NORTHWESTERN ENERGY GROUP, INC. The following includes a discussion of our results of operations and cash flows for the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 , on both a consolidated basis and on a segment basis. For a discussion of our financial results and cash flows for the year endedDecember 31, 2018 compared with the year endedDecember 31, 2017 , see 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 . This should be read in conjunction with Item 6. Selected Financial Data and our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 20 - Segment and Related Information, to the Consolidated Financial Statements, which is included in Item 8 herein. For information regarding our revenues, net income and assets, see our Consolidated Financial Statements included in Item 8. OVERVIEWNorthWestern Corporation , doing business asNorthWestern Energy , provides electricity and/or natural gas to approximately 734,800 customers inMontana ,South Dakota andNebraska . As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2019, 2018 and 2017. Following is a discussion of our strategy and significant trends. We are working to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees and investors. This includes bridging our history as a regulated utility safely providing low-cost and reliable service with our future as a globally-aware company offering a broader array of services performed by highly-adaptable and skilled employees. We seek to deliver value to our customers by providing high reliability and customer service, and an environmentally sustainable generation mix at an affordable price. We are focused on delivering long-term shareholder value by continuing to invest in our system including: • Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in distribution and substations that enables the use of changing technology.
• Integrating supply resources that balance reliability, cost, capacity, and
sustainability considerations with more predictable long-term commodity
prices.
• Continually improving our operating efficiency. Financial discipline is
essential to earning our authorized return on invested capital and
maintaining a strong balance sheet, stable cash flows, and quality credit
ratings.
We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.
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HOW WE PERFORMED IN 2019 COMPARED TO OUR 2018 RESULTS
Year Ended December 31, 2019 vs. 2018
Income Before Income Tax Benefit
Income Taxes (Expense) Net Income
(in millions)
Year ended December 31, 2018$ 178.3 $ 18.7$ 197.0 Items increasing (decreasing) net income: Higher revenue absent the 2018 impacts of the Tax Cuts and Jobs Act 22.1 (5.6 ) 16.5 Higher electric and natural gas retail volumes 17.3 (4.6 ) 12.7 Higher Montana electric retail rates 4.4 (1.1 ) 3.3 Income tax benefit - 3.0 3.0 Higher Montana electric supply cost recovery 3.9 (1.0 ) 2.9 Lower depreciation and depletion 1.6 (0.4 ) 1.2 Electric QF liability adjustment (20.9 ) 5.3 (15.6 ) Higher operating, general, and administrative expenses (17.3 ) 4.4 (12.9 ) Lower Montana electric transmission revenue (5.6 ) 1.4 (4.2 ) Lower Montana gas production rates (1.5 ) 0.6 (0.9 ) Other (0.1 ) (0.8 ) (0.9 ) Year ended December 31, 2019$ 182.2 $ 19.9$ 202.1 Change in Net Income$ 5.1 Consolidated net income in 2019 was$202.1 million as compared with$197.0 million in 2018. This increase was primarily due to a reduction in revenue in 2018 due to the impact of the Tax Cuts and Jobs Act regulatory settlements, higher volumes due to colder winter weather and customer growth, and a larger income tax benefit in 2019. These improvements were partly offset by the adjustment of our electric QF liability and higher operating expenses.
SIGNIFICANT TRENDS AND REGULATION
Electric Resource Planning -
InAugust 2019 , we issued our final 2019 Electricity Supply Resource Procurement Plan (Montana Resource Plan) that included responses to public comments. The Montana Resource Plan supports the goal of developing resources that will address the changing energy landscape inMontana to meet our customers' electric energy needs in a reliable and affordable manner. We are currently 630 MW short of our peak needs, which we procure in the market. We forecast that our energy portfolio will be 725 MW short by 2025, considering expiring contracts and a modest increase in customer demand. Based on our customers' future energy resource needs as identified in the Montana Resource Plan, we issued an all-source competitive solicitation request inFebruary 2020 for up to 280 MWs of peaking and flexible capacity to be available for commercial operation in early 2023. An independent evaluator is being used to administer the solicitation process and evaluate proposals, with the successful project(s) selected by the first quarter of 2021. We expect the process will be repeated in subsequent years to provide a resource-adequate energy and capacity portfolio by 2025. The proposed solicitation process will allow us to consider a wide variety of resource options. These options include power purchase agreements and owned energy resources comprised of different structures, terms and technologies that are cost-effective resources. The staged approach is designed to allow for incremental steps through time with opportunities for different resource type of new technologies while also building a reliable portfolio to meet local and regional conditions and minimizing customer impacts. 32 -------------------------------------------------------------------------------- Proposed Colstrip Unit 4 Capacity Acquisition - InFebruary 2020 , we filed an application for pre-approval with the MPSC to acquirePuget Sound Energy's 25% interest, 185 megawatts of generation, in Colstrip Unit 4 forone dollar . In addition, we are seeking approval to sell 90 megawatts toPuget Sound Energy for roughly 5 years at a price indexed to hourly prices at the Mid-Columbia power hub, with a price floor reflecting the recovery of fixed operating and maintenance costs and variable generation costs. Our proposal includes zero net effect on customer bills while setting aside the benefits from the transaction - estimated to be$4 million annually - to address environmental compliance, remediation and decommissioning costs associated with our existing 222 MWs of ownership.Puget Sound Energy remains responsible for its presale 25% ownership share of all costs for remediation of existing environmental conditions and decommissioning regardless of the proposed acquisition or when Colstrip Unit 4 is retired. We expect the MPSC to establish a procedural schedule in this docket in the first quarter of 2020. If this capacity acquisition is approved, this will reduce our need for capacity identified above in our resource plan by 170 MW, which is the accredited capacity. We also entered into an agreement withPuget Sound Energy to acquire an additional 95 MW interest in the 500 kV Colstrip Transmission System for net book value at the time of the sale. The net book value is expected to range between$2.5 million to$3.8 million . After the roughly 5-year purchase power agreement withPuget Sound Energy , we will have the option to acquire another 90 MW interest in the 500 kV Colstrip Transmission System for net book value at that time. These transmission acquisitions are conditioned upon approval and closing of the Unit 4 acquisition.
Recovery of the additional rate base from these transactions, if completed, will
be subject to review in the next
Electric Resource Planning -
InApril 2019 , we issued a request for proposals for 60 MW of flexible capacity resources to begin servingSouth Dakota customers by the end of 2021. As a result of a competitive solicitation process, we expect to own a natural gas fired reciprocating internal combustion engines atHuron, South Dakota . Dependent upon selection of manufacturer, we anticipate 55 - 60 MW to be online by late 2021 at a total investment of approximately$80 million . The selected proposal is subject to the execution of construction contracts and obtaining the applicable environmental and construction related permits.
We anticipate financing this project with a combination of cash flow from operations, first mortgage bonds and equity issuances. Based on current expectations, any equity issuance would be late 2020 or early 2021 and would be sized to maintain and protect current credit ratings.
Montana General Electric Rate Case
InDecember 2019 , the MPSC issued a final order approving our electric rate case settlement for rates effectiveApril 1, 2019 , resulting in an annual increase to electric revenue of approximately$6.5 million (based upon a 9.65% return on equity (ROE) and rate base and capital structure as filed) and an annual decrease in depreciation expense of approximately$9.3 million . Various parties have filed petitions for reconsideration of parts of thatDecember 2019 order, and we expect the MPSC to issue an order on these requests during the first quarter of 2020. FERC Filing - InMay 2019 , we submitted a filing with theFERC for ourMontana transmission assets. The revenue requirement associated with our Montana FERC assets is reflected in our Montana MPSC-jurisdictional rates as a credit to retail customers. We expect to submit a compliance filing with the MPSC upon resolution of our Montana FERC case adjusting the proposed credit in ourMontana retail rates. 33
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SIGNIFICANT INFRASTRUCTURE INVESTMENTS AND INITIATIVES
Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution infrastructure investment plan, are as follows (in millions):
[[Image Removed: regulated5yearforecast20191.jpg]]
Electric Supply Resource Plans - Our energy resource plans discussed above
identify portfolio resource requirements including potential investments. As a
result of a competitive solicitation process in South Dakota , we have included
$80 million of capital in our projections above for 55-60 MW of capacity
additions at a brownfield site near Huron, South Dakota expected to be in
service by late 2021.
We have not included any potential generation capital related to our Montana
competitive solicitation in the projections above. We anticipate that owned
assets to address energy and capacity needs in Montana could increase the
capital forecast presented above in excess of $200 million over the next five
years.
Natural Gas Production Assets - We own natural gas production and gathering
system assets in Montana as a part of an overall strategy to provide rate
stability and customer value through the addition of regulated assets that are
not subject to market forces. Our estimated capital expenditure requirements
above do not include estimates for incremental natural gas reserve acquisitions,
or other investment opportunities that may arise.
Distribution and Transmission Modernization and Maintenance - As part of our
commitment to maintain high level reliability and system performance, we
continue to evaluate the condition of our distribution and transmission assets
to address aging infrastructure through our asset management process. The
primary goals of our infrastructure investment are to reverse the trend in aging
infrastructure, maintain reliability, proactively manage safety, build capacity
into the system, and prepare our network for the adoption of new technologies.
We are taking a proactive and pragmatic approach to replace these assets while
also evaluating the implementation of additional technologies to prepare the
overall system for smart grid applications.
•We installed approximately $32 million of Automated Metering Infrastructure
(AMI) in our South Dakota and Nebraska jurisdictions from 2016 to 2019, which is
reflected in our property, plant and equipment. In 2020 through 2022, we expect
to install AMI in Montana at a cost ranging from approximately $100 to $105
million , which is reflected in the five year capital forecast above.
•Hazard trees are those trees that are structurally unsound and could fall into
our lines if the trees failed. Hazard trees may be located inside or outside our
electric transmission and distribution lines' rights of way and pose
34
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risks to our system including disruption of service, property damage, loss of
life, and/or fires. We worked with third parties, including the U.S. Forest
Service , to develop a plan to remove these hazard trees and began work in 2018.
The work related to this initiative is reflected in operating expenses in the
Consolidated Income Statements. During 2019 and 2018, we incurred approximately
$7.5 million and $3.3 million , respectively, in costs, which is incremental to
costs for vegetation management within our rights of way. We expect to continue
the program over the next several years with anticipated 2020 costs ranging from
approximately $4 million to $5 million , with cumulative operating expense for
the program exceeding $20 million .
RESULTS OF OPERATIONS
Our consolidated results include the results of our divisions and subsidiaries
constituting each of our business segments. The overall consolidated discussion
is followed by a detailed discussion of gross margin by segment.
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. We define Gross Margin as Revenues less Cost of Sales as presented in our Consolidated Statements of Income. The following discussion includes a reconciliation of Gross Margin to Operating Revenues, the most directly comparable GAAP measure. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Gross Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.
Factors Affecting Results of Operations
Our revenues may fluctuate substantially with changes in supply costs, which are
generally collected in rates from customers. In addition, various regulatory
agencies approve the prices for electric and natural gas utility service within
their respective jurisdictions and regulate our ability to recover costs from
customers.
Revenues are also impacted by customer growth and usage, the latter of which is
primarily affected 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 our residential and commercial
customers. We measure this effect using degree-days, which is the difference
between the average daily actual temperature and a baseline temperature of 65
degrees. Heating degree-days result when the average daily temperature is less
than the baseline. Cooling degree-days result when the average daily temperature
is greater than the baseline. The statistical weather information in our
regulated segments represents a comparison of this data.
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--------------------------------------------------------------------------------OVERALL CONSOLIDATED RESULTS
Year Ended
Consolidated net income in 2019 was$202.1 million as compared with$197.0 million in 2018, an increase of$5.1 million . As described in more detail below, this increase was primarily due to a reduction in revenue in 2018 due to the impact of the Tax Cuts and Jobs Act regulatory settlements, higher volumes due to colder winter weather and customer growth, and a larger income tax benefit in 2019. These improvements were partly offset by the adjustment of our electric QF liability and higher operating expenses. Consolidated operating revenues in 2019 were$1,257.9 million as compared with$1,192.0 million , an increase of$65.9 million . This increase was primarily due to a reduction in revenue in 2018 due to the impact of the Tax Cuts and Jobs Act regulatory settlements, higher supply costs being collected in rates, and increased volumes due to colder winter weather and customer growth. Consolidated gross margin in 2019 was$939.9 million as compared with$919.1 million in 2018, an increase of$20.8 million , or 2.3%. Electric Natural Gas Total 2019 2018 2019 2018 2019 2018 (in millions) Reconciliation of gross margin to operating revenue: Operating Revenues$ 981.2 $ 921.1 $ 276.7 $ 270.9 $ 1,257.9 $ 1,192.0 Cost of Sales 239.6 194.6 78.4 78.3 318.0 272.9 Gross Margin(1)$ 741.6 $ 726.5 $ 198.3 $ 192.6 $ 939.9 $ 919.1
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Year Ended December 31,
2019 2018 Change % Change
(in millions)
Gross Margin
Electric $ 741.6 $ 726.5 $ 15.1 2.1 %
Natural Gas 198.3 192.6 5.7 3.0
Total Gross Margin(1) $ 939.9 $ 919.1 $ 20.8 2.3 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
36
--------------------------------------------------------------------------------Primary components of the change in gross margin include the following (in millions):
Gross Margin 2019 vs. 2018
Gross Margin Items Impacting Net Income
Tax Cuts and Jobs Act impact $ 22.1
Electric and natural gas retail volumes 17.3
Montana electric retail rates 4.4
Montana electric supply cost recovery 3.9
Electric QF liability adjustment (20.9 )
Electric transmission (5.6 )
Montana natural gas production rates (1.5 )
Other 0.5
Change in Gross Margin Impacting Net Income 20.2
Gross Margin Items Offset Within Net Income
Property taxes recovered in trackers 3.0
Production tax credits flowed-through trackers (1.7 )
Operating expenses recovered in trackers (0.7 )
Change in Items Offset Within Net Income 0.6
Increase in Consolidated Gross Margin(1) $ 20.8
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Consolidated gross margin for items impacting net income increased
• A reduction in revenue in 2018 due to the impact of the Tax Cuts and Jobs Act;
• An increase in electric and gas retail volumes due primarily to colder
winter weather and customer growth;
• An increase in Montana electric revenue recognized consistent with the
order in our electric rate case, effective
above; and
• The recovery of Montana electric supply costs due to changes in the
associated statute, partly offset by higher supply costs in 2019 as
compared with 2018.
These increases were partly offset by the following items:
• The adjustment of our electric QF liability (unrecoverable costs
associated with PURPA contracts as a part of a 2002 stipulation with the
MPSC and other parties) as compared with 2018 due to the combination of:
? A lower periodic adjustment of approximately $14.2 million due to
price escalation, which was less than previously estimated; and
• A lower impact of the adjustment to actual output andpricing for
the contract year resulting in approximately $6.7 million in higher
supply costs for these QF contracts due primarily to outages at two
facilities in 2018.
• Lower demand to transmit energy across our transmission lines due to
market conditions and pricing; and
• A decrease in Montana natural gas rates associated with the annual step
down for our Montana gas production assets.
The change in consolidated gross margin also includes the following items that had no impact on net income:
• An increase in revenues for property taxes included in trackers, offset by
increased property tax expense;
• A decrease in revenue due to the increase in production tax creditbenefits passed through to customers in our tracker mechanisms, which are
offset by decreased income tax expense; and
• A decrease in revenues for operating costs included in trackers, offset by
a decrease in associated operating expense.
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Year Ended December 31,
2019 2018 Change % Change
(in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative $ 318.2 $ 307.1 $ 11.1 3.6 %
Property and other taxes 171.9 171.3 0.6 0.4
Depreciation and depletion 172.9 174.5 (1.6 ) (0.9 )
$ 663.0 $ 652.9 $ 10.1 1.5 %
Consolidated operating, general and administrative expenses were
Operating, General &
Administrative Expenses
2019 vs. 2018
Operating, General & Administrative Expenses Impacting Net Income
Hazard trees $ 4.2
Generation maintenance 3.7
Labor 2.2
Distribution maintenance 1.7
Gas transmission maintenance 1.5
Legal 1.5
Technology costs 1.2
Employee benefits 1.2
Western EIM costs 0.9
Other (0.8 )
Change in Items Impacting Net Income 17.3
Operating, General & Administrative Expenses Offset Within Net Income Pension and other postretirement benefits
(7.8 )
Operating expenses recovered in trackers (0.7 )
Non-employee directors deferred compensation 2.3
Change in Items Offset Within Net Income (6.2 )
Increase in Operating, General & Administrative Expenses $ 11.1
Consolidated operating, general and administrative expenses for items impacting
net income increased
• Higher maintenance costs at our electric generation facilities;
• Increased labor costs due primarily to compensation increases;
• Higher distribution costs due to proactive system maintenance;
• Higher natural gas transmission maintenance due to compressor repairs and
increased compliance costs;
• Higher general legal costs;
• Higher technology costs associated with security measures and maintenance
agreements;
• Higher employee benefit costs due primarily to increased pension expense
as a result of higher funding of our Montana plan, partly offset by lower
medical costs; and
• Higher costs associated with preparation to enter the Western EIM.
The change in consolidated operating, general and administrative expenses also includes the following items that had no impact on net income: • The regulatory treatment of the non-service cost components of pension and
postretirement benefit expense, which is offset in other income;
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• Lower operating expenses included in trackers recovered through revenue; and
• A change in value of non-employee directors deferred compensation due to
changes in our stock price, offset in other income.
Property and other taxes were$171.9 million in 2019, as compared with$171.3 million in 2018. This increase was primarily due to plant additions and higher estimated property valuations inMontana . Depreciation and depletion expense was$172.9 million in 2019, as compared with$174.5 million in 2018. This decrease was primarily due to the depreciation adjustment consistent with the final order in ourMontana electric rate case, as discussed above, partly offset by plant additions. Consolidated operating income in 2019 was$276.9 million as compared with$266.3 million in 2018. This increase was primarily due to higher gross margin, as discussed above, offset in part by the overall increase in operating, general, and administrative expenses. Consolidated interest expense in 2019 was$95.1 million , as compared with$92.0 million in 2018, due primarily to higher borrowings. See "Liquidity and Capital Resources" for additional information regarding our financing activities. Consolidated other income in 2019 was$0.4 million , as compared with$4.0 million in 2018. This decrease was primarily due to a$7.8 million increase in other pension expense that was partly offset by a$2.3 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation, both of which are offset in operating, general, and administrative expense with no impact to net income. This decrease was also partly offset by$1.6 million higher capitalization of AFUDC. Consolidated income tax benefit in 2019 was$19.9 million , as compared with$18.7 million in 2018. The income tax benefit for 2019 reflects the release of approximately$22.8 million of unrecognized tax benefits, including approximately$2.7 million of accrued interest and penalties, due to the lapse of statutes of limitation in the second quarter of 2019. The income tax benefit in 2018 reflects a benefit of approximately$19.8 million associated with the final measurement of excess deferred taxes associated with the Tax Cuts and Jobs Act. Our effective tax rate for the twelve months endedDecember 31, 2019 was (10.9)% as compared with (10.5)% for the same period of 2018. We currently estimate our effective tax rate will range between (2)% to 3% in 2020.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
Year Ended December 31,
2019 2018
Income Before Income Taxes $ 182.2 $ 178.3 Income tax calculated at federal statutory rate 38.3 21.0 %
37.4 21.0 %
Permanent or flow through adjustments:
State income, net of federal provisions 1.2 0.7 1.6 0.9
Recognition of unrecognized tax benefit (22.8 ) (12.5 ) - -
Flow-through repairs deductions (19.7 ) (10.8 ) (19.3 ) (10.8 )
Production tax credits (11.5 ) (6.3 ) (10.9 ) (6.1 )
Plant and depreciation of flow through items (4.0 ) (2.2 ) (2.2 ) (1.2 )
Amortization of excess deferred income taxes (DIT) (1.7 ) (0.9 ) (3.7 ) (2.1 )
Impact of Tax Cuts and Jobs Act (0.2 ) (0.1 ) (19.8 ) (11.1 )
Prior year permanent return to accrual adjustments 0.6 0.3 (3.0 ) (1.7 )
Other, net (0.1 ) (0.1 ) 1.2 0.6
(58.2 ) (31.9 ) (56.1 ) (31.5 )
Income Tax Benefit $ (19.9 ) (10.9 )% $ (18.7 ) (10.5 )%
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ELECTRIC OPERATIONS
We have various classifications of electric revenues, defined as follows:
• Retail: Sales of electricity to residential, commercial and industrial
customers.
• Regulatory amortization: Primarily represents timing differences for
electric supply costs and property taxes between when we incur these costs
and when we recover these costs in rates from our customers.
• Transmission: Reflects transmission revenues regulated by the
• Wholesale and other are largely gross margin neutral as they are offset by
changes in cost of sales.
Year Ended
Results
2019 2018 Change % Change
(in millions)
Retail revenue $ 890.7 $ 847.3 $ 43.4 5.1 %
Regulatory amortization 30.2 9.8 20.4 208.2
Total retail revenues 920.9 857.1 63.8 7.4 Transmission 54.2 58.1 (3.9 ) (6.7 ) Wholesale and Other 6.1 5.9 0.2 3.4 Total Revenues 981.2 921.1 60.1 6.5 Total Cost of Sales 239.6 194.6 45.0 23.1 Gross Margin(1)$ 741.6 $ 726.5 $ 15.1 2.1 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Revenues Megawatt Hours (MWH) Avg. Customer Counts
2019 2018 2019 2018 2019 2018
(in thousands)
Montana $ 308,840 $ 287,358 2,581 2,518 303,222 299,438
South Dakota 62,457 64,171 589 598 50,615 50,546
Residential 371,297 351,529 3,170 3,116 353,837 349,984
Montana 348,143 329,611 3,186 3,169 68,896 67,547
South Dakota 97,082 93,992 1,110 1,072 12,814 12,741
Commercial 445,225 423,603 4,296 4,241 81,710 80,288
Industrial 43,595 42,577 2,949 2,593 78 75
Other 30,595 29,600 165 166 6,219 6,185
Total Retail Electric $ 890,712 $ 847,309 10,580 10,116 441,844 436,532
Cooling Degree Days 2019 as compared with:
2019 2018 Historic Average 2018 Historic Average
Montana 370 337 403 10% warmer 8% colder
South Dakota 715 951 733 25% colder 2% colder
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Heating Degree Days 2019 as compared with:
2019 2018 Historic Average 2018 Historic Average
Montana 8,515 7,882 7,537 8% colder 13% colder
South Dakota 8,478 8,385 7,595 1% colder 12% colder
The following summarizes the components of the changes in electric gross margin
for the years ended
Gross Margin 2019 vs. 2018
Gross Margin Items Impacting Net Income
Tax Cuts and Jobs Act impact $ 21.5
Retail volumes 6.4
Montana retail rates 4.4
Montana supply cost recovery 3.9
QF liability adjustment (20.9 )
Transmission (5.6 )
Other 5.0
Change in Gross Margin Impacting Net Income 14.7
Gross Margin Items Offset Within Net Income
Property taxes recovered in trackers 2.1
Production tax credits flowed-through trackers (1.7 )
Change in Items Offset Within Net Income 0.4
Increase in Gross Margin(1) $ 15.1
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin for items impacting net income increased
• A reduction in revenue in 2018 due to the impact of the Tax Cuts and Jobs Act;
• An increase in retail volumes due primarily to colder winter weather and
customer growth;
• An increase in Montana electric revenue recognized consistent with the
final order in our electric rate case, effective April 1, 2019 , as
discussed above; and
• The recovery of Montana electric supply costs due to changes in the
associated statute, partly offset by higher supply costs in 2019 as
compared with 2018.
These increases were partly offset by the following items:
• The adjustment of our electric QF liability (unrecoverable costs
associated with PURPA contracts as a part of a 2002 stipulation with the
MPSC and other parties) as compared with the same period in 2018 due to
the combination of:
• A lower periodic adjustment of approximately$14.2 million due to price escalation, which was less than previously estimated; and • A lower impact of the adjustment to actual output and pricing for the contract year resulting in approximately$6.7 million in higher supply costs for these QF contracts due to primarily to outages at two facilities in 2018. • Lower demand to transmit energy across our transmission lines due to market conditions and pricing.
The change in gross margin also includes the following items that had no impact on net income:
• An increase in revenues for property taxes included in trackers, offset by
increased property tax expense; and
• A decrease in revenues due to the increase in production tax credit
benefits passed through to customers in our tracker mechanisms, which are
offset by decreased income tax expense.
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The change in regulatory amortization revenue is due to timing differences
between when we incur electric supply costs and when we recover these costs in
rates from our customers, which has a minimal impact on gross margin. Our
wholesale and other revenues are largely gross margin neutral as they are offset
by changes in cost of sales.
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NATURAL GAS OPERATIONS
We have various classifications of natural gas revenues, defined as follows: • Retail: Sales of natural gas to residential, commercial and industrial
customers.
• Regulatory amortization: Primarily represents timing differences for
natural gas supply costs and property taxes between when we incur these
costs and when we recover these costs in rates from our customers, which
is also reflected in cost of sales and therefore has minimal impact on
gross margin.
• Wholesale: Primarily represents transportation and storage for others.
Year Ended
Results
2019 2018 Change % Change
(in millions)
Retail revenues
Total retail revenues 240.8 231.1 9.7 4.2 Wholesale and other 35.9 39.8 (3.9 ) (9.8 ) Total Revenues 276.7 270.9 5.8 2.1 Total Cost of Sales 78.4 78.3 0.1 0.1 Gross Margin(1)$ 198.3 $ 192.6 $ 5.7 3.0 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Revenues Dekatherms Customer Counts
2019 2018 2019 2018 2019 2018
(in thousands)
Montana $ 109,395 $ 102,721 15,262 13,818 174,862 172,770
South Dakota 25,763 25,359 3,322 3,296 40,129 39,742
Nebraska 20,194 23,416 2,826 2,834 37,424 37,356
Residential 155,352 151,496 21,410 19,948 252,415 249,868
Montana 55,669 51,700 8,115 7,288 24,205 23,877
South Dakota 19,305 17,984 3,590 3,348 6,812 6,689
Nebraska 10,572 11,953 2,085 2,054 4,914 4,833
Commercial 85,546 81,637 13,790 12,690 35,931 35,399
Industrial 996 1,159 151 171 239 244
Other 1,012 986 168 156 164 163
Total Retail Gas $ 242,906 $ 235,278 35,519 32,965 288,749 285,674
Heating Degree Days 2019 as compared with:
2019 2018 Historic Average 2018 Historic Average
Montana 8,647 7,978 7,775 8% colder 11% colder
South Dakota 8,478 8,385 7,595 1% colder 12% colder
Nebraska 6,571 6,792 6,267 3% warmer 5% colder
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The following summarizes the components of the changes in natural gas gross
margin for the years ended
Gross Margin 2019 vs. 2018
Gross Margin Items Impacting Net Income
Retail volumes $ 10.9
Tax Cuts and Jobs Act 0.6
Montana production rates (1.5 )
Other (4.5 )
Change in Gross Margin Impacting Net Income 5.5
Gross Margin Items Offset Within Net Income
Property taxes recovered in trackers 0.9
Operating expenses recovered in trackers (0.7 )
Change in Items Offset Within Net Income 0.2
Increase in Gross Margin(1) $ 5.7
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin for items impacting net income increased
• An increase in retail volumes from colder winter weather and customer
growth; and
• A reduction in revenue in 2018 due to the impact of the Tax Cuts and Jobs Act.
These increases were partly offset by a reduction of rates due to the step down
of our
The change in gross margin also includes the following items that had no impact on net income:
• An increase in revenues for property taxes included in trackers, offset by
increased property tax expense; and
• A decrease in revenues for operating costs recovered in trackers, offset
by decreased operating expense.
Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
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LIQUIDITY AND CAPITAL RESOURCES
We require liquidity to support and grow our business, and use our liquidity for
working capital needs, capital expenditures, investments in or acquisitions of
assets, and to repay debt. We believe our cash flows from operations and
existing borrowing capacity should be sufficient to fund our operations, service
existing debt, pay dividends, and fund capital expenditures (excluding strategic
growth opportunities). The amount of capital expenditures and dividends are
subject to certain factors including the use of existing cash, cash equivalents
and the receipt of cash from operations. In addition, a material change in
operations or available financing could impact our current liquidity and ability
to fund capital resource requirements, and we may defer a portion of our planned
capital expenditures as necessary.
We issue debt securities to refinance retiring maturities, reduce revolver debt,
fund construction programs and for other general corporate purposes. To fund our
strategic growth opportunities we utilize available cash flow, debt capacity and
equity issuances that allows us to maintain investment grade ratings. We
anticipate financing our South Dakota flexible capacity resources with a
combination of cash flow from operations, first mortgage bonds and equity
issuances. Based upon current expectations, any equity issuance would be late
2020 or early 2021 and would be sized to maintain and protect current credit
ratings.
We plan to maintain a 50 - 55% debt to total capital ratio excluding finance
leases, and expect to continue targeting a long-term dividend payout ratio of 60
- 70% of earnings per share; however, there can be no assurance that we will be
able to meet these targets. In June 2019 , we priced $150 million aggregate
principal amount of Montana First Mortgage Bonds, at a fixed interest rate of
3.98% maturing in 2049. We issued $50 million of these bonds in June 2019 and
the remaining $100 million of these bonds in September 2019 in transactions
exempt from the registration requirements of the Securities Act of 1933, as
amended. Proceeds were used to repay a portion of our outstanding borrowings
under our revolving credit facilities and for other general corporate purposes.
The bonds are secured by our electric and natural gas assets in Montana .
Liquidity is provided by internal cash flows and the use of our unsecured
revolving credit facility. We have a $400 million revolving credit facility. In
addition, we have a $25 million revolving credit facility to provide swingline
borrowing capability. We utilize availability under our revolvers to manage our
cash flows due to the seasonality of our business, and utilize any cash on hand
in excess of current operating requirements to invest in our business and reduce
borrowings.
As of December 31, 2019 , our total net liquidity was approximately $141.1
million , including $5.1 million of cash and $136.0 million of revolving credit
facility availability. As of December 31, 2019 , there were no letters of credit
outstanding and $289 million in borrowings under our revolving line of credit.
As of February 7, 2020 , our availability under our revolving credit facility was
approximately $165.0 million .
Credit Ratings
In general, less favorable credit ratings make debt financing more costly and
more difficult to obtain on terms that are favorable to us and our customers,
may impact our trade credit availability, and could result in the need to issue
additional equity securities. Fitch Ratings (Fitch), Moody's Investors Service
(Moody's), and S&P Global Ratings (S&P) are independent credit-rating agencies
that rate our debt securities. These ratings indicate the agencies' assessment
of our ability to pay interest and principal when due on our debt. As of
February 7, 2020 , our current ratings with these agencies are as follows:
Senior Secured Rating Senior Unsecured Rating Commercial Paper
Outlook
Fitch A A- F2 Negative
Moody's A3 Baa2 Prime-2 Stable
S&P A- BBB A-2 Stable
_________________________
A security rating is not a recommendation to buy, sell or hold securities. Such
rating may be subject to revision or withdrawal at any time by the credit rating
agency and each rating should be evaluated independently of any other rating.
45
--------------------------------------------------------------------------------Capital Requirements
Our capital expenditures program is subject to continuing review and modification. Actual utility construction expenditures may vary from estimates due to changes in electric and natural gas projected load growth, changing business operating conditions and other business factors. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt and equity issuances and future rate increases. Our estimated capital expenditures are discussed above in the "Significant Infrastructure Investments and Initiatives" section.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as ofDecember 31, 2019 . See additional discussion in Note 18 - Commitments and Contingencies to the Consolidated Financial Statements. Total 2020 2021 2022
2023 2024 Thereafter
(in thousands)
Long-term debt (1)
$ 144,660 $ -$ 1,811,977 Finance leases 19,915 2,476 2,668 2,875 3,097 3,338 5,461 Estimated pension and other postretirement obligations (2) 66,087 13,514 13,491 13,209 13,097 12,776 N/A Qualifying facilities liability (3) 630,793 76,533 78,356 80,226 82,320 79,726 233,632 Supply and capacity contracts (4) 1,915,618 186,529 146,477 150,381 150,309 145,953 1,135,969 Contractual interest payments on debt (5) 1,505,723 86,420 85,883 77,602 76,397 74,709 1,104,712 Environmental remediation obligations (6) 4,540 2,482 912 720 213 213 N/A Total Commitments (7)$ 6,388,313 $ 367,954 $ 616,787 $ 325,013
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(1) Represents cash payments for long-term debt and excludes
debt discounts and debt issuance costs, net.
(2) We have estimated cash obligations related to our pension and other
postretirement benefit programs for five years, as it is not practicable to
estimate thereafter. The pension and other postretirement benefit estimates
reflect our expected cash contributions, which may be in excess of minimum
funding requirements.
(3) Certain QFs require us to purchase minimum amounts of energy at prices
ranging from
contractual obligation related to these QFs is approximately
A portion of the costs incurred to purchase this energy is recoverable
through rates authorized by the MPSC, totaling approximately
(4) We have entered into various purchase commitments, largely purchased power,
electric transmission, coal and natural gas supply and natural gas
transportation contracts. These commitments range from one to 24 years.
(5) Contractual interest payments include our revolving credit facilities, which
have a variable interest rate. We have assumed an average interest rate of
2.98% on the outstanding balance through maturity of the facilities.
(6) We estimate environmental remediation obligations for five years, as it is
not practicable to estimate thereafter. Our environmental reserve relates
primarily to the remediation of former manufactured gas plant sites owned by
us.
(7) Potential tax payments related to uncertain tax positions are not practicable
to estimate and have been excluded from this table.
Other Obligations - As a co-owner ofColstrip , we provided surety bonds of approximately$13.2 million and$5.8 million as ofDecember 31, 2019 and 2018, respectively, on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations,Colstrip Montana (the AOC) as required by theMontana Department of Environmental Quality . It is currently anticipated that each co-owner ofColstrip will be required to post an additional amount of financial assurance to support additional performance by the operator of closure and remediation actions under the AOC. As costs are incurred under the AOC, the surety bonds will be reduced. 46 --------------------------------------------------------------------------------
Factors Impacting our Liquidity
Supply Costs - Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas and electric sales typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolver, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements. The effect of this seasonality on our liquidity is also impacted by changes in electric and natural gas market prices. We recover the cost of our electric and natural gas supply through tracking mechanisms. The natural gas supply tracking mechanism in each of our jurisdictions, and electric supply tracking mechanism inSouth Dakota , are designed to provide stable recovery of supply costs, with a monthly adjustment to correct for any under or over collection. TheMontana electric supply tracking mechanism implemented in 2018, the PCCAM, is designed for us to absorb risk through a sharing mechanism, with 90% of the variance above or below the established base revenues and actual costs collected from or refunded to customers. Our electric supply rates were adjusted monthly under the prior tracker, and under the PCCAM design are adjusted annually. In periods of significant fluctuation of loads and / or market prices, this design impacts our cash flows as application of the PCCAM requires that we absorb certain power cost increases before we are allowed to recover increases from customers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we typically under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms can have a significant effect on cash flows from operations and make year-to-year comparisons difficult. As ofDecember 31, 2019 , we have under collected our costs recovered through tracking mechanisms by approximately$32.5 million , as compared with an over collection of$1.5 million as ofDecember 31, 2018 . 47 --------------------------------------------------------------------------------
Cash Flows
The following table summarizes our consolidated cash flows for 2019 and 2018(in
millions):
Year Ended December 31,
2019 2018
Operating Activities
Net income $ 202.1 $ 197.0
Non-cash adjustments to net income 165.8 169.5
Changes in working capital (53.0 )
51.8
Other noncurrent assets and liabilities (18.2 ) (36.3 ) Cash Provided by Operating Activities 296.7
382.0
Investing Activities Property, plant and equipment additions (316.0 ) (284.0 ) Acquisitions - (18.5 ) Proceeds from sale of assets -
0.1
Investment in equity securities (0.1 ) (2.5 ) Cash Used in Investing Activities (316.1 )
(304.9 )
Financing Activities Proceeds from issuance of common stock, net -
44.8
Issuances of long-term debt 150.0 - Line of credit (repayments) borrowings, net (19.0 )
308.0
(Repayments) issuances of short-term borrowings, net - (319.6 ) Dividends on common stock (115.1 ) (109.2 ) Financing costs (1.1 ) (0.1 ) Other 1.4 2.3 Cash Provided by (Used in) Financing Activities 16.2
(73.8 )
Net (Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash
$ (3.2 ) $ 3.3
Cash, Cash Equivalents, and Restricted Cash, beginning of period $ 15.3 $
12.0
Cash, Cash Equivalents, and Restricted Cash, end of period $ 12.1 $ 15.3
Cash Flows Provided By Operating Activities
As ofDecember 31, 2019 , our cash, cash equivalents, and restricted cash were$12.1 million as compared with$15.3 million atDecember 31, 2018 . Cash provided by operating activities totaled$296.7 million for the year endedDecember 31, 2019 as compared with$382.0 million during 2018. This decrease in operating cash flows is primarily due to an under collection of supply costs from customers in 2019 as compared with an over collection in 2018, resulting in an approximate$35.5 million reduction in working capital, credits toMontana customers during 2019 related to the Tax Cuts and Jobs Act of approximately$20.5 million , transmission generation interconnection refunds in 2019 as compared with deposits in 2018 decreasing working capital by approximately$22.1 million , and the receipt of insurance proceeds of$6.1 million in 2018.
Cash Flows Used In Investing Activities
Cash used in investing activities totaled$316.1 million during the year endedDecember 31, 2019 , as compared with$304.9 million during 2018. Plant additions during 2019 include maintenance additions of approximately$225.6 million , and capacity related capital expenditures of approximately$90.4 million . Plant additions during 2018 include maintenance additions of approximately$227.0 million , capacity related capital expenditures of approximately$57.0 million , and the acquisition of the 9.7 MW Two Dot wind project inMontana for approximately$18.5 million . 48
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Cash Flows Provided by (Used in) Financing Activities
Cash provided by financing activities totaled$16.2 million during 2019 as compared to cash used in financing activities of$73.8 million during 2018. During 2019, net cash provided by financing activities reflects the proceeds from the issuance of debt of$150.0 million , offset in part by payments of dividends of$115.1 million and net repayments under our revolving lines of credit of$19.0 million . During 2018, net cash used in financing activities reflects net repayments of commercial paper of$319.6 million and the payment of dividends of$109.2 million , partially offset by net issuances under our revolving lines of credit of$308.0 million and proceeds from the issuance of common stock of$44.8 million . 49 --------------------------------------------------------------------------------
CRITICAL ACCOUNTING POLICIES AND ESTIMATES Management's discussion and analysis of financial condition and results of operations is based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates. We consider an estimate to be critical if it is material to the Consolidated Financial Statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period.
We have identified the policies and related procedures below as critical to understanding our historical and future performance, as these polices affect the reported amounts of revenue and are the more significant areas involving management's judgments and estimates.
Regulatory Assets and Liabilities
Our operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. This accounting treatment is impacted by the uncertainties of our regulatory environment, anticipated future regulatory decisions and their impact. If any part of our operations becomes no longer subject to the provisions of ASC 980, or facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery, we would record a charge to earnings, which could be material. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets. While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 4 - Regulatory Assets and Liabilities, to the Consolidated Financial Statements for further discussion.
Pension and Postretirement Benefit Plans
We sponsor and/or contribute to pension, postretirement health care and life insurance benefits for eligible employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 14 - Employee Benefit Plans, to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, the long-term nature of the obligations, and the importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
• Discount rates used in determining the future benefit obligations;
• Expected long-term rate of return on plan assets; and
• Mortality assumptions.
We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon market interest rates, past experience and management's best estimate of future economic conditions.
We set the discount rate using a yield curve analysis, which projects benefit
cash flows into the future and then discounts those cash flows to the
measurement date using a yield curve. This is done by constructing a
hypothetical bond portfolio whose cash flow from coupons and maturities matches
the year-by-year projected benefit cash flow from our plans. Based on this
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analysis as of
In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Our expected long-term rate of return on assets assumptions are 3.45% and 4.49% on theNorthWestern Corporation andNorthWestern Energy pension plan, respectively, for 2020.
Cost Sensitivity
The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):
Impact on Projected
Actuarial Assumption Change in Assumption Impact on Pension Cost Benefit Obligation
Discount rate increase 0.25 % $ (1,759 ) $ (23,476 )
Discount rate decrease (0.25 )% 1,843 24,793
Rate of return on plan assets
increase 0.25 % (1,280 ) N/A
Rate of return on plan assets
decrease (0.25 )% 1,280 N/A
Accounting Treatment
We recognize the funded status of each plan as an asset or liability in the
Consolidated Balance Sheets. Differences between actuarial assumptions and
actual plan results are deferred and are recognized into earnings only when the
accumulated differences exceed 10% of the greater of the projected benefit
obligation or the market-related value of plan assets, which reduces the
volatility of reported pension costs. If necessary, the excess is amortized over
the average remaining service period of active employees.
Due to the various regulatory treatments of the plans, our Consolidated
Financial Statements reflect the effects of the different rate making principles
followed by the jurisdictions regulating us. Pension costs in Montana and other
postretirement benefit costs in South Dakota are included in rates on a pay as
you go basis for regulatory purposes. Pension costs in South Dakota and other
postretirement benefit costs in Montana are included in rates on an accrual
basis for regulatory purposes. Regulatory assets have been recognized for the
obligations that will be included in future cost of service.
Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. As ofDecember 31, 2019 , we had approximately$182 million of consolidated NOLs prior to consideration of unrecognized tax benefits to offset federal taxable income in future years. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ significantly from these estimates. The interpretation of tax laws involves uncertainty. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material. The uncertainty and judgment involved in the determination and filing of income taxes is accounted for by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately$35.1 million as ofDecember 31, 2019 . The resolution of tax 51 --------------------------------------------------------------------------------
matters in a particular future period could have a material impact on our provision for income taxes, results of operations and our cash flows.
Qualifying Facilities Liability
Our electric QF liability consists of unrecoverable costs associated with contracts covered under PURPA that are part of a 2002 stipulation with the MPSC and other parties. Under the terms of these contracts, we are required to purchase minimum amounts of energy at prices ranging from$63 to$136 per MWH throughJune 2029 . Our estimated gross contractual obligation is approximately$630.8 million throughJune 2029 . A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately$508.2 million throughJune 2029 . We maintain an electric QF liability based on the net present value (discounted at 7.75%) of the difference between our estimated obligations under the QFs and the fixed amounts recoverable in rates. The liability was established based on certain assumptions and projections over the contract terms related to pricing, estimated output and recoverable amounts. Since the liability is based on projections over the next several years, actual output, changes in pricing, contract amendments and regulatory decisions relating to these facilities could significantly impact the liability and our results of operations in any given year. In assessing the liability each reporting period, we compare our assumptions to actual results and make adjustments as necessary for that period. One of the contracts contains variable pricing terms, which exposes us to price escalation risks. The estimated annual escalation rate for this contract is a key assumption and is based on a combination of historical actual results and market data available for future projections. In recording the electric QF liability, we estimated an annual escalation rate of 3% over the remaining term of the contract (throughJune 2024 ). The actual escalation rate changes annually, which could significantly impact the liability and our results of operations. NEW ACCOUNTING STANDARDS
See Note 2 - Significant Accounting Policies, to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards.
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