BLACK HILLS CORPORATION Items 7 and 7A Index
Executive Summary 42 Prospective Information 46 Results of Operations - Consolidated Summary and Overview of Business Segments 47 Non-GAAP Measure 50Electric Utilities 51Gas Utilities 52 Power Generation 54 Mining 55 Corporate 56
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)
56
Liquidity and Capital Resources 57
Debt, Equity and Liquidity 59
Cash Flow Activities 62
Capital Expenditures 64
Credit Ratings 64
Contractual Obligations and Off-Balance Sheet Items 66
Critical Accounting Estimates 67
Market Risk Disclosures 70
New Accounting Pronouncements 71
Executive Summary
We are a customer-focused, growth-oriented electric and natural gas utility
company with a mission of improving life with energy and a vision to be the
energy partner of choice. The Company provides electricity and natural gas
through its Electric and Gas Utilities to 1.3 million customers in 824
communities in eight states, including Arkansas , Colorado , Iowa , Kansas ,
Montana , Nebraska , South Dakota and Wyoming . The Company conducts its utility
operations under the name Black Hills Energy predominantly in rural areas of the
Rocky Mountains and Midwestern states. The Company's Electric Utilities are
supported by our Power Generation and Mining segments. The Power Generation
segment produces electric power from its five generating facilities and sells
most of the electric capacity and energy to our Electric Utilities under
long-term contracts. Our Mining segment produces coal at our only location near
Gillette, Wyoming , and sells nearly all production to fuel the on-site,
mine-mouth power generation facilities.
The Company has provided energy and served customers for 136 years, since the
1883 gold rush days in Deadwood, South Dakota . Throughout our history, the
common thread that unites the past to the present is our commitment to serve our
customers and communities. Our strategic focus has not changed in over a century
- serving customers with affordable, reliable and safe energy. Our strategy
today continues that emphasis on serving customers, but with a renewed focus on
better engaging with the people and communities we serve. Customer expectations
are rapidly changing with the advancement of technology and customers are
demanding simpler, faster and more convenient solutions to their energy needs.
We are Ready to serve as we have done for the past 136 years.
Our strategy consists of five primary areas that focus on improving the way we
serve customers with safe, reliable and affordable energy while improving the
lives of the customers and communities we serve. The strategy is to 1) become
the safest energy company in the utility industry; 2) transform the customer
experience; 3) grow our electric and natural gas customer load; 4) pursue
operating efficiencies; and 5) modernize utility infrastructure. This strategic
focus will present the company with significant investment needs as we modernize
our infrastructure systems and meet customer growth. It will also allow us to
better understand our customer and community needs while providing more
intuitive and cost-effective interactions.
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Key Elements of our Business Strategy
Modernize, replace and operate utility infrastructure to meet our customers'
energy needs while providing safe, reliable and affordable energy. Our utilities
own and operate large electric and natural gas infrastructure systems that span
nearly 1,600 miles. Our Electric Utilities own and operate 939 MW of generation
capacity and 8,900 miles of transmission and distribution lines and our Gas
Utilities own and operate 46,000 miles of natural gas transmission and
distribution pipelines. A key strategic focus is to modernize this utility
infrastructure to meet customers' and communities' varied energy needs and to
ensure the continued delivery of safe, reliable and affordable energy. In
addition, we need to invest in the accessibility, capacity and integrity of our
systems to meet customer growth.
We rigorously comply with all applicable federal, state and local regulations
and strive to consistently meet industry best practice standards. A key
component of our modernization effort is the development of programs by our
Electric and Gas utilities to systematically and proactively replace aging
infrastructure on a system-wide basis. To meet our electric customers' continued
expectations of high levels of reliability, our Electric Utilities utilize a
distribution integrity program to ensure the timely repair and replacement of
aging infrastructure. Our Gas Utilities utilize a programmatic approach to
system-wide pipeline system replacement, particularly in high consequence areas.
Under the programmatic approach, obsolete, at-risk and vintage materials are
replaced in a proactive and systematic time frame. We have removed all cast- and
wrought-iron from our natural gas transmission and distribution systems and
continue to replace aging infrastructure through programs that prioritize safety
and reliability for our customers. Many of our Gas Utilities are authorized to
use system safety, integrity and replacement cost recovery mechanisms that
provide for customer rate adjustments which reflect the cost incurred in
repairing and replacing the gas delivery systems.
We estimate our five-year capital investment to be approximately $2.7 billion ,
with most of that investment targeted toward upgrading existing utility
infrastructure and to support customer and community growth needs. Our actual
2019 and forecasted capital expenditures and depreciation for next five years
from 2020 through 2024 are as follows (in
millions):[[Image Removed: chart-a069200ae3409a0e969a04.jpg]]
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Actual Planned Planned Planned Planned Planned
Capital Expenditures By Segment 2019 2020 2021 2022 2023 2024
(in millions)
Electric Utilities $ 223 $ 246 $ 203 $ 170 $ 137 $ 152
Gas Utilities 512 391 309 285 316 293
Power Generation 85 7 9 11 6 6
Mining 9 8 12 9 9 9
Corporate and Other 21 17 22 11 12 10
Total $ 850 $ 669 $ 555 $ 486 $ 480 $ 470
Efficiently plan, construct and operate rate base power generation facilities to
serve our Electric Utilities . We believe that we best serve customers and
communities with a vertically integrated business model for our Electric
Utilities . This business model remains a core strength and strategy today as we
invest in and operate efficient power generation resources to cost-effectively
supply electricity to our customers. We strive to provide power at reasonable
rates to our customers and earn competitive returns for our investors.
Our power production strategy focuses on low-cost construction and efficient
operation of our generating facilities. Our low power production costs result
from a variety of factors including low fuel costs, efficiency in converting
fuel into energy, low per unit operating and maintenance costs and high levels
of power plant availability. For our coal-fired power plants, we leverage our
mine-mouth location advantage to eliminate coal transportation costs that often
represent the largest component of the delivered cost of coal for many other
utilities. Additionally, we operate our plants with high levels of availability
as compared to industry benchmarks.
We continue to believe that ownership of power generation facilities by our
• When generating assets are included in the utility rate base and reviewed
and approved by government authorities, customer rates are more stable and
predictable, and typically less expensive in the long run; especially when
compared to power otherwise purchased from the open market through
wholesale contracts that are periodically re-priced to reflect current and
varying market conditions;
• Regulators participate in a planning process where long-term investments
are designed to match long-term energy demand;
• The lower-risk profile of rate-based generation assets contributes to
stronger credit ratings which, in turn, can benefit both customers and
investors by lowering the cost of capital; and
• Investors are provided a long-term, reasonable, stable return on their
investment.
Proactively integrate alternative and renewable energy into our utility energy
supply while mitigating customer rate impacts. Some of our customers,
particularly our larger customers, are demanding more renewable and cleaner
sources of energy to meet their sustainability goals. In addition, there is more
interest from voters, regulators and legislators to increase the use of
renewable and other alternative energy sources. To support this interest, we
have created and received approvals for new, voluntary renewable energy tariffs
to serve certain commercial, industrial and governmental agency customer
requests for renewable energy resources in South Dakota and Wyoming . To meet the
renewable energy commitments under the new tariffs, we also received approval
from the Wyoming Public Service Commission to build the Corriedale wind project,
a 52.5 MW wind farm to be constructed near Cheyenne, Wyoming . The $79 million
project is expected to be in service by year-end 2020. Supporting our renewable
energy efforts in Colorado , in November 2019 , we successfully commissioned Busch
Ranch II, a 60 MW wind farm near Pueblo, Colorado , to provide renewable energy
to our Colorado Electric utility.
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To date, many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. In addition, some states have either enacted or are considering legislation setting GHG emissions reduction targets. Federal legislation for both renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely drive the need for significant investment in ourElectric Utilities andGas Utilities segments. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility we are responsible for providing safe, reliable and affordable sources of energy to our customers. Accordingly, we employ a customer-focused strategy for complying with standards and regulations that balances our customers' rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers. Build and maintain strong relationships with wholesale power customers of our utilities and our power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be an important provider of electricity to wholesale utility customers, who will continue to need products such as capacity and energy to reliably serve their customers. By providing these products under long-term contracts, we help our customers meet their energy needs. We also earn more stable revenues and greater returns for shareholders over the long-term than we would by selling energy into more volatile energy spot markets. In addition, relationships that we have established with wholesale power customers have developed into other opportunities. MEAN, MDU and theCity of Gillette, Wyoming were wholesale power customers that are now joint minority owners in two of our power plants, Wygen I and Wygen III, reducing risk and providing steady revenues. Vertically integrate businesses that are supportive of our Electric and Gas utility businesses. While our primary focus is on growing our core utilities, we selectively invest in vertically integrated businesses that provide cost effective and efficient fuel and energy to our utilities. We currently own and operate power generation and mining assets that are vertically integrated into and supportive of ourElectric Utilities . These operations are located at our utility-generating complexes and are physically integrated into our Electric Utility operations. The Power Generation segment currently owns five power facilities, four of which are contracted with our affiliateElectric Utilities under long-term power purchase agreements. Our Power Generation segment has an experienced staff with significant expertise in planning, building and operating power plants. The power generation team has constructed 20 coal-fired, gas-fired and renewable generation projects since 1995 with aggregate project costs in excess of$2.1 billion . This team also provides shared services to ourElectric Utilities' generation facilities, resulting in efficient management of all of the company's generation assets. In certain states, ourElectric Utilities are required to competitively bid for generation resources needed to serve customers. Generally, our Power Generation segment submits bids in response to those competitive solicitations. Our Power Generation segment can often realize competitive advantages provided by prior construction expertise, fuel supply advantages and by co-locating new plants at existing sites, reducing infrastructure and operating costs. Our surface coal mine is located immediately adjacent to ourGillette energy complex in northeasternWyoming , where all five of our coal-fired power plants are located. We operate and own majority interests in four of our five power plants. We own 20% of the fifth power plant which is operated by a majority owner. The mine provides low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. On average, the fuel can be delivered to the adjacent power plants at less than$1.00 per MMBtu, providing very cost competitive fuel to our power plants when compared to other coal-fired and gas-fired power plants. Nearly all of the mine's production is sold to the five on-site, mine-mouth generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus contracts with affiliates. A small portion of the mine's production is sold to off-site industrial customers and delivered by truck. Expand utility operations through selective acquisitions of electric and gas utilities. The electric and natural gas utility industries have consolidated significantly over the past two decades and continue to consolidate. We have successfully acquired and integrated numerous utility systems since 2005, including two large, transformational acquisitions - the Aquila Transaction in 2008 and SourceGas Transaction in 2016. Through these acquisitions, we developed a scalable platform that simplifies the rapid integration of acquired utilities, providing significant benefits to both customers and shareholders. The company targets small to large utilities, including municipal and private utility systems, located primarily in geographies that are near to or contiguous with our existing utility service territories and can provide long-term value for both customers and shareholders. In the near-term, we do not expect to pursue large utility acquisitions, particularly given the high valuation multiples realized in recent utility transactions. As pipeline regulations continue to increase, we believe there will be more opportunities to purchase these smaller and more rural utility systems. 45
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Grow our dividend. We are extremely proud of our track record of annual dividend increases for shareholders. InJanuary 2020 , our Board of Directors declared a quarterly dividend of$0.535 per share, equivalent to an annual dividend of$2.14 per share. This current annual equivalent rate of$2.14 per share, if declared and paid in 2020, will represent 50 consecutive years of annual dividend increases. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%. Maintain an investment grade credit rating and ready access to debt and equity capital markets. We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and earnings accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining our investment-grade issuer credit rating. Prospective Information We expect to generate long-term growth through the expansion of integrated utilities and supporting operations. Sustained growth requires continued capital deployment. Our integrated energy portfolio, focused predominately on regulated utilities, provides growth opportunities, yet avoids concentrating business risk. We expect much of our growth in the next few years will come from the need for capital deployment at our utilities and continued focus on improving efficiencies and controlling costs. Although dependent on market conditions, we are confident in our ability to obtain additional financing, as necessary, to continue our growth plans. We remain focused on prudently managing our operations and maintaining our overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plan. Prospective information for our operating segments should be read in conjunction with our business strategy discussed above, and our 2019 company highlights discussed below. 46
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Our discussion and analysis for the year endedDecember 31, 2019 compared to 2018, as well as discussion and analysis of the results of operations for the year endedDecember 31, 2018 compared to 2017 given segment reporting changes adopted by the Company in 2019, is included herein. For further discussion and analysis that remains unchanged for the year endedDecember 31, 2018 compared to 2017, please refer to Item 7 of Part II, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year endedDecember 31, 2018 , which was filed with theSEC onFebruary 19, 2019 .
Segment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.
Results of OperationsConsolidated Summary and Overview
For the Years Ended
2019 2018 2017
(in millions, except per diluted share
amounts) Income EPS Income EPS Income EPS
Net income from continuing operations available for common stock$ 199.3 $ 3.28 $ 265.3 $ 4.78 $ 194.1 $ 3.52 Net (loss) from discontinued operations - - (6.9 ) (0.12 ) (17.1 ) (0.31 ) Net income available for common stock$ 199.3 $ 3.28 $ 258.4 $ 4.66 $ 177.0 $ 3.21 2019 Compared to 2018
The variance to the prior year included the following:
•
to reduced purchased power capacity costs, increased rider revenues and
the prior year Wyoming Electric PCA settlement partially offset by higher
operating expenses driven by outside services and employee costs;
•
due to new customer rates and rider revenues, customer growth and
increased transport and transmission driven by increased volumes from new
and existing customers partially offset by higher operating expenses
driven by outside services and employee costs;
• Power Generation's adjusted operating income increased
primarily due to higher revenue from increased wind MWh sold and higher
PPA pricing partially offset by higher depreciation and property taxes
from new wind assets;
• Mining's adjusted operating income decreased
lower tons sold driven by planned and unplanned generating facility
outages partially offset by lower operating expenses;
• Corporate and Other expenses decreased
year expenses related to the oil and gas segment that were not
reclassified to discontinued operations;
• A
equity securities of a privately held oil and gas company;
• We expensed $5.4 million of development costs related to projects we no
longer intend to construct; and
• Increased tax expense of $53 million primarily due to a prior year $73 million tax benefit resulting from legal entity restructuring partially
offset by a prior year $4.0 million income tax expense associated with
changes in the previously estimated impact of tax reform on deferred
income taxes and current year $5.9 million federal PTCs and related state
ITCs associated with new wind assets.
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The variance when comparing 2018 to 2017 included the following:
•
to TCJA benefits delivered to customers, the Wyoming Electric PCA
settlement and higher operating expenses partially offset by increased
rider revenues and favorable weather;
•
due to colder winter weather, new customer rates, customer growth and
increased transport and transmission offset by TCJA benefits delivered to
customers and higher operating expenses;
• Power Generation's adjusted operating income decreased
primarily due to a decrease in MWh sold and higher operating expenses;
• Mining's adjusted operating income increased
increase in price per ton sold and lower operating expenses;
• Corporate and Other expenses decreased
year acquisition costs; and
• Increased tax benefit of
benefit resulting from legal entity restructuring and a reduction in the
federal corporate income tax rate from 35% to 21% from the TCJA, effective
January 1, 2018 .
The following table summarizes select financial results by operating segment and details significant items (in thousands):
For the Years Ended December 31,
2019 Variance 2018 Variance 2017
(in thousands)
Revenue
Revenue $ 1,885,669 $ (11,573 ) $ 1,897,242 $ 83,721 $ 1,813,521
Intercompany eliminations (150,769 ) (7,795 ) (142,974 ) (9,719 ) (133,255 )
$ 1,734,900 $ (19,368 ) $ 1,754,268 $ 74,002 $ 1,680,266
Adjusted operating income (a)
Electric Utilities $ 160,297 $ 4,428 $ 155,869 $ (21,868 ) $ 177,737
Gas Utilities 189,971 4,732 185,239 134 185,105
Power Generation 44,779 2,165 42,614 (4,076 ) 46,690
Mining 12,627 (3,713 ) 16,340 2,840 13,500
Corporate and Other (1,632 ) 1,393 (3,025 ) 3,271 (6,296 )
406,042 9,005 397,037 (19,699 ) 416,736
Interest expense, net (137,659 ) 2,316 (139,975 ) (2,873 ) (137,102 ) Impairment of investment (19,741 ) (19,741 ) - - - Other income (expense), net (5,740 ) (4,560 ) (1,180 ) (3,288 ) 2,108 Income tax benefit (expense) (29,580 ) (53,247 ) 23,667 97,034 (73,367 ) Income from continuing operations 213,322 (66,227 ) 279,549 71,174 208,375 (Loss) from discontinued operations, net of tax - 6,887 (6,887 ) 10,212 (17,099 ) Net income 213,322 (59,340 ) 272,662 81,386 191,276 Net income attributable to noncontrolling interest (14,012 ) 208 (14,220 ) 22 (14,242 ) Net income available for common stock$ 199,310 $ (59,132 ) $ 258,442 $ 81,408 $ 177,034 _____________
(a) In 2019, we changed our measure of segment performance to adjusted operating
income, which impacted our segment disclosures for all periods presented. See
Note 5 of the Notes to the Consolidated Financial Statements in this
Annual Report on Form 10-K for more information.
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2019 Overview of Business Segments and Corporate Activity
• On
its Renewable Advantage program, to potentially add up to 200 MW of
renewable energy to its southern
solicitation process for the addition of cost-effective, utility-scale
renewable energy projects includes wind, solar and battery storage to
supplement existing natural gas and wind generation power supplies Bidders
have until
by an independent evaluator overseen by the CPUC. Based on the outcome of
the bidding process, projects would be placed in service no later than
2023.
• In July 2019 , South Dakota Electric and Wyoming Electric received
approvals for the Renewable Ready program and related jointly-filed CPCN
to construct
electric utilities to deliver renewable energy for large commercial,
industrial and governmental agency customers. In
under the program by 12.5 MW. The two electric utilities also received a
determination from the WPSC to increase the project to 52.5 MW. The $79
million project is expected to be in service by year-end 2020.
• On
final 94-mile segment of a 175-mile electric transmission line from Rapid
City, South Dakota , to Stegall, Nebraska . The first 48-mile segment was
placed in service on July 25, 2018 , and the second 33-mile segment was
placed in service on November 20, 2018 .
•
• OnJuly 19, 2019 ,Colorado Electric set a new all-time and summer peak load of 422 MW, exceeding the previous peak of 413 MW set inJune 2018 . •Wyoming Electric set a new all-time and summer peak load, and also set a
new winter peak load:
• OnJuly 19, 2019 ,Wyoming Electric set a new all-time and summer peak load of 265 MW, exceeding the previous peak of 254 MW set inJuly 2018 . • OnDecember 16, 2019 ,Wyoming Electric set a new winter peak load of 247 MW, exceeding the previous peak of 238 MW set inDecember 2018 . • Cooling degree days for the year endedDecember 31, 2019 were 14% higher
than the normal compared to 29% higher than normal in 2018.
• Heating degree days for the year ended
than normal compared to 3% higher than normal in 2018.
•
States of
• OnDecember 11, 2019 ,Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its four
existing gas
distribution territories. A new, single statewide ratestructure
will be effective March 1, 2020 . New rates are expected to generate
$13 million in new revenue based on a return on equity of
9.40% and
a capital structure of 50.23% equity and 49.77% debt. The approval
also allows for a rider to recover integrity investments for system
safety and reliability.
• On February 1, 2019 , Colorado Gas submitted a rate reviewwith the
CPUC to consolidate rates, tariffs and services of its two existing
gas distribution territories. The rate review requested $2.5 million
in new revenue to recover investments in safety, reliability and
system integrity. Colorado Gas also requested a new rider mechanism
to recover future safety and integrity investments in its system. On
December 27, 2019 , the ALJ issued a recommended decision
denying the
company's plan to consolidate rate territories and recommending a
rate decrease. Colorado Gas has filed exceptions to the ALJ's
recommended decision. A decision by the CPUC is expected by the end
of March 2020 . Legal consolidation was previously approved by the
CPUC in late 2018 and completed in early 2019.
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• OnOctober 29, 2019 ,Nebraska Gas received approval from the
NPSC to
merge its two natural gas distribution companies. Legal
consolidation was effective January 1, 2020 , and a rate review is
expected to be filed by mid-year 2020 to consolidate the rates,
tariffs and services.
• On
35-mile
delivery capacity for customers in central
pipeline interconnects from a supply point near
facilities near
the Wyoming Gas rate review completed in December 2019 .
• Heating degree days at the
2019 were 5% higher than normal compared to 2% higher than normal in 2018.
Power Generation
• On
Busch Ranch II. Through a competitive bidding process, Black Hills
Electric Generation was selected to deliver renewable energy under a
25-year PPA to Colorado Electric .
• On
a request with FERC for approval of a new 60 MW PPA. The agreement would
fulfill the capacity need for Wyoming Electric at the expiration of the
current agreement on
will continue to deliver 60 MW of energy to
Wygen I power plant starting
On December 23, 2019 , the Company filed a response to questions from the
FERC and awaits a decision from FERC .
Mining
• In
contract with the Wyodak power plant. Effective
price was reset at
the prior contract price of
Corporate and Other
• On
senior unsecured notes. Proceeds were used to repay the
Corporate term loan due
senior notes due July 15, 2020 and repay a portion of short-term debt.
• During the year ended December 31, 2019 , we issued a total of 1.3 million
shares of common stock for net proceeds of $99 million under our ATM
equity offering program.
• On June 17, 2019 , we amended our Corporate term loan due July 30, 2020 .
This amendment increased total commitments to $400 million from $300
million and extended the term through June 17, 2021 on substantially
similar terms and covenants. The net proceeds were used to pay down
short-term debt. Proceeds from the October 3, 2019 debt transaction were
used to repay this term loan.
Operating Results
A discussion of operating results from our business segments follows.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance
with GAAP, as well as another financial measure, gross margin, that is
considered a "non-GAAP financial measure." Generally, a non-GAAP financial
measure is a numerical measure of a company's financial performance, financial
position or cash flows that excludes (or includes) amounts that are included in
(or excluded from) the most directly comparable measure calculated and presented
in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP
financial measure due to the exclusion of depreciation and amortization from the
measure. The presentation of gross margin is intended to supplement investors'
understanding of our operating performance.
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Gross margin for ourElectric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for ourGas Utilities is calculated as operating revenues less cost of gas sold. Our gross margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers. Our gross margin measure may not be comparable to other companies' gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
Operating results for the years ended
2019 Variance 2018 Variance 2017
Revenue $ 712,752 $ 1,301 $ 711,451 $ 6,801 $ 704,650 Total fuel and purchased power 268,297 (15,543 ) 283,840 9,477
274,363 Gross margin (non-GAAP) 444,455 16,844 427,611 (2,676 ) 430,287 Operations and maintenance 195,581 9,406 186,175 13,868 172,307
Depreciation and amortization 88,577 3,010 85,567 5,324
80,243
Total operating expenses 284,158 12,416 271,742 19,192
252,550
Adjusted operating income (a)
____________________
(a) Due to the changes in our segment disclosures discussed in Note 5 of the
Notes to the Consolidated Financial Statements in this Annual Report on Form
10-K, Electric Utilities Adjusted operating income was revised for the years
ended
of
2019 Compared to 2018
Gross margin increased over the prior year as a result of:
(in millions)
Reduction in purchased power capacity costs $ 6.5
Prior year Wyoming Electric PCA Stipulation settlement 3.7
Rider recovery 3.1
Increased commercial and industrial demand 1.9
Weather 0.2
Other 1.4
Total increase in Gross margin (non-GAAP) $ 16.8
Operations and maintenance expense increased primarily due to $4.7 million of
higher employee costs and $2.9 million of higher outside services expenses.
Various other expenses comprise the remainder of the increase compared to the
prior year.
Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.
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2018 Compared to 2017
Gross margin decreased over the prior year as a result of:
(in millions)
TCJA revenue reserve $ (22.3 )
Wyoming Electric PCA Stipulation settlement (2.6 )
Other (1.4 )
Horizon Point shared facility revenue (a) 9.8
Rider recovery 5.1
Weather 3.6
Power Marketing, transmission and Tech Services 3.5
Residential customer growth 1.6
Total increase (decrease) in Gross margin (non-GAAP)
____________________
(a)
operating segments and had no impact on consolidated results.
Operations and maintenance expense increased primarily due to$4.5 million of higher facility costs,$4.1 million of higher outside services expenses,$3.6 million of higher employee costs, and$1.0 million of higher property taxes due to a higher asset base.
Depreciation and amortization increased primarily due to higher asset base driven by current and prior year capital expenditures.
For the year ended December 31,
Contracted power plant fleet availability (a) 2019 2018 2017
Coal-fired plants (b) 92.1% 93.9%
88.9%
Natural gas fired plants and Other plants (c) 87.9% 96.4% 96.1% Wind 95.6% 96.9% 93.3% Total availability 89.9% 95.6% 93.6% Wind capacity factor 38.7% 39.2% 36.7% ____________________
(a) Availability and wind capacity factor are calculated using a weighted average
based on capacity of our generating fleet.
(b) 2019 included planned outages at Neil Simpson II and Wygen III and unplanned
outages at Wyodak Plant and Wygen III.
(c) 2019 included planned outages at Neil Simpson CT and Lange CT.
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Operating results for the years endedDecember 31 for theGas Utilities were as follows (in thousands): 2019 Variance 2018 Variance 2017 Revenue: Natural gas - regulated$ 932,111 $ (10,813 ) $ 942,924 $ 77,093 $ 865,831 Other - non-regulated services 77,919 (4,464 ) 82,383 584 81,799 Total revenue 1,010,030 (15,277 ) 1,025,307 77,677 947,630 Cost of natural gas sold: Natural gas - regulated 406,643 (35,887 ) 442,530 61,271 381,259 Other - non-regulated services 19,255 (368 ) 19,623 (8,721 ) 28,344 Total cost of sales 425,898 (36,255 ) 462,153 52,550 409,603 Gross margin (non-GAAP) 584,132 20,978 563,154 25,127 538,027 Operations and maintenance 301,844 10,363 291,481 22,291 269,190
Depreciation and amortization 92,317 5,883 86,434 2,702
83,732
Total operating expenses 394,161 16,246 377,915 24,993 352,922
Adjusted operating income $ 189,971 $ 4,732 $ 185,239 $ 134 $ 185,105
2019 Compared to 2018
Gross margin increased over the prior year as a result of:
(in millions)
New rates $
16.2
Customer growth - distribution
5.2
Increased transport and transmission
2.6
Weather
(2.2 ) Decreased mark-to-market on non-utility natural gas commodity contracts
(3.3 )
Other 2.5
Total increase in Gross margin (non-GAAP) $
21.0
Operations and maintenance expense increased primarily due to$5.5 million of higher outside services expenses,$1.2 million higher employee costs and$2.0 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures. Various other expenses comprise the remainder of the increase compared to the prior year.
Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.
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2018 Compared to 2017
Gross margin increased over the prior year as a result of:
(in millions)
Weather (a) $ 13.8
New rates 10.7
Customer growth - distribution 5.2
Increased mark-to-market on non-utility natural gas commodity contracts
4.0
Increased transport and transmission
3.6
Natural gas volumes sold
3.2
Non-utility - Choice Gas, Tech Services and appliance repair 2.7 Other 2.4 TCJA revenue reserve (20.5 ) Total increase (decrease) in Gross margin (non-GAAP) $
25.1
___________________
(a) Heating degree days at the
were 2% higher than normal compared to 10% lower than normal in 2017.
Operations and maintenance expense increased primarily due to$11.8 million of higher employee costs,$4.7 million of higher facility costs,$4.0 million of higher outside services expenses and$2.1 million of higher bad debt expense driven by an increase in revenues.
Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.
Power Generation
Our Power Generation segment operating results for the years ended
2019 Variance 2018 Variance 2017
Revenue $ 101,258 $ 8,807 $ 92,451 $ (2,169 ) $ 94,620
Total fuel 9,059 467 8,592 (748 ) 9,340
Operations and maintenance 28,429 3,294 25,135 2,093 23,042
Depreciation and amortization 18,991 2,881 16,110 562 15,548
Total operating expenses 56,479 6,642 49,837 1,907 47,930
Adjusted operating income (a)
____________________
(a) Due to the changes in our segment disclosures discussed in Note 5 of the
Notes to the Consolidated Financial Statements in this Annual Report on Form
10-K, Power Generation Adjusted operating income was revised for the years
ended
2019 Compared to 2018
Revenue increased in the current year due to increased wind MWh sold and higher
PPA prices. Operating expenses increased in the current year primarily due to
higher depreciation and property taxes from new wind assets.
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2018 Compared to 2017
Revenue decreased in 2018 due to a decrease in MWh sold, primarily from a planned outage at Wygen I. Operating expenses increased due to higher maintenance expenses primarily related to outage costs at Wygen I and higher depreciation.
For the year ended December 31,
Contracted power plant fleet availability (a) 2019 2018 2017 Coal-fired plant (b) 94.5% 85.8% 96.9% Natural gas-fired plants 98.6% 99.4% 99.2% Wind (c) 90.6% N/A N/A Total availability 95.0% 95.9% 98.6% Wind capacity factor (c) 23.5% N/A N/A ___________
(a) Availability and wind capacity factor are calculated using a weighted average
based on capacity of our generating fleet.
(b) Wygen I experienced a planned outage in 2018
(c) Change from 2018 to 2019 is driven by
acquisition of new wind assets.
Mining
Mining operating results for the years ended December 31 were as follows (in
thousands):
2019 Variance 2018 Variance 2017
Revenue $ 61,629 $ (6,404 ) $ 68,033 $ 1,412 $ 66,621
Operations and maintenance 40,032 (3,696 ) 43,728 (1,154 ) 44,882
Depreciation, depletion and amortization 8,970 1,005 7,965 (274 ) 8,239
Total operating expenses 49,002 (2,691 ) 51,693 (1,428 ) 53,121
Adjusted operating income $ 12,627 $ (3,713 ) $ 16,340 $ 2,840 $ 13,500 The following table provides certain operating statistics for the Mining segment (in thousands):
2019 2018 2017
Tons of coal sold 3,716 4,085 4,183
Cubic yards of overburden moved 8,534 8,970 9,018 Coal reserves at year-end (in tons) 185,448 189,164 194,909
Revenue per ton$ 15.94 $ 16.11 $ 15.93 2019 Compared to 2018
Current year revenue decreased primarily due to 9% fewer tons sold driven primarily by planned and unplanned generation facility outages at the Wyodak Plant. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues and lower fuel, labor, and major maintenance expenses.
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2018 Compared to 2017
Revenue increased primarily due to a 1% increase in price per ton sold. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income, net. Operating expenses decreased primarily due to lower major maintenance expenses. Corporate and Other Corporate and Other operating results for the years endedDecember 31 were as follows (in thousands): (in thousands) 2019 Variance 2018 Variance 2017
Adjusted operating (loss) (a)
____________
(a) Due to the changes in our segment disclosures discussed in Note 5 of the
Notes to the Consolidated Financial Statements in this Annual Report on Form
10-K, Corporate and Other Adjusted operating (loss) was revised for the years
ended
2019 Compared to 2018
The variance in Adjusted operating (loss) was primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.
2018 Compared to 2017
The variance in Adjusted operating (loss) was primarily due to prior year acquisition costs.
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)
(in thousands) 2019 Variance 2018 Variance 2017 Interest expense, net$ (137,659 ) $ 2,316 $ (139,975 ) $ (2,873 ) $ (137,102 ) Impairment of investment (19,741 ) (19,741 ) - - -
Other income (expense), net (5,740 ) (4,560 ) (1,180 ) (3,288 ) 2,108 Income tax benefit (expense) (29,580 ) (53,247 ) 23,667 97,034
(73,367 )
2019 Compared to 2018
Impairment of Investment
For the year ended December 31, 2019 , we recorded a pre-tax non-cash write-down
of $20 million in our investment in equity
securities of a privately held oil and gas company. The impairment was triggered
by a deterioration in earnings performance of
the privately held oil and gas company and an adverse change in future natural
gas prices. See Note 1 of the Notes to
Consolidated Financial Statements for additional details.
Other Income (Expense)
For the year ended
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Income Tax Benefit (Expense)
The increase in tax expense was primarily due to a prior year
• A prior year
the previously estimated impact of tax reform on deferred income taxes;
• Current year $3.8 million of federal PTCs and $2.1 million of relatedstate ITCs associated with new wind assets;
• A current year
flow-through regulatory jurisdictions;
• A current year
tax amortization related to tax reform; and
• A current year $3.4 million tax benefit from a
federal tax loss carry-back claim including interest. We identified
certain qualified expenses that extend beyond the typical two-year
carry-back period.
2018 Compared to 2017
Other Income (Expense)
The variance in Other income (expense), net was primarily due to the presentation change of non-service pension costs to Other income (expense) in 2018, previously reported in Operations and maintenance.
Income Tax Benefit (Expense)
The variance in Income tax benefit (expense) was primarily due to a$73 million tax benefit in 2018 resulting from legal entity restructuring and the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effectiveJanuary 1, 2018 , partially offset by a$(4.0) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes. Liquidity and Capital Resources OVERVIEW Our company requires significant cash to support and grow our businesses. Our predominant source of cash is from our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the construction season. We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section. 57
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The following table provides an informational summary of our financial position as ofDecember 31 (dollars in thousands): Financial Position Summary 2019
2018
Cash and cash equivalents$ 9,777 $
20,776
Restricted cash and equivalents$ 3,881 $
3,369
Notes payable$ 349,500 $
185,620
Short-term debt, including current maturities of long-term debt$ 5,743 $ 5,743 Long-term debt (a)$ 3,140,096 $ 2,950,835 Stockholders' equity$ 2,362,123 $ 2,181,588 Ratios Long-term debt ratio 57 % 57 % Total debt ratio 60 % 59 % ______________
(a) Carrying amount of long-term debt is net of deferred financing costs.
Significant Factors Affecting Liquidity
Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including weather seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow. However, the potential for unforeseen events affecting cash needs will continue to exist. Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. AtDecember 31, 2019 , we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.
Weather Seasonality, Commodity Pricing and Associated Hedging Strategies
We manage liquidity needs through hedging activities, primarily in connection with seasonal needs of our utility operations (including seasonal peaks in fuel requirements), interest rate movements and commodity price movements.
Utility Factors
Our cash flows, and in turn liquidity needs in many of our regulated jurisdictions, can be subject to fluctuations in weather and commodity prices. Since weather conditions are uncontrollable, we have implemented commission-approved natural gas hedging and storage programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging a percentage of our forecasted natural gas supply consumption using options, futures, basis swaps and physical fixed price purchases.
Interest Rates
Some of our debt instruments have a variable interest rate component which can change significantly depending on the economic climate. We do not have any interest rate swap agreements atDecember 31, 2019 ; 90% of our interest rate exposure has been mitigated through fixed interest rates. 58
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Federal and State Regulations
We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
CASH GENERATION AND CASH REQUIREMENTS
Cash Generation
Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring in 2023, our CP Program, our ATM equity offering program and our ability to access the public and private capital markets through debt and equity securities offerings when necessary.
Cash Collateral
Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral with the counterparty to meet these obligations. The cash collateral we were required to post atDecember 31, 2019 was not material.
DEBT, EQUITY AND LIQUIDITY
Debt
Revolving Credit Facility and CP Program
OnJuly 30, 2018 , we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of$750 million and extending the term throughJuly 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to$1.0 billion . Borrowings continue to be available under a base rate or various Eurodollar rate options. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information. We have a$750 million , unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed$750 million . See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
Current Short-term borrowings at Letters of Credit at Available Capacity at
Credit Facility Expiration Capacity December 31, 2019 December 31, 2019 December 31, 2019
Revolving Credit
Facility and CP
Program July 30, 2023 $ 750 $ 350 $ 30 $ 370
The weighted average interest rate on short-term borrowings at December 31, 2019
was 2.03%. Short-term borrowing activity for the twelve months ended December
31, 2019 was:
(dollars in millions) Maximum amount outstanding - short-term borrowing (based on daily outstanding balances)
$ 357
Average amount outstanding - short-term borrowing (based on daily outstanding balances)
$ 187
Weighted average interest rates - short-term borrowing 2.47 %
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The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. We were in compliance with these covenants as of December 31, 2019. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information. The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.
Cross-Default Provisions
Our$7 million Corporate term loan contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to make timely payments of debt obligations or triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of$50 million or more that permits the acceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and the threshold principal amount is$50 million .
The Revolving Credit Facility prohibits us from paying cash dividends if we are in default or if paying dividends would cause us to be in default.
As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with theFERC and appropriate state regulators. Under the utility money pool agreements, our utilities may at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates (2.210% atDecember 31, 2019 ). While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.
At
Borrowings From
Subsidiary Money Pool Outstanding
BHSC $ 148,041
South Dakota Electric 57,585
Wyoming Electric 37,993
Total Money Pool borrowings from Parent $ 243,619
Equity
Shelf Registration
We have an effective automatic shelf registration statement on file with the SEC
under which we may issue, from time to time, senior debt securities,
subordinated debt securities, common stock, preferred stock, warrants and other
securities. Although the shelf registration statement does not limit our
issuance capacity, our ability to issue securities is limited to the authority
granted by our Board of Directors, certain covenants in our financing
arrangements and restrictions imposed by federal and state regulatory
authorities. The shelf registration expires in August 2020 . Our articles of
incorporation authorize the issuance of 100 million shares of common stock and
25 million shares of preferred stock. As of December 31, 2019 , we had
approximately 61 million shares of common stock outstanding and no shares of
preferred stock outstanding.
ATM
In 2019, we issued a total of 1,328,332 shares of common stock under the ATM for proceeds of$99 million , net of$1.2 million in issuance costs. As ofDecember 31, 2019 , all shares were settled. 60
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Common Stock Dividends
Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors. OnJanuary 29, 2020 , our Board of Directors declared a quarterly dividend of$0.535 per share, equivalent to an annual dividend rate of$2.14 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share: 2019 2018 2017 Dividend Payout Ratio 63% 40% 50% Dividends Per Share$2.05 $1.93 $1.81
Our three-year compound annualized dividend growth rate was 6.9% and all dividends were paid out of available operating cash flows.
Dividend Restrictions
As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities inArkansas ,Colorado ,Iowa ,Kansas andNebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither BHSC nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. See additional information in Note 6 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants. See additional information in Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Covenants within
Financing Activities
Financing activities in 2019 consisted of the following:
• We issued a total of 1.3 million shares of common stock under the ATM
equity offering program for proceeds of
in issuance costs.
• On
principal amount in senior unsecured notes. The debt offering consisted of
million of 3.875% 30-year senior notes due
used to repay the
retire the
portion of short-term debt.
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• OnJune 17, 2019 , we amended our Corporate term loan dueJuly 30, 2020 . This amendment increased total commitments to$400 million from$300 million , extended the term throughJune 17, 2021 and continued to have
substantially similar terms and covenants as the amended and restated
Revolving Credit Facility. The net proceeds were used to pay down
short-term debt. Proceeds from the October 3, 2019 debt transaction were
used to repay this term loan.
• Short-term borrowings from our Revolving Credit Facility and CP Program.
Future Financing Plans
We anticipate the following financing activities in 2020:
• Renew our shelf registration and ATM;
• Continued equity issuance under the ATM or assess other equity issuance
options;
• Refinance a portion of short-term borrowings held through the Revolving
Credit Facility and CP Program to long-term debt; and
• Continue to assess debt and equity needs to support our capital
expenditure plan.
CASH FLOW ACTIVITIES
The following table summarizes our cash flows (in thousands):
2019 2018 2017
Cash provided by (used in)
Operating activities $ 505,513 $ 488,811 $ 428,261
Investing activities $ (816,210 ) $ (465,849 ) $ (317,118 )
Financing activities $ 300,210 $ (17,057 ) $ (108,695 )
2019 Compared to 2018
Operating Activities:
Net cash provided by operating activities was
• Cash earnings (income from continuing operations plus non-cash adjustments)
were
at our Electric and Gas Utilities ;
• Net outflows from operating assets and liabilities were
than prior year, primarily attributable to:
• Cash outflows increased by approximately $40 million as a result of
changes in accounts payable and accrued liabilities, driven by the
impact of higher outside services, employee costs and other working
capital requirements;
• Cash inflows increased by approximately $59 million compared to theprior year primarily as a result of lower accounts receivable driven by
lower pass-through revenues reflecting lower commodity prices; and
• Cash inflows decreased by approximately $44 million primarily as a
result of changes in our current regulatory liabilities due to the TCJA
tax rate change that has subsequently been returned to customers and
from changes in our current regulatory assets driven by lower fuel cost
adjustments and the impact of lower commodity prices; and
• Cash outflows decreased approximately
operating activities of discontinued operations in 2019.
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Investing Activities:
Net cash used in investing activities was$816 million in 2019, compared to net cash used in investing activities of$466 million in 2018 for a variance of$350 million . This variance was primarily due to:
• Capital expenditures of approximately
million in 2018. The $361 million increase from the prior year was due to
higher capital expenditures driven by higher programmatic safety,
reliability and integrity spending at our Electric and Gas Utilities
segments, the Corriedale Wind Energy Project at our Electric Utilities segment, construction of the final segment of the 175-mile transmission line
from Rapid City, South Dakota , to Stegall, Nebraska , at our Electric
Utilities segment, the 35-mile Natural Bridge pipeline project at our Gas
Utilities segment, and construction of Busch Ranch II at our Power
Generation segment; and
• Net cash used in investing activities decreased
year activities associated with divesting of our oil and gas segment.
Financing Activities:
Net cash provided by financing activities was$300 million in 2019 as compared to net cash used by financing activities of$17 million in 2018, an increase of$317 million due to the following:
• Increase of
excess of required maturities that were used to fund our capital program
• Decrease of
gross proceeds of approximately
partially offset by current year net proceeds of
equity offering program;
• Cash dividends on common stock of
$107 million paid in 2018; and
• Cash outflows for other financing activities increased by approximately
million driven primarily by current year financing costs incurred in the
October 3, 2019 debt transaction.
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Table of Contents CAPITAL EXPENDITURES Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. SeeKey Elements of our Business Strategy above in Item 7 - Executive Summary and Business Strategy for forecasted capital expenditure requirements. A significant portion of our capital expenditures relates to safety, reliability and integrity assets benefiting customers that may be included in utility rate base and can be recovered from our utility customers following regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.
Historical Capital Requirements
Our primary capital requirements for the three years endedDecember 31 were as follows (in thousands): 2019 2018 2017 Property additions: (a) Electric Utilities (b)$ 222,911 $ 152,524 $ 138,060 Gas Utilities (c) 512,366 288,438 184,389 Power Generation (d) 85,346 30,945 1,864 Mining 8,430 18,794 6,708 Corporate and Other 20,702 11,723 6,668 Capital expenditures before discontinued operations 849,755 502,424 337,689 Discontinued operations - 2,402 23,222 Total capital expenditures 849,755 504,826 360,911 Common stock dividends 124,647 106,591 96,744
Maturities/redemptions of long-term debt 905,743 854,743
105,743
Total capital requirements $ 1,880,145 $ 1,466,160 $ 563,398
____________________________(a) Includes accruals for property, plant and equipment as disclosed in Note
17 of the Notes to the Consolidated Financial Statements in this Annual
Report on Form 10-K.
(b) Current year capital expenditures at our
due to higher programmatic safety, reliability and integrity spending, the
transmission line from
(c) Current year capital expenditures at our
to higher programmatic safety, reliability and integrity spending and the
35-mile
(d) Current year capital expenditures at our Power Generation segment increased
due to construction of Busch Ranch II.
CREDIT RATINGS AND COUNTERPARTIES
Financing for operational needs and capital expenditure requirements, not
satisfied by operating cash flows, depends upon the cost and availability of
external funds through both short and long-term financing. In order to operate
and grow our business, we need to consistently maintain the ability to raise
capital on favorable terms. Access to funds is dependent upon factors such as
general economic and capital market conditions, regulatory authorizations and
policies, the Company's credit ratings, cash flows from routine operations and
the credit ratings of counterparties. After assessing the current operating
performance, liquidity and credit ratings of the Company, management believes
that the Company will have access to the capital markets at prevailing market
rates for companies with comparable credit ratings. BHC notes that credit
ratings are not recommendations to buy, sell, or hold securities and may be
subject to revision or withdrawal at any time by the assigning rating agency.
Each rating should be evaluated independently of any other rating.
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The following table represents the credit ratings, outlook and risk profile of BHC atDecember 31, 2019 : Rating Agency Senior Unsecured Rating Outlook S&P (a) BBB+ Stable Moody's (b) Baa2 Stable Fitch (c) BBB+ Stable __________
(a) On
outlook.
(b) On
Stable outlook.
(c) On
outlook.
Certain of our fees and our interest rates under various bank credit agreements
are based on our credit ratings at all three rating agencies. If all of our
ratings are at the same level, or if two of our ratings are the same level and
one differs, these fees and interest rates will be based on the ratings that are
at the same level. If all of our ratings are at different levels, these fees
and interest rates will be based on the middle level. Currently, our Fitch and
S&P ratings are at the same level, and our Moody's rating is one level below.
Therefore, if Fitch or S&P downgraded our senior unsecured debt, we will be
required to pay higher fees and interest rates under these bank credit
agreements.
The following table represents the credit ratings of South Dakota Electric at
December 31, 2019 :
Rating Agency Senior Secured Rating
S&P (a) A
Moody's (b) A1
Fitch (c) A
__________
(a) On
(b) On
(c) On
We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.
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CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS
Contractual Obligations
In addition to our capital expenditure programs, we have contractual obligations and other commitments that will need to be funded in the future. The following information summarizes our cash obligations and commercial commitments atDecember 31, 2019 . Actual future obligations may differ materially from these estimated amounts (in thousands): Payments Due by
Period
Contractual Obligations 2020 2021 2022 2023 2024 Thereafter Total
Long-term debt(a)
2,855$ 2,635,000 $ 3,177,033 Interest payments (a) 131,859 131,842 131,756 131,756 109,390 1,273,648 1,910,251 Unconditional purchase obligations(b) 181,773 159,827 134,018 105,583 54,098 126,147 761,446 Lease obligations(c) 1,144 991 869 844 724 2,009 6,581 AROs (d) 330 231 144 33 9,362 54,105 64,205 Employee benefit plans(e) 18,921 19,678 19,736 19,944 19,896 35,580 133,755 CP Program 349,500 - - - - - 349,500 Total contractual cash obligations(f)$ 689,270 $ 321,004 $ 286,523 $ 783,160 $
196,325
__________
(a) Long-term debt amounts do not include deferred financing costs or discounts
or premiums on debt. Estimated interest payments on variable rate debt are
calculated by utilizing the applicable rates as of
(b) Unconditional purchase obligations include the energy and capacity costs
associated with our PPAs, capacity and certain transmission, gas
transportation and storage agreements. The energy charges under the PPAs are
variable costs, which for purposes of estimating our future obligations, were
based on costs incurred during 2019 and price assumptions using existing
prices at
tariffs as of
(c) Includes leases associated with several office and operating facilities,
communication tower sites, equipment and materials storage.
(d) Represents estimated payments for AROs associated with long-lived assets
primarily related to retirement and reclamation of natural gas pipelines,
mining sites, wind farms and an evaporation pond. See Notes 1 and 8
of the Notes to the Consolidated Financial Statements in this Annual Report
on Form 10-K for additional information.
(e) Represents estimated employer contributions to the Defined Benefit Pension
Plan, the Non-Pension Defined Benefit Postretirement Healthcare Plan and the
Supplemental Non-Qualified Defined Benefit Plans through the year 2029 as
discussed in Note 18 of the Notes to the Consolidated Financial
Statements in this Annual Report on Form 10-K.
(f) Amounts in the table exclude: (1) any obligation that may arise from our
derivatives, including commodity related contracts that have a negative fair
value at
impractical to reasonably estimate the final amount and/or timing of any
associated payments; (2) a portion of our gas purchases are hedged. These
hedges are in place to reduce our customers' underlying exposure to commodity
price fluctuations. The impact of these hedges is not included in the above
table; (3) our
accordance with accounting guidance for uncertain tax positions as discussed
in Note 15 of the Notes to the Consolidated Financial Statements in this
Annual Report on Form 10-K.
OurGas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. In addition, a portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure, are carried out for 60 days. As ofDecember 31, 2019 , we are committed to purchase 3.7 million MMBtu, 3.7 million MMBtu, and 1.8 million MMBtu in each of the years from 2020 to 2022, respectively.
Off-Balance Sheet Commitments
We have entered into various off-balance sheet commitments in the form of guarantees and letters of credit.
Guarantees
We provide various guarantees supporting certain of our subsidiaries under
specified agreements or transactions. For more information on these guarantees,
see Note 20 of the Notes to the Consolidated Financial Statements in this
Annual Report on Form 10-K.
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Letters of Credit
Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. For more information on these letters of credit, see
Note 7 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Critical Accounting Policies Involving Significant Accounting Estimates
We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management's judgment in application. There are also areas which require management's judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments, or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee. The following discussion of our critical accounting estimates should be read in conjunction with Note 1 , "Business Description and Significant Accounting Policies" of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. Regulation Our regulated Electric andGas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings. To some degree, each of our Electric andGas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows. As ofDecember 31, 2019 and 2018, we had total regulatory assets of$271 million and$284 million , respectively, and total regulatory liabilities of$537 million and$541 million , respectively. See Note 13 of the Notes to the Consolidated Financial Statements for further information. 67
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We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as ofOctober 1 , which aligns our testing date with our financial planning process. Accounting standards for testing goodwill for impairment require a two-step process be performed to analyze whether or not goodwill has been impaired.Goodwill is tested for impairment at the reporting unit level. The first step of this test, used to identify potential impairment, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds fair value under the first step, then the second step of the impairment test is performed to measure the amount of any impairment loss. Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our 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. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. Varying by reporting unit, weighted average cost of capital in the range of 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed in the fourth quarter of 2019. Although 1% to 2% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews, as well as other improved efficiency and cost reduction initiatives. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and 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, we add a reasonable control premium when calculating 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 estimates and assumptions used in the impairment assessments are based on available market information and we believe they are reasonable. However, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. For the years endedDecember 31, 2019 , 2018, and 2017, there were no impairment losses recorded. AtDecember 31, 2019 , the fair value substantially exceeded the carrying value at all reporting units. As described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have prospectively adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, onJanuary 1, 2020 .
Pension and Other Postretirement Benefits
As described in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. AMaster Trust holds the assets for the pension plan. A trust for the funded portion of the post-retirement healthcare plan has also been established. Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense. The 2020 pension benefit cost for our non-contributory funded pension plan is expected to be$10.2 million compared to$2.1 million in 2019. The increase in pension benefit cost is driven primarily by a decrease in the discount rate and lower expected return on assets. 68
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The effect of hypothetical changes to selected assumptions on the pension and
other postretirement benefit plans would be as follows in thousands of dollars:
December 31,
2019 2020
Percentage Increase/(Decrease) Increase/(Decrease)
Assumptions Change PBO/APBO (a) Expense - Pretax
Pension
Discount rate (b) +/- 0.5 (28,998)/31,912 (3,965)/4,311
Expected return on assets +/- 0.5 N/A (2,036)/2,036
OPEB
Discount rate (b) +/- 0.5 (2,836)/3,095 90/116
Expected return on assets +/- 0.5 N/A (39)/39
__________________________(a) Projected benefit obligation (PBO) for the pension plan and accumulated
postretirement benefit obligation (APBO) for OPEB plans.
(b) Impact on service cost, interest cost and amortization of gains or losses.
Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. As ofDecember 31, 2019 , we have a regulatory liability associated with TCJA related items of$285 million , completing our accounting for the revaluation of deferred taxes pursuant to the TCJA. A significant portion of the excess deferred taxes are subject to the average rate assumption method, as prescribed by theIRS , and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As ofDecember 31, 2019 , the Company has amortized$6.5 million of regulatory liability associated with TCJA related items. The portion that was eligible for amortization under the average rate assumption method in 2019, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.
See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
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Market Risk DisclosuresOur market risk disclosures are detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, with additional information provided in the following paragraphs.
Our exposure to the market risks detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K is also affected by other factors including the size, duration and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates and the liquidity of the related interest rate and commodity markets. The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at least quarterly and as necessary, appropriate or desirable, to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.
Electric and
We produce, purchase and distribute power in four states, and purchase and distribute natural gas in six states. Our utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to "true-up" billed amounts to match the actual energy cost we incurred. InColorado ,South Dakota andWyoming , we have ECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. InArkansas ,Colorado ,Iowa ,Kansas ,Nebraska andWyoming , we have GCA provisions that adjust natural gas rates when our natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic prudence reviews by the state utility commissions. See additional information in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
A potential risk related to power sales is the price risk arising from the sale of wholesale power that exceeds our generating capacity. These potential short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin.
Financing Activities
Periodically, we have engaged in activities to manage risks associated with changes in interest rates. We have utilized pay-fixed interest rate swap agreements to reduce exposure to interest rate fluctuations associated with floating rate debt obligations and anticipated debt refinancings. AtDecember 31, 2019 , we had no interest rate swaps in place. As discussed in Item 7 - Liquidity and Capital Resources , 90% of our variable interest rate exposure has been mitigated through issuing fixed rate debt.
Further details of past swap agreements are set forth in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Credit Risk
Our credit risk disclosures are detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, with additional information provided below.
We have adopted the Black Hills Corporation Credit Policy that establishes
guidelines, controls and limits to manage and mitigate credit risk within risk
tolerances established by the Board of Directors. In addition, our Executive
Risk Committee, which includes senior executives, meets on a regular basis to
review our credit activities and to monitor compliance with the adopted
policies.
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New Accounting Pronouncements
See Note 1 of the Notes to the Consolidated Financial Statements in this
Annual Report on Form 10-K for information on new accounting standards adopted
in 2019 or pending adoption.
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