, as well as the role of our executive officers,
are discussed in the “Compensation Discussion and Analysis.”
The compensation committee has sole authority to retain compensation consultants, legal counsel, or other advisers to assist in
consideration of the compensation of the chief executive officer, the other Section 16 officers, and the board of directors, and the
committee is directly responsible for the appointment, compensation, and oversight of the work of such advisers. The compensation
committee’s practice has been to retain a compensation consultant every other year to conduct a competitive analysis on executive
compensation. The competitive analysis is conducted internally by the human resources department in the other years. In 2018, the
compensation committee retained a compensation consultant, Meridian Compensation Partners, LLC, to conduct a competitive analysis on
executive compensation for 2019. Prior to retaining an adviser, the compensation committee considers all factors relevant to ensure the
adviser’s independence from management. Annually the compensation committee conducts a potential conflicts of interest assessment
raised by the work of any compensation consultant and how such conflicts, if any, should be addressed. The compensation committee
requested and received information from Meridian Compensation Partners, LLC to assist in its potential conflicts of interest assessment.
Based on its review and analysis, the compensation committee determined in 2018 that Meridian Compensation Partners, LLC was
independent from management.
The board of directors determines compensation for our non-employee directors based upon recommendations from the compensation
committee. The compensation committee’s practice has been to retain a compensation consultant every other year to conduct a competitive
analysis on director compensation. In 2018, the analysis of non-employee director compensation was performed by the human resources
department. Meridian Compensation Partners, LLC will conduct the analysis in 2019.
Compensation Policies and Practices as They Relate to Risk Management
The human resources department has conducted an assessment of the risks arising from our compensation policies and practices for all
employees and concluded that none of these risks is reasonably likely to have a material adverse effect on the company. Based on the
human resources department’s assessment and taking into account information received from the risk identification process, senior
management and our management policy committee concluded that risks arising from our compensation policies and practices are not
reasonably likely to have a material adverse effect on the company. After review and discussion with senior management, the compensation
committee concurred with this assessment.
As part of its assessment of the risks arising from our compensation policies and practices, the human resources department identified the
principal areas of risk faced by the company that may be affected by our compensation policies and practices, including any risks resulting
from our operating businesses’ compensation policies and practices. In assessing the risks arising from our compensation policies and
practices, the human resources department identified the following practices designed to prevent excessive risk taking:
•Business management and governance practices:
risk management is a specific performance competency included in the annual performance assessment of Section 16 officers;
board oversight on capital expenditure and operating plans promotes careful consideration of financial assumptions;
Corporate Headquarters
MDU Resources Group, Inc.
Street Address: 1200 W. Century Ave.
Bismarck, ND 58503
Mailing Address: P.O. Box 5650
Bismarck, ND 58506-5650
Telephone: [phone]
Toll-Free Telephone: [phone]
www.mdu.com
The company has filed as exhibits to its Annual Report on Form
10-K the CEO and CFO certifications as required by Section 302
of the Sarbanes-Oxley Act.
The company also submitted the required annual CEO
certification to the New York Stock Exchange.
Common Stock
MDU Resources’ common stock is listed on the NYSE under the
symbol MDU. The stock began trading on the NYSE in 1948 and
is included in the Standard & Poor’s MidCap 400 index. Average
daily trading volume in 2018 was 827,903 shares.
Common Stock Prices High Low Close
2018
First Quarter $28.23 $24.29 $28.16
Second Quarter 29.28 27.05 28.68
Third Quarter 29.62 25.33 25.69
Fourth Quarter 26.96 22.73 23.84
2017
First Quarter $29.74 $25.83 $27.37
Second Quarter 27.89 25.58 26.20
Third Quarter 27.73 25.14 25.95
Fourth Quarter 28.22 25.89 26.88
Shareowner Service Plus Plan
The Shareowner Service Plus Plan provides interested investors the
opportunity to purchase shares of MDU Resources’ common stock
and to reinvest all or a percentage of dividends without incurring
brokerage commissions or service charges. The plan is sponsored
and administered by Equiniti Trust Company, transfer agent and
registrar for MDU Resources. For more information, contact
Equiniti Trust Company at 877-536-3553 or visit www.
shareowneronline.com.
2019 Key Dividend Dates
Ex-Dividend Date Record Date Payment Date
First Quarter March 13 March 14 April 1
Second Quarter June 12 June 13 July 1
Third Quarter September 11 September 12 October 1
Fourth Quarter December 11 December 12 January 1, 2020
Key dividend dates are subject to the discretion of the Board of Directors.
Annual Meeting
11 a.m. CDT May 7, 2019
Montana-Dakota Utilities Co. Service Center
909 Airport Road
Bismarck, North Dakota
Shareholder Information and Inquiries
Registered shareholders have electronic access to their accounts by
visiting www.shareowneronline.com. Shareowner Online allows
shareholders to view their account balance, dividend information,
reinvestment details and more. The stock transfer agent maintains
stockholder account information.
Communications regarding stock transfer requirements, lost
certificates, dividends or change of address should be directed to
the stock transfer agent.
Company information, including financial reports, is available at
www.mdu.com.
Shareholder Contact
Dustin J. Senger
Telephone: [phone]
Email: [e-mail]
Analyst Contact
Jason L. Vollmer
Telephone: [phone]
Email: [e-mail]
Transfer Agent and Registrar for All Classes of Stock
Equiniti Trust Company
Stock Transfer Department
P.O. Box 64874
St. Paul, MN 55164-0874
Telephone: [phone]
Toll-Free Telephone: [phone]
www.shareowneronline.com
Independent Registered Public Accounting Firm
Deloitte & Touche LLP
50 S. Sixth St., Suite 2800
Minneapolis, MN 55402-1538
Note: This information is not given in connection with any sale or
offer for sale or offer to buy any security.
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The paper used in this annual report is
certified by the Forest Stewardship Council®
and contains a minimum of 10 percent
post-consumer recycled paper fibers.
Stockholder Information