interest rate http://fimendurance.com/ Wed, 16 Mar 2022 12:55:15 +0000 en-US hourly 1 https://wordpress.org/?v=5.9 https://fimendurance.com/wp-content/uploads/2021/10/icon-5-120x120.png interest rate http://fimendurance.com/ 32 32 Buy-to-let lenders raise mortgage rates on cheapest fixed deals https://fimendurance.com/buy-to-let-lenders-raise-mortgage-rates-on-cheapest-fixed-deals/ Wed, 16 Mar 2022 12:25:53 +0000 https://fimendurance.com/buy-to-let-lenders-raise-mortgage-rates-on-cheapest-fixed-deals/ Annual mortgage costs for buy-to-let owners have risen by nearly £500 in as little as three months, new research shows. Since early December, the average two-year fixed contract for an owner with 40% deposit or capital has increased by 0.3%, from 1.76% to 2.06%. The rate hikes are fueled in part by the Bank of […]]]>

Annual mortgage costs for buy-to-let owners have risen by nearly £500 in as little as three months, new research shows.

Since early December, the average two-year fixed contract for an owner with 40% deposit or capital has increased by 0.3%, from 1.76% to 2.06%.

The rate hikes are fueled in part by the Bank of England’s decision to hike the base rate, first in December from 0.1% to 0.25%, then last month from 0.25% to 0.5%.

Homeowners are facing increases of up to £41 a month as the cost of buy-to-let fixed rate mortgages rises following the two recent base rate changes.

The Bank’s monetary policy committee is due to meet again on Thursday and could decide to raise the base rate further, with owners warned to expect further rate hikes.

Mortgage broker Property Master’s latest buy-to-let tracker analyzed 30 lenders, representing around 75% of total rental mortgages.

He said the 0.3% increase in two-year fixed rates would add an extra £41 per month or £492 per year to mortgage payments, for a homeowner with a £160,000 mortgage on an interest-only deal .

The increase was less severe for those opting for five-year fixed rate contracts.

According to Property Master, a typical five-year fixed rate rental mortgage covering 60% of a property’s value increased by 0.25%, from 1.98% to 2.23%.

For someone only paying interest on a £160,000 mortgage, that would equate to an extra £33 a month.

The cost of a standard variable rate (SVR) mortgage now stands at an average of 4.99%, also up 0.25% since the Bank of England raised the base rate for the first times in December.

Angus Stewart, Managing Director of Property Master, said: “Our team has had one of the busiest weeks ever to ensure our search systems are up to date with all the recent activity in this market. .

“Entire product lines have been pulled, then relaunched, by multiple lenders, but the result has generally been to increase the cost to owners.”

And things would have to get worse for owners before they get better.

“We are now in a rising interest rate environment and most commentators are expecting another rate hike next week when the Bank of England meets again on Thursday,” Stewart added.

“With inflation continuing to rise, exacerbated by global events, we expect further increases in base rates over the past few months.

“We can already see lenders preparing to raise rates again, further tightening the pressure on consumers and homeowners.”

Owners are encouraged to plan ahead and set their next deal

Homeowners coming to the end of their fixed rate contract, or on an adjustable rate or tracker mortgage, are encouraged to remortgage as soon as possible to limit the damage.

Mortgage deals are usually valid for three to six months, so fixed-rate homeowners can arrange to renew and lock in a rate at current rates before their current contract expires.

Despite rising averages, the best buy rates are still relatively low.

With further base rate hikes expected, buy-to-let interest rates are expected to continue to rise.

With further base rate hikes expected, buy-to-let interest rates are expected to continue to rise.

The lowest rate for a two-year fixed lease-purchase agreement for a mortgage covering 60% of the value of the property is currently 1.09% offered by The Mortgage Works.

While its pricing might be attractive, it also comes with a hefty extra charge of £4,239.

Someone with a £160,000 interest-only mortgage could expect to pay £150 every month if they add the fees to the mortgage.

However, that would mean they had added an additional £4,239 to the amount of their existing mortgage that would eventually need to be paid off.

Owners may be able to find a higher rate with a lower fee, or no fee, which would be cheaper overall.

> Compare rates and fees using the This is Money Mortgage Calculator

Chris Sykes, Mortgage Consultant at Private Finance, said: “Lenders tend to assess rate hikes before the base rate hike happens, which is why we’ve seen rates rise steadily over the over the past few weeks.”

“We suspect that the base interest rate will continue to rise given the dramatic inflation rates, and this will continue to have an upward impact on mortgage rates across the board.

“That said, there are some incredibly good rates on the market right now. However, the best available rates charge a 2% arrangement fee and therefore may not be the best rate for potential borrowers, so always consider the additional fee when making your decision.

For anyone with a mortgage due this year, the advice is to start looking for a new deal as soon as possible.

Mark Harris, managing director of mortgage broker SPF Private Clients, said: ‘Most homeowners have fixed rates, so any payment shock will come after those deals expire, when they find it will cost them more to remortgage on another product.

“Homeowners due to remortgage this year should plan six months ahead. Write down the end date of your existing deal, then start looking for a new deal up to six months before that, as many lenders will allow you to book a rate up to six months before you need it.

“Anyone whose rates mature in September and before should look now, preferably by consulting a broker.”

Do I have to pay prepayment charges and remortgage now?

With mortgage products lasting only a few days in some cases, borrowers fear they will miss out on the best fixed deals if rates continue to climb.

It’s essential to know exactly when your current contract ends, because leaving a fixed rate mortgage too soon can lead to prepayment charges of up to 5% of the total amount.

It may not be as simple as being exactly two or five years into the mortgage.

Some lenders, such as Nationwide, will fix for a number of years from the start date of the mortgage – also known as the completion date.

However, many fixed rate offers are fixed on a certain date, so you may find more or less time than you originally thought to fulfill your mortgage.

You can find this date on your mortgage offer letter or by contacting your lender. A mortgage broker should also be able to advise you on this.

Once you know this, you can plan to apply up to 6 months before your current contract expires.

However, if you’re currently on a fixed-rate mortgage and the deal doesn’t end for a year, you might be considering switching anyway.

The problem here is that you might be hit with prepayment charges.

Most fixed rate transactions come with a prepayment charge, which often ranges from 1-5% of the outstanding mortgage amount.

In some cases, the amount decreases as the mortgage transaction nears completion.

For example, while in the first year of a five-year mortgage contract, you may be slammed with a 5% charge, however, if you are in your final year, you may only be subject to a 5% charge. 1%.

Whether or not it’s financially prudent to absorb a prepayment charge to take advantage of current rates depends on your situation.

For example, how much would the prepayment charge be, your thoughts on medium and long-term interest rates, and how long you expect to own the property, etc.

buy to leave best buys

Some links in this article may be affiliate links. If you click on it, we may earn a small commission. This helps us fund This Is Money and keep it free to use. We do not write articles to promote products. We do not allow any business relationship to affect our editorial independence.

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World braces for Russian debt default as payment deadline approaches – live updates https://fimendurance.com/world-braces-for-russian-debt-default-as-payment-deadline-approaches-live-updates/ Wed, 16 Mar 2022 08:29:00 +0000 https://fimendurance.com/world-braces-for-russian-debt-default-as-payment-deadline-approaches-live-updates/ gHello. All eyes are likely on Russia today as the deadline for a $117 million coupon on the country’s sovereign bonds nears. An attempt to pay in rubles can be considered a default on the debt of Moscow. Later in the day, the Federal Reserve is expected to take its first steps towards tackling soaring […]]]>

gHello. All eyes are likely on Russia today as the deadline for a $117 million coupon on the country’s sovereign bonds nears. An attempt to pay in rubles can be considered a default on the debt of Moscow.

Later in the day, the Federal Reserve is expected to take its first steps towards tackling soaring inflation in the United States, by raising interest rates.

5 things to start your day

1) How Komarek took control of the lottery in the race against Camelot – and what it means for consumers The outside bet unexpectedly triumphed with its lottery bid, which will fall on the shoulders of a little-known tycoon

2) BNP Paribas lawyer who kept job after calling Asian colleague ‘Hu She’ quits French bank Emails also showed that the lead attorney referred to another employee as “Biryani”.

3) Germany to relight mothballed coal power plants One of Europe’s largest energy companies is examining which plants can be brought back online to reduce dependence on Russian gas

4) Elon Musk attributes soaring costs to Tesla’s price hike The cheapest car sold in Britain, the Model 3, is now £1,000 more at almost £44,000

5) War forces farmers to rethink GM crops Genetic modification could make Britain’s food system less susceptible to geopolitical unrest

What happened overnight

Asian stocks rose on Wednesday as investors awaited a widely expected decision from the U.S. Federal Reserve on interest rate policy.

Japan’s benchmark Nikkei 225 jumped 1.7% in morning trade to 25,784.71. Australia’s S&P/ASX 200 added 0.9pc to 7,160.00.

The South Korean Kospi gained 0.8pc to 2,641.23. Hong Kong’s Hang Seng rose 2.1% to 18,807.58, while the Shanghai Composite lost 0.4% to 3,050.59.

coming today

  • Business : Computacenter, 4imprint, Centamin, CLS Holdings, Ferrexpo, Fevertree, IP Group, Restaurant Group (full year); IG group (commercial update)
  • Economy: Federal Reserve interest rate decision, retail sales (WE)
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Supply: consumer resilience threatened by inflationary pressures https://fimendurance.com/supply-consumer-resilience-threatened-by-inflationary-pressures/ Sat, 12 Mar 2022 15:45:32 +0000 https://fimendurance.com/supply-consumer-resilience-threatened-by-inflationary-pressures/ US consumers continue to spend despite the end of federal stimulus programs last year. According to the US Census Bureau, retail sales in January were up 7.5% from a year ago. Holiday sales rose a record 14.1% last year, far exceeding expectations. Part of the sales gain was due to higher prices in everything from […]]]>

US consumers continue to spend despite the end of federal stimulus programs last year. According to the US Census Bureau, retail sales in January were up 7.5% from a year ago. Holiday sales rose a record 14.1% last year, far exceeding expectations.

Part of the sales gain was due to higher prices in everything from breakfast cereals to steak and wood. Economists warn retail sales data has not been adjusted for inflation, which could artificially boost sales figures for months to come.

With prices rising faster than expected in January, the Federal Open Market Committee has become more hawkish on interest rate hikes by March. St. Louis Federal Reserve Chairman James Bullard said he believed the first interest rate hike would be more aggressive than expected.

Randall Waldron, professor of economics at John Brown University, said consumers and businesses have so far managed inflationary pressures. That said, Waldron expects inflation to get worse before it gets better, which should weigh on consumer purchasing power in the first half of this year.

While savings rates have increased amid the pandemic, a recent Bankrate.com survey found that only 44% of consumers had enough savings to cover an unexpected $1,000 expense. While 20% would put payment on a credit card, 15% said they would cut costs elsewhere to cover the cost. One in 10 people would ask friends and family for help, and 4% would take out a personal loan.

Greg McBride, CFA, chief financial analyst for Bankrate, said the survey found borrowing remains high, with the majority of households needing help to cover a $1,000 expense.

Growing household debt is also a concern. Wells Fargo Securities economists reported household debt balances rose $333 million in the fourth quarter, marking the largest quarterly rise in nearly 15 years. Mortgage and credit card balances also saw the largest increases in the fourth quarter since before the pandemic. Consumer debt jumped in the fourth quarter to nearly $15.6 trillion.

Wells Fargo Securities chief economist Jay Bryson expects some inflationary prices to slow in the coming months as more spending shifts from goods to services.

“While the most immediate price distortions caused by the pandemic and the initial policy response dissipate, wage pressures continue to build and point to a more consistent source of inflation. The result is that inflation is likely to remain uncomfortably high. for consumers, businesses and the Fed,” Bryson said.

February consumer sentiment, according to the University of Michigan survey, indicates that consumer worries about inflation have risen to their highest level since 2008 and have weighed on consumers’ views on their household finances. housework.

Wells Fargo economists said the highest inflation in more than 40 years is challenging consumers’ disposable income, likely making them more cost-conscious. Wells Fargo also reported that consumer credit card debt rose $52 billion in the fourth quarter, the largest quarterly increase in the 22-year history of published data. Use of revolving credit cards rose just $2.1 billion in December, the smallest gain since April 2021, as consumers cut back on year-end spending.

“Inflationary headwinds on consumer activity are expected to accelerate through 2022, as evidenced by the recent deterioration in consumer sentiment,” Bryson said.

The University of Michigan’s preliminary consumer sentiment index for the first half of February fell to 61.7, its lowest level since October 2011. The decline in sentiment was entirely among households with incomes of 100,000 $ or more. The survey found that nearly half of consumers expect disposable income to decline over the year, as prices rise faster than wages. February’s sentiment reading also included fewer households citing savings wealth, which could result from falling stock prices this year and eroding incomes from rising prices of goods and services.

“Recent declines have been driven by weakening personal financial outlooks, largely due to higher inflation, lower confidence in government economic policies and the worst long-term economic outlook since. a decade,” said Richard Curtin, chief economist at the University. from Michigan.

Curtain said the decline in sentiment signaled the start of a sustained slowdown in consumer spending. However, the depth of the crisis is subject to several caveats that were not present in previous downturns, including the impact of unspent stimulus funds and the disruption to spending and work situations caused by the pandemic. He said households had amassed substantial savings from stimulus funds and limited consumption choices amid the pandemic. But rising interest rates and price inflation will erode savings.

The National Retail Federation (NRF) said there were near-term challenges with inflationary pressures, labor shortages, the impacts of COVID-19 and uncertainty related to international tensions in Russia and China.

Through January, retail spending held up, indicating consumers are resisting near-term inflationary pressures, according to NRF CEO Matthew Shay. The trade group is bullish on consumer spending as economic forces are expected to moderate later this year.

This sentiment contrasts with consumer data released by Deloitte in January. Deloitte found that consumers felt more prudent about their spending, not because of Omicron, but because of higher prices. The proportion of consumers who also expressed concerns about savings has intensified compared to last fall. Deloitte reports that 68% of survey respondents said they faced rising grocery prices in January and their intentions to buy new vehicles dropped to 16%.

Another report from Resonate found that 34% of consumers have less discretionary income, and nearly four in five cite best prices as the criteria for selecting the #1 retailer. Although they have a long list of wish list, they need to keep it affordable.

Editor’s note: The side section offers of Talk Business & Politics focuses on the businesses, organizations, issues and individuals engaged in providing products and services to retailers. The Supply Side is managed by Talk Business & Politics and sponsored by Propak logistics.

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GOAT.Finance Launches BSC’s Highest Automatic Fixed APY https://fimendurance.com/goat-finance-launches-bscs-highest-automatic-fixed-apy/ Fri, 11 Mar 2022 10:47:49 +0000 https://fimendurance.com/goat-finance-launches-bscs-highest-automatic-fixed-apy/ Sacramento, California, USA, March 11, 2022 (GLOBE NEWSWIRE) — Decentralized finance (or DeFI) is a financial revolution and represents the future of finance and funding. Holders and investors of GOAT.Finance can achieve returns that seem impossible in the financial world. The tool that DeFi companies use to create these high returns are financial algorithms and […]]]>

Sacramento, California, USA, March 11, 2022 (GLOBE NEWSWIRE) — Decentralized finance (or DeFI) is a financial revolution and represents the future of finance and funding. Holders and investors of GOAT.Finance can achieve returns that seem impossible in the financial world. The tool that DeFi companies use to create these high returns are financial algorithms and token staking strategies.

Defi 1.0 introduced different staking strategies that attracted millions of investors and built many of the top performers in crypto. GOAT.Finance with Defi 2.0 promises token holders greater simplicity and security in staking, and the best fixed returns as well as BUSD rewards.

Goat.Finance developers have introduced Autostaking, a DeFi 2.0 protocol that offers perhaps the best set of benefits for holders in the industry.

Direct Debit Protocol – Safe, Fast, Highest Fixed APY, BUSD Rewards

GOAT.Finance offers token holders simplicity, security, and consistently high returns through Auto Staking. It brings various benefits;

Easy and safe staking – The GOAT token always stays in your wallet and you automatically receive rewards. No more complicated staking processes on someone else’s website.

Automatic Rebase Rewards – You never have to worry about reinvesting your tokens. Rewards are base-changing, meaning they automatically accumulate, ensuring you never miss a payment.

Highest Fixed APY – Goat.Finance auto-staking protocol pays out 150,000% per year, which is a constant compound interest rate that tops the DeFi industry (and every other industry in the world).

Fastest Rebase Rewards – Goat.Finance’s automatic staking protocol pays out every thirty minutes or 48 times a day.

BUSD Rewards – GOAT token holders reward 4% of all trades as BUSD rewards.

How GOAT.Finance offers its best fixed APY of 150,000%

The Goat.Finance Autostaking protocol uses a complex set of elements to deliver its industry-leading APY. They include GOAT.Finance cash, trading volume fees, and risk-free value (RFV). They all work in harmony to provide a high and fixed APY.

· Rebase rewards are backed by RFV reserves and part of the Treasury.

4% of every buy and sell goes to the treasury, which increases the balance of GOAT tokens in circulation and provides a large marketing budget.

5% of every buy and sell automatically goes to the BNB/GOAT liquidity pool on PancakeSwap.

4% of GOAT.Finance’s trading volume is redirected to the protocol’s risk-free value (RFV). The function of the RFV is to support the rebase rewards of the GOAT token.

The project support system is designed in such a way that RFV allows the purchase and burning of GOAT tokens on the secondary market when the supply of pairs is 2.5% of the total supply.

This combination of factors distributes an automatic rebase reward every 30 minutes and ensures a return of 0.00417% per rebase or 2% per day for GOAT token holders.

About GOAT.Finance

GOAT.Finance is a DeFi development company that creates next-generation products and services. Their auto-staking protocol is the foundation for a series of DeFi 2.0 projects starting with the GOAT token that automatically stakes and compounds in your wallet, and offers the industry’s best fixed APY of 150,000%. GOAT.Finance will develop projects, products and protocols that will bring cutting-edge benefits to GOAT Token holders.

Social link :

Twitter: https://twitter.com/GoatFinanceDeFi

Reddit: https://reddit.com/user/GoatFinanceDeFi

Telegram: https://t.me/goatfinancebsc

Website: https://goatbsc.finance

        

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10-year fixed-rate student loans slide after three weeks of uptrend https://fimendurance.com/10-year-fixed-rate-student-loans-slide-after-three-weeks-of-uptrend/ Wed, 09 Mar 2022 20:37:28 +0000 https://fimendurance.com/10-year-fixed-rate-student-loans-slide-after-three-weeks-of-uptrend/ Our goal at Credible Operations, Inc., NMLS Number 1681276, hereafter referred to as “Credible”, is to give you the tools and confidence you need to improve your finances. Although we promote the products of our partner lenders, all opinions are our own. Credible Market’s latest private student loan interest rates, updated weekly. (Stock) Average private […]]]>

Our goal at Credible Operations, Inc., NMLS Number 1681276, hereafter referred to as “Credible”, is to give you the tools and confidence you need to improve your finances. Although we promote the products of our partner lenders, all opinions are our own.

Credible Market’s latest private student loan interest rates, updated weekly. (Stock)

Average private student loan rates decreased for 10-year fixed rates and increased for 5-year variable rates for borrowers with credit scores of 720 or higher who used the Credible Marketplace to take out student loans during the week of February 28, 2022 :

  • 10-year fixed rate: 6.03%, compared to 6.19% the previous week, -0.16
  • 5-year variable rate: 4.49%, compared to 4.04% the previous week, +0.45

With Credible, you can compare private student loan rates from lenders without affecting your credit score.

10-year fixed student loan rates fell this week after rising for three straight weeks, while 5-year variable rates rose. Both rates are well below their 2022 highs so far; 10-year fixed rate student loans were 6.75% the week of January 17 and 5-year variable rates were 4.77% the week of January 24.

You should always exhaust federal student loan options before turning to private student loans to cover any funding shortfalls. Private lenders such as banks, credit unions, and online lenders offer private student loans. You can use private loans to pay for education and living expenses, which may not be covered by your federal student loans.

Private student loan interest rates and terms may vary depending on your financial situation, credit history and the lender you choose.

Take a look at the rates from Credible Partner Lenders for borrowers who used the Credible Marketplace to select a lender during the week of February 21:

Private student loan rates (diploma and undergraduate)

Student Loan Weekly Rate Trends

9-mars-loan-student-graph.jpg

Who sets federal and private interest rates?

Congress sets interest rates for federal student loans each year. These fixed interest rates depend on the type of federal loan you take out, your dependent status, and your school year.

Private student loan interest rates can be fixed or variable and depend on your credit, repayment term and other factors. Generally, the better your credit score, the lower your interest rate is likely to be.

You can compare rates from multiple student lenders using Credible.

How does student loan interest work?

An interest rate is a percentage of the loan periodically added to your balance – essentially the cost of borrowing money. Interest is a way lenders make money from loans. Your monthly payment often pays interest first, with the rest going to the amount you originally borrowed (the principal).

Getting a low interest rate could help you save money over the life of the loan and pay off your debt faster.

What is a fixed rate or variable rate loan?

Here is the difference between a fixed rate and a variable rate:

  • With a fixed rate, your monthly payment amount will remain the same for the duration of your loan.
  • With a floating rate, your payments can go up or down as interest rates change.

Comparative purchases for private student loan rates is easy when you use Credible.

Calculate your savings

Using a student loan interest calculator help you estimate your monthly payments and the total amount you will owe over the term of your federal or private student loans.

Once you’ve entered your information, you’ll be able to see what your estimated monthly payment will be, the total you’ll pay in interest over the term of the loan, and the total amount you’ll repay.

About Credible

Credible is a multi-lender marketplace that allows consumers to discover the financial products best suited to their particular situation. Credible’s integrations with major lenders and credit bureaus allow consumers to quickly compare accurate and personalized loan options without putting their personal information at risk or affecting their credit score. The Credible Marketplace delivers an unparalleled customer experience, as evidenced by over 4,300 positive Trustpilot reviews and a TrustScore of 4.7/5.

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HIGHWATER ETHANOL LLC Management’s Discussion and Analysis of Financial Condition and Results of Operations (Form 10-Q) https://fimendurance.com/highwater-ethanol-llc-managements-discussion-and-analysis-of-financial-condition-and-results-of-operations-form-10-q/ Wed, 09 Mar 2022 19:44:02 +0000 https://fimendurance.com/highwater-ethanol-llc-managements-discussion-and-analysis-of-financial-condition-and-results-of-operations-form-10-q/ We have prepared the following discussion and analysis to help you better understand our financial condition, changes in our financial condition and results of operations for the three-month period ended January 31, 2022, compared to the same period of the previous year. This discussion should be read in conjunction with the condensed financial statements and […]]]>

We have prepared the following discussion and analysis to help you better understand our financial condition, changes in our financial condition and results of operations for the three-month period ended January 31, 2022, compared to the same period of the previous year. This discussion should be read in conjunction with the condensed financial statements and notes and disclosures contained in the company’s annual report on Form 10-K for the year ended October 31, 2021.

Forward-looking statements

This report contains forward-looking statements that involve future events, our future performance, and our expected future operations and actions. In some cases, you can identify forward-looking statements by using words such as “will”, “may”, “should”, “anticipate”, “believe”, “expect”, “plan”, “future” , “intend”, “could”, “estimate”, “predict”, “hope”, “potential”, “continue”, or the negative form of these terms or other similar expressions. These forward-looking statements are only our predictions and involve numerous assumptions, risks and uncertainties. Many factors could cause actual results to differ materially from those projected in the forward-looking statements. While it is impossible to identify all of these factors, factors that could cause actual results to differ materially from those estimated by us include, but are not limited to:

      Changes in the availability and price of corn and natural gas;
      Reduction or elimination of the Renewable Fuel Standard;
      Volatile commodity and financial markets;
      Changes in legislation benefiting renewable fuels;
      Our ability to comply with the financial covenants contained in our credit agreements
      with our lenders;
      Our ability to profitably operate the ethanol plant and maintain a positive spread
      between the selling price of our products and our raw material costs;
      Results of our hedging activities and other risk management strategies;
      Ethanol and distillers grains supply exceeding demand and corresponding price
      reductions;
      Our ability to generate cash flow to invest in our business and service our debt;
      Changes in the environmental regulations that apply to our plant operations and changes
      in our ability to comply with such regulations;
      Changes in our business strategy, capital improvements or development plans;
      Changes in plant production capacity or technical difficulties in operating the plant;
      Changes in general economic conditions or the occurrence of certain events causing an
      economic impact in the agriculture, oil or automobile industries;
      Lack of transportation, storage and blending infrastructure preventing ethanol from
      reaching high demand markets;
      Changes in federal and/or state laws or policies impacting the ethanol industry;
      Changes and advances in ethanol production technology and the development of
      alternative fuels and energy sources and advanced biofuels;
      Competition from alternative fuel additives;
      Changes in interest rates and lending conditions;
      Decreases in the price we receive for our ethanol and distillers grains;
      Our inability to secure credit or obtain additional equity financing we may require in
      the future;
      Our ability to retain key employees and maintain labor relations;
      Changes in the price of oil and gasoline;
      Competition from clean power systems using fuel cells, plug-in hybrids and electric
      cars;
      International trade disputes and the imposition of tariffs by foreign governments on
      our products;
      Use by the EPA of small refinery exemptions; and
      A slowdown in global and regional economic activity, reduced demand for our products
      and the potential for labor shortages and shipping disruptions resulting from the
      COVID-19 pandemic.


The disclaimers mentioned in this section should also be considered in connection with any subsequent written or oral forward-looking statements that may be made by us or by persons acting on our behalf. We undertake no obligation to update any forward-looking statements contained in this report. Further, we cannot guarantee future results, activity levels, performance or achievements. We caution you not to place undue reliance on forward-looking statements, which

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speak only as of the date of this report. You should read this report and the documents we refer to in this report and have filed as exhibits in their entirety and with the understanding that our actual future results may differ materially from what we currently anticipate. We qualify all of our forward-looking statements with these cautionary statements.

Information available

Our website address is www.highwaterethanol.com. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and any amendments to such reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), are available, free of charge, on our website at www.highwaterethanol.com under the link “SEC Compliance”, as soon as reasonably possible after we have electronically filed such documents or provided such materials for, the Security and Exchange Commission. The content of our website is not incorporated by reference into this Quarterly Report on Form 10-Q.

Overview

Highwater Ethanol, LLC (“we”, “our”, “Highwater Ethanol” or the “Company”) has been incorporated as Minnesota limited liability company organized on May 2, 2006for the purpose of constructing, owning and operating an ethanol plant near
Lamberton, MN. Since August 2009, we have been engaged in the production of ethanol and distillers grains at the plant. In October 2019our application for an air permit at Minnesota Pollution Control Agency to allow 70.2 million gallons of denatured ethanol per 12-month rolling average was approved.

At August 26, 2020we have reached an agreement with Nelson Baker BioTech, Inc. to install a system that will allow us to produce high purity USP grade alcohol for use in the disinfectant market. We started construction in November 2020. The project was completed in October 2021 and a limited production of high-purity alcohol began. However, we only had limited production of high purity alcohol in our fiscal year 2021 due to the current positive margins in ethanol. We expect to begin sales in our fiscal year 2022. We have entered into an agreement with RPMG, Inc. (“RPMG”) to be the exclusive distributor of our high purity alcohol. RPMG is currently our exclusive distributor and distributor of ethanol and corn oil. We also own Renewable Products Marketing Group, LLCthe parent entity of RPMG.

At November 17, 2021our Board of Governors declared a cash distribution of
$1,500 per subscription unit to unitholders of record at the close of business on
November 17, 2021for a total distribution of $7,158,750. The distribution was paid on December 17, 2021.

At January 19, 2022our Board of Governors declared a cash distribution of
$2,300 per subscription unit to unitholders of record at the close of business on
December 31, 2021for a total distribution of $10,972,150. The distribution was paid on February 11, 2022.

At February 8, 2022we have executed a First Amendment to the Third Amended and Restated Credit Agreement (the “First Amendment”), which amends the Third Amended and Restated Credit Agreement dated March 15, 2021 with Compeer Financial, PCA f/k/a AgStar Financial Services, PCA, as administrative agent (“Compeer”). The first amendment was primarily intended to change the interest rate of the revolving term loan and revolving line of credit, effective March 1, 2022. The First Amendment deleted references to the LIBOR rate and provided that the Term Revolving Loan and the Revolving Line of Credit will each bear interest at a variable interest rate based on the wall street journal Prime rate plus ten basis points with a minimum interest rate of 2.10%. The revolving line of credit loan, which was due to mature on March 15, 2022has also been extended to January 22, 2023. We expect to finance our operations over the next 12 months using cash flow from our continuing operations and our existing credit facilities. However, if we encounter adverse operating conditions in the ethanol industry that prevent us from operating the ethanol plant profitably, we may need to seek additional funds.



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© Edgar Online, source Previews

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Differences between debit, credit and “pay later” cards https://fimendurance.com/differences-between-debit-credit-and-pay-later-cards/ Sun, 06 Mar 2022 20:06:13 +0000 https://fimendurance.com/differences-between-debit-credit-and-pay-later-cards/ Adhil Shetty, CEO of BankBazar.com, says, “While debit cards let you access your existing funds in a savings bank account, credit cards let you access credit. Line of credit cards or “pay later” cards are the ones that let you make purchases and then split the bill into three or more installments.” For example, “pay […]]]>

Adhil Shetty, CEO of BankBazar.com, says, “While debit cards let you access your existing funds in a savings bank account, credit cards let you access credit. Line of credit cards or “pay later” cards are the ones that let you make purchases and then split the bill into three or more installments.”

For example, “pay later” cards allow you to spread your monthly expenses evenly over three months at no additional cost. On the other hand, Uni “pay later” cards go beyond the transaction level. In the case of Uni, you can choose which transactions you want to pay in full and pay the rest over the next three months. “Pay later” cards issued by fintech companies often focus on millennials who are digitally active but lack a credit history. Fintech companies give them these cards with a credit limit as low as 2,000. However, the card limit increases dynamically over a period as they spend more and pay off the bill on time.

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Paras Jain/Mint

Credit cards vs “pay later”

Pay later cards are an emerging form of small loans bundled into a card, aimed at millennials and Gen Z customers. In contrast, credit card issuers have specific predefined eligibility criteria. This way, consumers with no credit history or those with very meager incomes can get a “pay later” card. However, obtaining a credit card depends on the individual’s creditworthiness, repayment behavior and income stability.

Raj Khosla, founder and managing director of MyMoneyMantra.com, says the extended credit limit on a “pay later” card is usually relatively lower than that offered on a credit card. On a “pay later” card, the credit limit starts from 2,000 and can go up to a maximum of 10 lakh, while credit limits on a credit card usually start from 20,000. There is no upper cap on credit card limits because the lender can increase your credit limit based on your usage, income, and frequency of spending.

“Currently, ‘pay later’ cards only offer the option of splitting the transaction amount into three equal installments, while credit cards offer the option of longer equivalent monthly installments (EMIs) that can be s ‘extend up to 36 months,’ Khosla added.

Also, with “pay later” cards, you don’t have to pay recurring interest, i.e. there are no interest charges applied on new purchases during that you make a partial refund of the invoice. However, in the case of credit cards, if you make late or partial payments, interest is charged from the date of the transaction. Sachin Vasudeva, Associate Director and Head of Credit Cards, Paisbaazaar.com, says the biggest drawback of a credit card is the high interest rate on revolving credit. This means that even a few missed payments can send you into a spiral of debt. “Credit cards with revolving credit interest rate finance charges are significantly high at 30% to 45% per year, while “pay later” cards charge 20% to 30% (non-renewable) in case of non-payment,” says Vasudeva. .

Yet, the benefits and rewards offered on a credit card are generally higher and more diverse than the benefits available on a “pay later” card. Pay later cards offer approximately 1% cash back on timely bill payment; Credit cards offer several other benefits such as cash back, rewards points, discounts and airline miles. says Khosla, “Users can choose the type of credit card based on their spending habits to get maximum benefits, while the benefits of ‘pay later’ cards are similar across the board.”

Debit Cards vs Credit Cards/Pay Later

Debit cards, credit cards, and “pay later” cards are all different payment options. “Comparing debit cards with credit or pay-after cards is completely unfair, as the former represent your money in bank accounts, while credit and pay-after cards are a form of unsecured lending. which is grouped in a plastic (card). “In addition, after transactions made with credit cards and “pay later” cards, you are still obligated to honor future bills. In contrast, debit card payments mean that you settle the transaction immediately after have spent.

Vasudeva says, “Because debit cards are directly linked to your savings or checking account, they are best used for small expenses and ATM withdrawals, usually those you can prepay without deplete your savings. Debit cards allow you to withdraw cash from ATMs for free. But withdrawing money using a credit card or “pay later” card will incur high interest rates because these transactions are treated as cash advances.”

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You can use these cards at online and offline stores, ATMs, and point-of-sale (PoS) terminals. The benefits and rewards associated with these cards are purely subjective to the nature of the transaction. To get the maximum benefits, you should use these cards interchangeably depending on the nature of the transactions you make.

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First issuance of a green loan to optimize the capital structure and finance future growth https://fimendurance.com/first-issuance-of-a-green-loan-to-optimize-the-capital-structure-and-finance-future-growth/ Mon, 28 Feb 2022 06:42:18 +0000 https://fimendurance.com/first-issuance-of-a-green-loan-to-optimize-the-capital-structure-and-finance-future-growth/ DGAP-News: Pacifico Renewables Yield AG / Key word(s): Financing/Sustainability28.02.2022 / 07:30 The issuer is solely responsible for the content of this announcement. Pacifico Renewables Yield AG: First Green Loan Issuance to Optimize Capital Structure and Fund Further Growth Green loan private placement of 35 million euros with a fixed interest rate of 4.85% and a […]]]>

DGAP-News: Pacifico Renewables Yield AG / Key word(s): Financing/Sustainability
28.02.2022 / 07:30
The issuer is solely responsible for the content of this announcement.

Pacifico Renewables Yield AG: First Green Loan Issuance to Optimize Capital Structure and Fund Further Growth

  • Green loan private placement of 35 million euros with a fixed interest rate of 4.85% and a term of 5 years

  • First green financial instrument issued under the Green Finance Framework recently implemented by the Group

  • Refinancing of existing debt demonstrates continued optimization of capital structure

  • Additionally provides funding for building a new portfolio

Gruenwald, February 28, 2022 – On February 26, Pacifico Renewables Yield AG (ISIN: DE000A2YN371) (“Pacifico Renewables”, or the “Group”), an independent producer of electricity from renewable sources, signed, through a subsidiary, a first guaranteed green loan private placement of 35 million euros with UBS Asset Management. The fixed interest rate of the green loan is 4.85% and there is no interest rate exposure. The duration of the financing is five years from the signature with a repayment in fine.

Optimized capital structure

Around 26 million euros will be used to reduce existing debt and optimize the Group’s capital structure. Of this amount, approximately €9.3 million will be used to refinance an existing subordinated debt facility with an interest rate approximately one percentage point higher than the signed private placement. The refinancing of this subordinated debt facility also enables a simplification of the corporate structure resulting in significant cost savings. An additional approximately €16.5 million will be used to refinance the Group’s revolving credit line, thereby optimizing the Group’s refinancing profile by replacing a short-term line with longer-term financing. The fixed interest rate further reinforces the Group’s high sensitivity to interest rates.

Accretive financing of portfolio construction

The rest of the net proceeds will be used to finance the further construction of the Group’s existing portfolio and new acquisitions. Given the Group’s close cooperation with developers and the high visibility on growth opportunities, the Group’s management is comfortable deploying net proceeds in an accretive manner.

Co-CEO Dr Martin Siddiqui summarizes: “We are proud to be able to issue such a large private placement with a reputable investor such as UBS Asset Management. For a young company like ours, this demonstrates our ability to grow by exploiting a variety of sources. financing and to ensure growth for our shareholders by constantly optimizing our capital structure. After having initially financed growth mainly by raising equity, we consider this private placement as a historical transaction for our company, and it demonstrates our ability to effectively fund growth using different sources of capital. With UBS Asset Management, we have found a highly professional partner with whom we are excited to explore other funding opportunities in the future.”

Alessandro Merlo, Head of Investment, Infrastructure Debt at UBS-AM REPMsaid, “Our investment in Pacifico Renewables represents an exciting opportunity for UBS-AM to fund its ambitious expansion plans, aiming to more than double production capacity in the coming years, and we look forward to supporting Pacifico Renewables in this adventure. The transaction also highlights the broader demand we are seeing in infrastructure markets for investments to support expansion and meet sustainability goals, and we look forward to announcing further transactions in this space at the future “.

First issue under the Group’s new Green Finance Framework[1]

Green finance instruments that may be issued under the Green Finance Framework (the “Framework”) include (among others) bonds, private placements and loan facilities. The Framework defines the use of products by the Group, including its eligibility criteria, product management, evaluation and selection criteria as well as its commitments in terms of annual reporting and external verification. Proceeds from green finance instruments issued under the framework will only be invested in projects that are fully aligned with the ICMA Green Bond Principles[2] and EU taxonomy[3]. The Group has set up a Green Finance Committee which will select and assess projects likely to be added to its portfolio of eligible projects. Finally, the Group will publish annual allocation and impact reports on its website in order to keep stakeholders informed of the actual use of revenues. The award report will be independently verified by a third party.

The Group’s Green Finance Framework received a second part opinion by ISS ESG[4] which found that Pacifico Renewables’ green finance framework is fully aligned with both the ICMA Green Bond Principles and the EU Taxonomy.

“Having successfully completed several equity financings in the recent past, we are proud to see that our first green debt raising has been well received by debt investors. This demonstrates confidence in our business model and the future growth potential for equity and debt investors.We are also delighted to be able to use our new green financing framework for the first time with this green debt issuance.Finally, the fact that we have been able to issue a green instrument aligned with ICMA’s Green Bond Principles and EU Taxonomy, as verified by ISS ESG, shows that our decision to focus on sustainability from the start has paid off,” says Christoph Strasser, co-CEO.

ABN AMRO acted as Sole Arranger and Sole Placement Agent/Green Structuring Advisor and Linklaters LLP provided legal advice to Pacifico Renewables in connection with the financing.

About Pacifico Renewables Yield AG

Pacifico Renewables Yield AG is an independent power producer listed on the open market of the Düsseldorf Stock Exchange with additional requirements (Primärmarkt) (ISIN: DE000A2YN371) with the aim of building a gradually growing portfolio of power generation facilities from renewable sources. With operational wind and photovoltaic power plants spread across Europe, the Company offers a clear and diversified profile with stable and predictable revenues.

Warning

This announcement does not constitute an offer or a solicitation of an offer to buy securities of Pacifico Renewables Yield AG or any of its subsidiaries. The titles have already been sold.

This announcement may contain certain forward-looking statements, estimates, opinions and forecasts regarding the future business condition, earnings condition and results of Pacifico Renewables Yield AG (“forward-looking statements”). Forward-looking statements can be identified by words such as “believe”, “estimate”, “anticipate”, “expect”, “intend”, “will” or “should” and their negation and variations similar or comparable terminology. Forward-looking statements include all matters that are not historical facts. Forward-looking statements are based on the current opinions, forecasts and assumptions of the board of directors of Pacifico Renewables Yield AG and involve important known and unknown risks and uncertainties. Therefore, actual results, performance and events may differ materially from those expressed or implied by looking at the statements. The forward-looking statements contained herein should not be construed as guarantees of future performance or results and are not necessarily reliable indicators of whether or not such results will be achieved. The forward-looking statements contained in this press release speak only as of the date of this publication. Pacifico Renewables Yield AG will not update the information, forward-looking statements or conclusions contained in this release in light of subsequent events or circumstances, nor will it reflect subsequent events or circumstances or correct any inaccuracies that arise after the date of this release as a result of new information, future developments or otherwise, and the company assumes no obligation to do so. The Company assumes no responsibility for the realization of any forward-looking statements or assumptions contained herein.

[1] Pacifico Renewables Investor Relations

[2] ICMA Green Bond Principles

[3] EU taxonomy

[4] ISS ESG

28.02.2022 Broadcast of a Corporate News, transmitted by the DGAP – a service of EQS Group AG.
The issuer is solely responsible for the content of this announcement.

DGAP distribution services include regulatory announcements, financial/corporate news and press releases.
Archive at www.dgap.de

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IRIDIUM COMMUNICATIONS INC. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Form 10-K) https://fimendurance.com/iridium-communications-inc-managements-discussion-and-analysis-of-financial-condition-and-results-of-operations-form-10-k/ Thu, 17 Feb 2022 12:06:05 +0000 https://fimendurance.com/iridium-communications-inc-managements-discussion-and-analysis-of-financial-condition-and-results-of-operations-form-10-k/ A discussion regarding our financial condition and results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019 can be found in Part II, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the year ended […]]]>
A discussion regarding our financial condition and results of operations for the
year ended December 31, 2020 compared to the year ended December 31, 2019 can be
found in Part II, Item 7 "Management's Discussion and Analysis of Financial
Condition and Results of Operations" of our Annual Report on Form 10-K for the
year ended December 31, 2020, as filed with the SEC on February 11, 2021.

Fund


We were initially formed in 2007 as GHL Acquisition Corp., a special purpose
acquisition company. In 2009, we acquired all the outstanding equity in Iridium
Holdings LLC and changed our name to Iridium Communications Inc.

Overview of our company


We are engaged primarily in providing mobile voice and data communications
services using a constellation of orbiting satellites. We are the only
commercial provider of communications services offering true global coverage,
connecting people, organizations and assets to and from anywhere, in real time.
Our unique L-band satellite network provides reliable communications services to
regions of the world where terrestrial wireless or wireline networks do not
exist or are limited, including remote land areas, open ocean, airways, the
polar regions and regions where the telecommunications infrastructure has been
affected by political conflicts or natural disasters.

We provide voice and data communications services to businesses, the U.S. and
foreign governments, non-governmental organizations and consumers via our
satellite network, which has an architecture of 66 operational satellites with
in-orbit and ground spares and related ground infrastructure. We utilize an
interlinked mesh architecture to route traffic across the satellite
constellation using radio frequency crosslinks between satellites. This unique
architecture minimizes the need for ground facilities to support the
constellation, which facilitates the global reach of our services and allows us
to offer services in countries and regions where we have no physical presence.

We sell our products and services to commercial end users through a wholesale
distribution network, encompassing approximately 100 service providers, 285
value-added resellers, or VARs, and 85 value-added manufacturers, or VAMs, who
either sell directly to the end user or indirectly through other service
providers, VARs or dealers. These distributors often integrate our products and
services with other complementary hardware and software and have developed a
broad suite of applications for our products and services targeting specific
lines of business.

At December 31, 2021 we had approximately 1,723,000 billable subscribers
worldwide, an increase of 247,000, or 17%, from approximately 1,476,000 billable
subscribers at December 31, 2020. We have a diverse customer base, including end
users in land-mobile, Internet of Things, or IoT, maritime, aviation and
government.

We recognize revenue from both the provision of services and the sale of
equipment. Service revenue represented 80% and 79% of total revenue for the
years ended December 31, 2021 and 2020, respectively. Voice and data and IoT
data service revenues have historically generated higher margins than subscriber
equipment revenue, and we expect this trend to continue. We also recognize
revenue from our hosted payloads, principally Aireon, including fees for hosting
the payloads and fees for transmitting data from the payloads over our network,
as well as revenue from other services, such as satellite time and location
services.

Service Agreements for Satellite Constellation Upgrade

In 2019, we completed the full replacement of our first generation satellites with our upgraded constellation at a cost of approximately $3 billion.


In June 2010, we executed a primarily fixed price full scale development
contract, or FSD, with Thales Alenia Space for the design and manufacture of
satellites for the upgraded constellation. The total price under the FSD was
$2.3 billion. Final payments under this contract were made during the second
quarter of 2019. These costs were capitalized as construction in progress within
property and equipment, net in the accompanying consolidated balance sheets.

To complete the upgraded constellation, we launched a total of 75 satellites
into low earth orbit using eight Falcon 9 rockets under two contracts with Space
Exploration Technologies Corp., or SpaceX, with a total price of $510.8 million.
Final payments to SpaceX for these launches were made during the second quarter
of 2019. These costs were capitalized as
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construction in progress in property, plant and equipment, net in the accompanying consolidated balance sheets. We shared a launch with GFZ German Research Center for Geosciences for which we received $29.8 million of them.

term loan


In November 2019, we borrowed our $1,450.0 million Term Loan with an
accompanying $100.0 million revolving loan available to us, or the Revolving
Facility. Both facilities are under a credit agreement with the lenders, or the
Credit Agreement. We used the proceeds of the Term Loan, along with our debt
service reserve account and cash on hand to repay in full all of the
indebtedness outstanding under a previous credit facility with a syndicate of
bank lenders guaranteed by Bpifrance Assurance Export S.A.S., or the BPIAE
Facility, as well as related expenses.

In February 2020, we borrowed an additional $200.0 million under our Term Loan
and used the proceeds and approximately $183.5 million of cash on hand to repay
in full all of the indebtedness outstanding under senior unsecured promissory
notes, or the Notes, including premiums for early repayment.

In January 2021 and July 2021, we repriced all borrowings outstanding under our
Term Loan and incurred third-party financing costs of $3.6 million and
$1.3 million, respectively. As repriced, the Term Loan bears interest at an
annual rate of LIBOR plus 2.50%, with a 0.75% LIBOR floor. All other terms of
the Term Loan remain the same as before the repricing, including maturity in
November 2026. The Revolving Facility bears interest at an annual rate of LIBOR
plus 3.75% (but without a LIBOR floor) if and as drawn, with no original issue
discount, a commitment fee of 0.5% per year on the undrawn amount, and a
five-year maturity. See   Note 7   to the consolidated financial statements
included in this annual report for further discussion of our Term Loan.

As of December 31, 2021, we reported an aggregate balance of $1,621.1 million in
borrowings under the Term Loan, before $23.1 million of net deferred financing
costs, for a net principal balance of $1,598.0 million outstanding in our
consolidated balance sheet. We have not drawn on our Revolving Facility.

Our Term Loan contains no financial maintenance covenants. With respect to the
Revolving Facility, we are required to maintain a consolidated first lien net
leverage ratio of no greater than 6.25 to 1 if more than 35% of the Revolving
Facility has been drawn. The Credit Agreement contains other customary
representations and warranties, affirmative and negative covenants, and events
of default. We were in compliance with all covenants under the Credit Agreement
as of December 31, 2021.

The Credit Agreement restricts our ability to incur liens, engage in mergers or
asset sales, pay dividends, repay subordinated indebtedness, incur indebtedness,
make investments and loans, and engage in other transactions as specified in the
Credit Agreement. The Credit Agreement provides for specified exceptions,
including baskets measured as a percentage of trailing twelve months of earnings
before interest, taxes, depreciation and amortization, or EBITDA, and unlimited
exceptions based on achievement and maintenance of specified leverage ratios,
for, among other things, incurring indebtedness and liens and making
investments, restricted payments for dividends and share repurchases, and
payments of subordinated indebtedness. The Credit Agreement permits repayment,
prepayment, and repricing transactions and requires quarterly principal payments
of 0.25% of the $1.65 billion principal amount as of February 2020. The Credit
Agreement also contains a mandatory prepayment sweep mechanism with respect to a
portion of our excess cash flow (as defined in the Credit Agreement), which is
phased out based on achievement and maintenance of specified leverage ratios. As
of December 31, 2021, our leverage ratio was below the specified level, and we
were not required to make a mandatory prepayment with respect to 2021 cash
flows. As of December 31, 2020, our mandatory excess cash flow prepayment, as
specified in the Credit Agreement, was calculated to be $12.7 million. Lenders
have the right to decline payment. As such, we paid $4.7 million to lenders who
did not decline payment in May 2021 with respect to the 2020 cash flows. This
amount counted towards our required quarterly principal payments through
December 31, 2021.

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Derivative financial instruments


On November 27, 2019, we executed a two-year interest rate swap (the "Swap") to
mitigate variability in forecasted interest payments on a portion of our
borrowings under the Term Loan. We paid a fixed rate of 1.565% per annum on the
$1.0 billion notional amount of the Swap, which expired in November 2021. We
also entered into an interest rate swaption agreement (the "Swaption"), for
which we paid a fixed rate of 0.50% per annum on the $1.0 billion notional
amount. We sold the Swaption in May 2021 for $0.7 million but continued to pay
the fixed rate through the expiration of the Swaption in November 2021. At
inception, the Swap and Swaption (collectively, the "swap contracts") were
designated as cash flow hedges for hedge accounting. The unrealized changes in
market value were recorded in accumulated other comprehensive income (loss) and
any remaining balance will be reclassified into earnings during the period in
which the hedged transaction affects earnings. As a result of the repricing of
the Term Loan in July 2021, we elected to de-designate the Swap as a cash flow
hedge. Accordingly, as the related interest payments were still probable, the
accumulated balance within other comprehensive income (loss) as of the
de-designation date was amortized into earnings through the remaining term, and
subsequent to de-designation, the changes in the valuation of the Swap were
recorded directly into earnings.

On July 21, 2021, we entered into an interest rate cap agreement (the "Cap")
that began in December 2021 upon the expiration of the Swap. The Cap manages our
exposure to interest rate movements on a portion of the Term Loan now that the
Swap has expired. The Cap provides the right for us to receive payment if
one-month LIBOR exceeds 1.5%. Beginning in December 2021, we began to pay a
fixed monthly premium based on an annual rate of 0.31% for the Cap. The Cap
carried a notional amount of $1.0 billion as of December 31, 2021.

The Cap is designed to mirror the terms of the Term Loan and to offset the cash
flows being hedged. We designated the Cap as a cash flow hedge of the
variability of the LIBOR-based interest payments on the Term Loan. The effective
portion of the Cap's change in fair value will be recorded in accumulated other
comprehensive income (loss) and will be reclassified into earnings during the
period in which the hedged transaction affects earnings. See   Note 8   to our
consolidated financial statements included in this report for further discussion
of our derivative financial instruments.

Senior Unsecured Notes


On March 21, 2018, we issued $360.0 million in aggregate principal under the
Notes, before $9.0 million of deferred financing costs, for a net principal
balance of $351.0 million in borrowings from the Notes. The Notes bore interest
at 10.25% per annum and were due to mature on April 15, 2023. Interest was
payable semi-annually on April 15 and October 15, beginning on October 15, 2018,
and principal would have been repaid in full upon maturity. As described above,
the Notes were redeemed in full on February 13, 2020.

Total interest on debt and loss on extinguishment


Total interest incurred includes amortization of deferred financing fees and
capitalized interest. To reprice the Term Loan in January 2021 and July 2021, we
incurred third-party financing costs of $3.6 million and $1.3 million,
respectively. These costs were expensed and are included within interest expense
on the consolidated statements of operations and comprehensive income (loss) for
the year ended December 31, 2021. Total interest incurred during the years ended
December 31, 2021, 2020 and 2019 was $72.8 million, $99.2 million and $140.5
million, respectively. Interest incurred includes amortization of deferred
financing fees of $4.3 million, $3.8 million and $21.3 million for the years
ended December 31, 2021, 2020 and 2019, respectively. Interest capitalized
during the year ended December 31, 2021, 2020 and 2019 was $2.1 million, $3.2
million and $15.1 million, respectively. As of December 31, 2021 and 2020,
accrued interest on the Term Loan was $0.1 million and $0.2 million,
respectively.

As part of the repayment of our previous debt facility in November 2019, we
incurred a loss of approximately $111.7 million for the early extinguishment. In
February 2020, we incurred a loss of approximately $30.2 million for the early
extinguishment of the Notes. In July 2021, certain lenders did not participate
in the repricing of the Term Loan, described above. Those portions of the Term
Loan were replaced by new or existing lenders. This resulted in a loss of
approximately $0.9 million. These losses were recorded within other income
(expense) on our consolidated statements of operations and comprehensive income
(loss).

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Material trends and uncertainties

Our industry and our clientele have historically developed thanks to:

• demand for remote and reliable mobile communications services;

•a growing number of new products and services and associated applications;

•an extensive wholesale distribution network with access to diversified and geographically dispersed niche markets;

•increased demand for communication services by relief and relief organizations and emergency first responders;

•improving data transmission speeds for mobile satellite service offers;

•regulatory mandates requiring the use of mobile satellite services;

•a general fall in the prices of mobile satellite services and subscriber equipment; and

•the geographic expansion of the market thanks to the possibility of offering our services in other countries.

Nonetheless, we face a number of challenges and uncertainties in operating our business, including:

• our ability to maintain the health, capacity, control and level of service of our satellites;

•our ability to develop and launch new innovative products and services;

•changes in general economic, business and industry conditions, including the effects of currency exchange rates;

• our reliance on a single primary business gateway and primary satellite network operations center;

•competition from other mobile satellite service providers and, to a lesser extent, the expansion of terrestrial cellular telephone systems and related pricing pressures;

•acceptance of our products by the market;

•regulatory requirements in existing and new geographic markets;

•rapid and significant technological changes in the telecommunications industry;

•our ability to generate sufficient internal cash flow to repay our debt;

•dependency on our wholesale distribution network to effectively market and sell our products, services and applications;


•reliance on a global supply chain, including single-source suppliers for the
manufacture of most of our subscriber equipment and for some of the components
required in the manufacture of our end-user subscriber equipment and our ability
to purchase component parts that are periodically subject to shortages resulting
from surges in demand, natural disasters or other events, including the COVID-19
pandemic; and

•reliance on a few significant customers, particularly agencies of the U.S.
government, for a substantial portion of our revenue, as a result of which the
loss or decline in business with any of these customers may negatively impact
our revenue and collectability of related accounts receivable.

Significant Accounting Policies and Estimates


The discussion and analysis of our financial condition and results of operations
is based upon our consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United States,
or U.S. GAAP. The preparation of these financial statements requires the use of
estimates and judgments that affect the reported amounts of assets, liabilities,
revenue and expenses, and related disclosure of contingent assets and
liabilities. On an ongoing basis, we evaluate our estimates, including those
related to revenue recognition, income taxes, useful lives of property and
equipment, loss contingencies, and other estimates. We base our estimates on
historical experience and on various other assumptions that we believe to be
reasonable under the circumstances. Actual results may differ from these
estimates under different assumptions or conditions.

The accounting policies we believe to be most critical to understanding our
financial results and condition and that require complex and subjective
management judgments are discussed below. Our accounting policies are more fully
described in   Note 2   to the consolidated financial statements included in
this report.

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Revenue recognition


We sell services and equipment through contracts with our customers. We evaluate
whether a contract exists as it relates to collectability of the contract. Once
a contract is deemed to exist, we evaluate the transaction price including both
fixed and variable consideration. The variable consideration contained within
our contracts with customers may include discounts, credits and other similar
items. When a contract includes variable consideration, we evaluate the estimate
of the variable consideration to determine whether the estimate needs to be
constrained. Therefore, we include constrained consideration in the transaction
price only to the extent that it is probable that a significant reversal of the
amount of cumulative revenue recognized will not occur when the uncertainty
associated with the variable consideration or collectability is subsequently
resolved. Variable consideration estimates are updated at the end of each
quarter and collectability assessments are evaluated with new customers, or on
an ongoing basis if initially deemed not probable, and updated as facts and
circumstances change.

We sell prepaid services in the form of e-vouchers and prepaid cards. A
liability is established equal to the cash paid upon purchase for the e-voucher
or prepaid card. We recognize revenue from (i) the prepaid services upon the use
of the e-voucher or prepaid card by the customer and (ii) the estimated pattern
of use. We continually monitor the pattern of use for prepaid services. A change
in the estimated pattern of use may impact our revenue recognition. While the
terms of prepaid e-vouchers can be extended by the purchase of additional
e-vouchers, prepaid e-vouchers may not be extended beyond three or four years,
dependent on the initial term when purchased.

Revenue associated with some of our fixed-price engineering services
arrangements is recognized over time using costs incurred to date relative to
total estimated costs at completion to measure progress toward satisfying our
performance obligation. We recognize revenue on cost-plus-fixed-fee arrangements
to the extent of estimated costs incurred plus the applicable fees earned. If
actual results are not consistent with our estimates or assumptions, we may be
exposed to changes to earned and unearned revenue that could be material to our
results of operations.

Income Taxes

We account for income taxes using the asset and liability approach. This
approach requires that we recognize deferred tax assets and liabilities based on
differences between the financial statement bases and tax bases of our assets
and liabilities. Deferred tax assets and liabilities are recorded based upon
enacted tax rates for the period in which the deferred tax items are expected to
reverse. Changes in tax laws or tax rates in various jurisdictions are reflected
in the period of change. Significant judgment is required in the calculation of
our tax provision and the resulting tax liabilities as well as our ability to
realize our deferred tax assets. Our estimates of future taxable income and any
changes to such estimates can significantly impact our tax provision in a given
period. Significant judgment is required in determining our ability to realize
our deferred tax assets related to federal, state and foreign tax attributes
within their carryforward periods including estimating the amount and timing of
the future reversal of deferred tax items in our projections of future taxable
income. A valuation allowance is established to reduce deferred tax assets to
the amounts we expect to realize in the future. We also recognize tax benefits
related to uncertain tax positions only when we estimate that it is "more likely
than not" that the position will be sustainable based on its technical merits.
If actual results are not consistent with our estimates and assumptions, this
may result in material changes to our income tax provision.

Property and Equipment


Property and equipment are stated at cost, less accumulated depreciation and
amortization. Property and equipment are depreciated or amortized over their
estimated useful lives. We apply judgment in determining the useful lives based
on factors such as engineering data, our long-term strategy for using the
assets, the manufacturer's estimated design life for the assets, laws and
regulations that could impact the useful lives of the assets and other economic
factors. In evaluating the useful lives of our satellites, we assess the current
estimated operational life of the satellites, including the potential impact of
environmental factors on the satellites, ongoing operational enhancements and
software upgrades. Additionally, we review engineering data relating to the
operation and performance of our satellite network.

We depreciate our satellites over the shorter of their potential operational
life or the period of their expected use. The appropriateness of the useful
lives is evaluated on a quarterly basis or as events occur that require
additional assessment. The upgraded satellites that have been placed into
service are depreciated using the straight-line method over their respective
estimated useful lives. If the estimated useful lives of our upgraded satellites
change, it could have a material impact on the timing of the recognition of
depreciation expense and hosted payload revenue.

                                       46
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During the construction period for our upgraded satellite constellation, assets
under construction primarily consisted of costs incurred associated with the
design, development and launch of the upgraded satellites, upgrades to our
current infrastructure and ground systems and internal software development
costs. We capitalized a portion of the interest on the BPIAE Facility during the
construction period of the upgraded satellite constellation. Capitalized
interest was added to the cost of the upgraded satellites. Once these assets
were placed in service, they are depreciated using the straight-line method over
their respective estimated useful lives. During each year end, we evaluate the
useful lives of all assets under construction.

Comparison of Our Results of Operations for the Years Ended December 31, 2021
and 2020

                                                                   Year Ended December 31,
                                                               % of Total                                 % of Total                        Change
($ In thousands)                           2021                  Revenue                2020                Revenue              Dollars             Percent
Revenue:
Service revenue
Commercial                            $    388,104                      63  %       $ 362,208                      62  %       $ 25,896                     7  %
Government                                 103,887                      17  %         100,887                      17  %          3,000                     3  %
Total service revenue                      491,991                      80  %         463,095                      79  %         28,896                     6  %
Subscriber equipment                        92,071                      15  %          86,119                      15  %          5,952                     7  %
Engineering and support services            30,438                       5  %          34,225                       6  %         (3,787)                  (11) %
Total revenue                              614,500                     100  %         583,439                     100  %         31,061                     5  %
Operating expenses:
Cost of services (exclusive of
depreciation
and amortization)                           97,020                      16  %          91,097                      16  %          5,923                     7  %
Cost of subscriber equipment                53,376                       9  %          51,596                       9  %          1,780                     3  %
Research and development                    11,885                       2  %          12,037                       2  %           (152)                   (1) %
Selling, general and administrative        100,474                      16  %          90,052                      15  %         10,422                    12  %
Depreciation and amortization              305,431                      50  %         303,174                      52  %          2,257                     1  %
Total operating expenses                   568,186                      93  %         547,956                      94  %         20,230                     4  %
Operating income                            46,314                       7  %          35,483                       6  %         10,831                    31  %
Other income (expense):
Interest expense, net                      (73,906)                    (12) %         (94,271)                    (16) %         20,365                   (22) %
Loss on extinguishment of debt                (879)                      0  %         (30,209)                     (5) %         29,330                   (97) %
Other income (expense), net                   (417)                      0  %              33                       0  %           (450)               (1,364) %
Total other expense                        (75,202)                    (12) %        (124,447)                    (21) %         49,245                   (40) %
Loss before income taxes                   (28,888)                     (5) %         (88,964)                    (15) %         60,076                   (68) %
Income tax benefit                          19,569                       3  %          32,910                       5  %        (13,341)                  (41) %
Net loss                              $     (9,319)                     (2) %       $ (56,054)                    (10) %       $ 46,735                   (83) %



                                       47
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Commercial Service Revenue

                                                                          Year Ended December 31,
                                                     2021                                                         2020                                                       Change
                                                  Billable                                                     Billable                                                     Billable
                             Revenue          Subscribers (1)           ARPU (2)          Revenue           Subscribers (1)           ARPU (2)          Revenue           Subscribers             ARPU
                                                                                         (Revenue in millions and subscribers in thousands)

Commercial services:
Voice and data              $ 175.6                  370              $      41          $ 168.6                   350              $      40          $   7.0                  20             $     1
IoT data                      110.9                1,193              $    8.58             97.0                   962              $    9.16             13.9                 231             $ (0.58)
Broadband (3)                  43.0                 13.2              $     288             36.0                  11.7              $     266              7.0                 1.5             $    22
Hosted payload and other
data                           58.6                         N/A                             60.6                          N/A                             (2.0)                      N/A
Total commercial services   $ 388.1                1,576                                 $ 362.2                 1,324                                 $  25.9                 252



(1)Billable subscriber numbers are shown as of the end of the respective period.
(2)Average monthly revenue per unit, or ARPU, is calculated by dividing revenue
in the respective period by the average of the number of billable subscribers at
the beginning of the period and the number of billable subscribers at the end of
the period and then dividing the result by the number of months in the period.
Billable subscriber and ARPU data is not applicable for hosted payload and other
data service revenue items.
(3)Commercial broadband consists of Iridium OpenPort and Iridium Certus
broadband services.

For the year ended December 31, 2021, total commercial revenue increased $25.9
million, or 7%, primarily as a result of increases in IoT, broadband, and voice
and data revenue mainly driven by increases in billable subscribers. Commercial
IoT revenue increased $13.9 million, or 14%, from the prior year. The increase
in IoT revenue was driven by a 24% increase in IoT billable subscribers due to
continued strength in personal communications devices, as well as the lifting of
mobility restrictions that had been imposed due to COVID-19. The subscriber
increase effect on revenue was partially offset by a 6% reduction in IoT ARPU,
primarily due to the increased proportion of personal communication subscribers
using lower ARPU plans, countered in part by an increase in usage and ARPU by
aviation subscribers due to increases in air travel from the prior year.

Commercial broadband revenue increased $7.0 million, or 20%, from the prior
year, primarily due to the increase in broadband billable subscribers and an
increase in ARPU associated with the increase in the mix of subscribers
utilizing higher ARPU Iridium Certus broadband plans. Commercial voice and data
revenue increased $7.0 million, or 4%, from the prior year, primarily due to an
increase in volume across all voice and data services. These increases were
offset in part by a decrease in hosted payload and other service revenue of $2.0
million, or 3%, compared to the prior year. This decrease was primarily due to a
one-time data billing settlement that resulted in recognition of $1.3 million in
the prior year period, plus the recognition of an additional $1.4 million of
hosting data service revenue in the prior year due to an updated estimate of
data service usage that did not recur in 2021.

Government Service Revenue

                                                             Year Ended December 31,
                                                 2021                                          2020                                      Change
                                                          Billable                                   Billable                                    Billable
                                   Revenue             Subscribers (1)          Revenue           Subscribers (1)           Revenue             Subscribers
                                                                    

(Revenues in millions and subscribers in thousands)

Government service revenue     $      103.9                          147       $ 100.9                          152       $     3.0                   (5)


(1)The billable subscriber numbers shown are at the end of the respective period.


We provide airtime and airtime support to U.S. government and other authorized
customers pursuant to our EMSS contract entered into in September 2019. Under
this agreement, authorized customers utilize specified Iridium airtime services
provided through the U.S. government's dedicated gateway. The fee is not based
on subscribers or usage, allowing an unlimited number of users access to these
services. The annual rate under the EMSS contract increased from $103.0 million
in the prior year to $106.0 million during the third quarter of 2021.

                                       48
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Revenue from subscriber equipment


Subscriber equipment revenue increased $6.0 million, or 7%, to $92.1 million for
the year ended December 31, 2021 compared to the prior year, primarily due to an
increase in the volume of handset and IoT device sales, partially offset by a
decrease in the volume of Iridium Pilot and L-band transceiver device sales.

Engineering and Support Services Revenue


                    Year Ended December 31,
                       2021                 2020       Change
                               (In millions)

Commercial   $        4.6                 $  4.5      $  0.1
Government           25.8                   29.7        (3.9)
Total        $       30.4                 $ 34.2      $ (3.8)



Engineering and support service revenue decreased by $3.8 million, or 11%, for
the year ended December 31, 2021 compared to the prior year primarily due to the
episodic nature of contract work under certain government contracts.

Functionnary costs

Cost of services (excluding depreciation and amortization)


Cost of services (exclusive of depreciation and amortization) includes the cost
of network engineering and operations staff, including contractors, software
maintenance, product support services, and cost of services for government and
commercial engineering and support service revenue.

Cost of services (exclusive of depreciation and amortization) increased by $5.9
million, or 7%, for the year ended December 31, 2021 compared to the prior year,
primarily as a result of higher product support and network and satellite
operation costs. These costs were higher in the current year primarily due to
increased management incentive costs. This increase was partially offset by the
decrease in work under certain government engineering contracts, as noted above.

Cost of subscriber equipment

The cost of subscriber equipment includes direct costs of equipment sold, which include manufacturing costs, overhead allocation and warranty costs.


Cost of subscriber equipment increased $1.8 million, or 3%, for the year
ended December 31, 2021 compared to the prior year period primarily due to an
increase in volume of higher margin handsets and an increase in IoT device
sales, partially offset by a decrease in the volume of Iridium Pilot and L-band
transceiver device sales, as described above.

Research and development


Research and development expenses decreased by $0.2 million, or 1%, for the year
ended December 31, 2021 compared to the prior year period based on consistent
spending on device-related features for our network.

Selling, general and administrative expenses


Selling, general and administrative expenses that are not directly attributable
to the sale of services or products include sales and marketing costs as well as
employee-related expenses (such as salaries, wages, and benefits), legal,
finance, information technology, facilities, billing and customer care expenses.

Selling, general and administrative expenses increased by $10.4 million, or 12%,
for the year ended December 31, 2021, primarily due to higher management
incentive costs incurred in the current year. Management incentive costs were
higher in the current year based on improved results and were lower in the prior
year due to the impacts of the COVID-19 pandemic. The increase was partially
offset by a decrease in stock appreciation rights expense in the current year
resulting from changes in our stock valuation between the years. The increase
was also offset by a decrease in bad debt expense and favorable settlements
including social contribution tax credit received in the current year.

                                       49
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Depreciation and amortization


Depreciation and amortization expense increased by $2.3 million, or 1%, for the
year ended December 31, 2021 compared to the prior year. The increase was
primarily due to software enhancements related to our Iridium Certus service
line that were placed into service during July 2021. We anticipate depreciation
and amortization to remain relatively consistent over the next several years.

Other Income (Expense)

Interest Expense, net

Interest expense, net, for the year ended December 31, 2021 was $73.9 million,
compared to $94.3 million for the prior year. The decrease resulted primarily
from a decrease in the annual interest rate on our Term Loan to LIBOR plus 2.5%,
with a 0.75% LIBOR floor, from an annual interest rate of LIBOR plus 3.75%, with
a 1.0% LIBOR floor, as a result of the repricing of our Term Loan in January
2021 and July 2021. The decrease in interest expense was offset in part by
$4.9 million of third-party financing costs paid in 2021, which were expensed as
incurred, in connection with the repricing transactions.

Loss on extinguishment of debt


Loss on extinguishment of debt was $0.9 million for the year ended December 31,
2021, compared to $30.2 million for the prior year. During July 2021, we
repriced our Term Loan and wrote off unamortized debt issuance costs related to
several lenders who did not participate in the repricing and whose portions of
the Term Loan were replaced by new or existing lenders. The loss on
extinguishment of debt in 2020 resulted from the write off of unamortized debt
issuance costs when we closed on an additional $200.0 million under our Term
Loan in February 2020 and used the proceeds, together with cash on hand, to
prepay all of the indebtedness outstanding under the Notes, including premiums
for early prepayment.

Income Tax Benefit

For the year ended December 31, 2021, our income tax benefit was $19.6 million,
compared to income tax benefit of $32.9 million for the prior year. Our
effective tax rate was approximately 67.7% for the year ended December 31, 2021
compared to 37.0% for the prior year. The decrease in income tax benefit was
primarily related to a decrease in loss before income taxes compared to the
prior year. If our current estimates change in future periods, the impact on the
deferred tax assets and liabilities may change correspondingly. See   Note 12
to our consolidated financial statements for more detail on the individual items
impacting our effective tax rate for the years.

Net loss


Net loss was $9.3 million for the year ended December 31, 2021, compared to net
loss of $56.1 million during the prior year. The improvement primarily resulted
from the $29.3 million decrease in loss on extinguishment of debt, the $20.4
million decrease in interest expense, net, and the $10.8 million increase in
total operating income partially offset by the $13.3 million decrease in income
tax benefit.

Cash and capital resources


Our current indebtedness consists exclusively of amounts outstanding under the
Term Loan, the terms of which are described above under the section captioned
"Term Loan."

As of December 31, 2021, we held non-cancelable purchase obligations of
approximately $32.0 million for inventory purchases with Benchmark Electronics,
Inc., or Benchmark, our primary third-party vendor. Our purchase obligations,
all of which are due during 2022, increased $18.5 million from 2020 primarily
due to increased demand and recovery from supply-chain constraints experienced
during 2021.

As of December 31, 2021, our total cash and cash equivalents balance was $320.9
million, and we had $100.0 million of borrowing availability under our Revolving
Facility. In addition to the Revolving Facility, our principal sources of
liquidity are cash, cash equivalents and internally generated cash flows. Other
than the purchase obligation noted above, our principal liquidity requirements
over the next twelve months are primarily required principal and interest on the
Term Loan, which we expect to be $16.5 million and, based on the current
interest rate, approximately $60.0 million, respectively, as well as capital
                                       50
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expenditures of $45.0 million, working capital and potential share repurchases
under the share repurchase program described in   Note 10   to our consolidated
financial statements included in this report.

We estimate that our sources of liquidity will provide us with sufficient funds to meet our liquidity needs for at least the next 12 months.

Our significant long-term cash requirement is the repayment of the remaining principal amount under the term loan when it matures in 2026, which is expected to be $1,555.1 million. We expect to refinance this amount at or before maturity.

Cash Flow – Comparison of Years Ended December 31, 2021 and 2020

The following table presents our consolidated cash flows:

                                                    Year Ended December 31,
Statement of Cash Flows                              2021              2020          Change
                                                               (in thousands)

Net cash flow generated by operating activities $302,874 $249,767 $53,107
Net cash used in investing activities

           $     (36,382)     $  (46,470)     $ 10,088
Net cash used in financing activities           $    (182,469)     $ 

(188 186) $5,717

Cash flow from operating activities


Net cash provided by operating activities for the year ended December 31, 2021
increased $53.1 million from the prior year. Net loss, as adjusted for non-cash
activities, improved by $41.3 million over the prior year, primarily as a result
of improved profitability. Net cash from operating activities also increased
related to working capital changes of approximately $11.7 million. Cash flows
from working capital increased primarily as a result of a decreased payout on
management incentives in 2021 due to the COVID-19 impact on our 2020 financial
results as compared to our expectations at the time the management incentives
were originally established. Cash flows from working capital also increased as a
result of lower interest payments associated with the completed retirement of
the Notes in 2020 and the subsequent Term Loan repricing transactions in 2021.
These increases were offset by net cash outflows resulting from the timing of
customer collections and payments to vendors.

Cash flow from investing activities


Net cash used in investing activities for the year ended December 31, 2021
decreased $10.1 million from the prior year period due primarily to maturities
of marketable securities in the current year and purchases of marketable
securities in the prior year. The movement in marketable securities was offset
in part by a $3.5 million increase in capital expenditures. We continue to
expect our capital expenditures to average approximately $40.0 million per year
until 2029.

Cash flow from financing activities


Net cash used in financing activities for the year ended December 31, 2021
decreased $5.7 million compared to the prior year period primarily due to lower
net principal payments as we utilized our cash to pay down additional debt in
2020, offset by share repurchases we made in 2021. We repurchased and
subsequently retired 4.3 million shares of our common stock during the year
ended December 31, 2021, for a total purchase price of $163.4 million. The
combination of full repayment of the Notes and additional borrowings under the
Term Loan resulted in net payments of $193.8 million for the year ended
December 31, 2020 compared to net payments of $16.5 million for 2021. See   Note
7   to our consolidated financial statements included in this report for further
discussion of our indebtedness.

Seasonality


Our results of operations have been subject to seasonal usage changes for
commercial customers, and our results will be affected by similar seasonality
going forward. March through October are typically the peak months for
commercial voice services revenue and related subscriber equipment sales. U.S.
government revenue and commercial IoT revenue have been less subject to seasonal
usage changes.

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EVERSOURCE ENERGY Management’s Discussion and Analysis of Financial Condition and Results of Operations (Form 10-K) https://fimendurance.com/eversource-energy-managements-discussion-and-analysis-of-financial-condition-and-results-of-operations-form-10-k/ Thu, 17 Feb 2022 11:11:13 +0000 https://fimendurance.com/eversource-energy-managements-discussion-and-analysis-of-financial-condition-and-results-of-operations-form-10-k/ EVERSOURCE ENERGY AND SUBSIDIARIES The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this combined Annual Report on Form 10-K. References in this combined Annual Report on Form 10-K to "Eversource," the "Company," "we," "us," and "our" refer to Eversource Energy and its […]]]>

EVERSOURCE ENERGY AND SUBSIDIARIES


The following discussion and analysis should be read in conjunction with our
consolidated financial statements and related combined notes included in this
combined Annual Report on Form 10-K.  References in this combined Annual Report
on Form 10-K to "Eversource," the "Company," "we," "us," and "our" refer to
Eversource Energy and its consolidated subsidiaries.  All per-share amounts are
reported on a diluted basis.  The consolidated financial statements of
Eversource, NSTAR Electric and PSNH and the financial statements of CL&P are
herein collectively referred to as the "financial statements."  Our discussion
of fiscal year 2021 compared to fiscal year 2020 is included herein. Unless
expressly stated otherwise, for discussion and analysis of fiscal year 2019
items and of fiscal year 2020 compared to fiscal year 2019, please refer to Item
7, Management's Discussion and Analysis of Financial Condition and Results of
Operations, in our combined 2020   Annual Report on Form 10-K  , which is
incorporated herein by reference.

Refer to the Glossary of Terms included in this combined Annual Report on Form
10-K for abbreviations and acronyms used throughout this Management's Discussion
and Analysis of Financial Condition and Results of Operations.

The only common equity securities that are publicly traded are common shares of
Eversource. The earnings and EPS of each business discussed below do not
represent a direct legal interest in the assets and liabilities of such
business, but rather represent a direct interest in our assets and liabilities
as a whole. EPS by business is a financial measure not recognized under GAAP
(non-GAAP) that is calculated by dividing the Net Income Attributable to Common
Shareholders of each business by the weighted average diluted Eversource common
shares outstanding for the period. Our earnings discussion also includes
non-GAAP financial measures referencing our 2021 earnings and EPS excluding
charges at CL&P related to a settlement agreement that included credits to
customers and funding of various customer assistance initiatives and a storm
performance penalty imposed on CL&P by the PURA and our 2021 and 2020 earnings
and EPS excluding certain acquisition and transition costs.

We use these non-GAAP financial measures to evaluate and provide details of
earnings results by business and to more fully compare and explain our 2021 and
2020 results without including these items. This information is among the
primary indicators we use as a basis for evaluating performance and planning and
forecasting of future periods. We believe the impacts of the CL&P settlement
agreement, the storm performance penalty imposed on CL&P by the PURA, and
acquisition and transition costs are not indicative of our ongoing costs and
performance. We view these charges as not directly related to the ongoing
operations of the business and therefore not an indicator of baseline operating
performance. Due to the nature and significance of the effect of these items on
Net Income Attributable to Common Shareholders and EPS, we believe that the
non-GAAP presentation is a more meaningful representation of our financial
performance and provides additional and useful information to readers of this
report in analyzing historical and future performance of our business. These
non-GAAP financial measures should not be considered as alternatives to reported
Net Income Attributable to Common Shareholders or EPS determined in accordance
with GAAP as indicators of operating performance.

Financial situation and business analysis

Summary


Eversource Energy is a public utility holding company primarily engaged, through
its wholly-owned regulated utility subsidiaries, in the energy delivery
business. Eversource Energy's wholly-owned regulated utility subsidiaries
consist of CL&P, NSTAR Electric and PSNH (electric utilities), Yankee Gas, NSTAR
Gas and Eversource Gas Company of Massachusetts (EGMA) (natural gas utilities)
and Aquarion (water utilities). Eversource is organized into the electric
distribution, electric transmission, natural gas distribution, and water
distribution reportable segments.

The following elements of this executive summary are further explained in this Combined Annual Report on Form 10-K:

Overview of benefits and future prospects:

• We won $1.22 billionWhere $3.54 per share, in 2021, versus $1.21 billionWhere $3.55 per share, in 2020.


•Our 2021 results include after-tax costs recorded within the electric
distribution segment resulting from a PURA-approved CL&P settlement agreement
and an after-tax charge at CL&P for a PURA assessment as a result of CL&P's
preparation for and response to Tropical Storm Isaias in August 2020. Our 2021
results also include after-tax acquisition and transition costs recorded at
Eversource parent. In total, these after-tax costs were $109.7 million, or $0.32
per share in 2021. Our 2020 results include after-tax acquisition and transition
costs of $32.1 million, or $0.09 per share, recorded primarily at Eversource
parent. Excluding those costs, our non-GAAP earnings were $1.33 billion, or
$3.86 per share, in 2021, compared with $1.24 billion, or $3.64 per share, in
2020.

•We currently project 2022 non-GAAP earning guidance of between $4.00 per share
and $4.17 per share, which excludes the impact of remaining integration costs as
a result of transitioning EGMA onto Eversource's systems. We also project that
our long-term EPS growth rate through 2026 from our regulated utility businesses
will be in the upper half of a 5 to 7 percent range.



                                       27
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Liquidity:

• Cash flow from operating activities totaled $1.96 billion in 2021, compared to $1.68 billion in 2020. Investments in property, plant and equipment $3.18 billion in 2021 and $2.94 billion in 2020.


•Cash totaled $66.8 million as of December 31, 2021, compared with $106.6
million as of December 31, 2020.  Our available borrowing capacity under our
commercial paper programs totaled $1.14 billion as of December 31, 2021. In
2021, we issued $3.23 billion of new long-term debt and we repaid $1.14 billion
of long-term debt.

•In 2021, we issued dividends totaling $2.41 per common share, compared with
dividends of $2.27 per common share in 2020. Our quarterly common share dividend
payment was $0.6025 per share in 2021, as compared to $0.5675 per share in
2020.  On February 2, 2022, our Board of Trustees approved a common share
dividend payment of $0.6375 per share, payable on March 31, 2022 to shareholders
of record as of March 3, 2022.

•We project to make capital expenditures of $18.14 billion from 2022 through
2026, of which we expect $7.02 billion to be in our electric distribution
segment, $4.53 billion to be in our natural gas distribution segment, $4.60
billion to be in our electric transmission segment, and $0.89 billion to be in
our water distribution segment.  We also project to invest $1.10 billion in
information technology and facilities upgrades and enhancements. Additionally,
we currently expect to make investments in our offshore wind business between
$0.9 billion and $1.0 billion in 2022 and expect to make investments for our
three projects in total between $3.0 billion and $3.6 billion from 2023 through
2026. These estimates assume that the three projects are completed and are
in-service by the end of 2025, as planned.

Strategic and regulatory elements:


•On January 18, 2022, South Fork Wind received BOEM's final approval of its
Construction and Operations Plan (COP), following BOEM's November 2021 issuance
of the Record of Decision, which concluded BOEM's environmental review of the
project. The COP approval outlines the project's one nautical mile turbine
spacing, the requirements on the construction methodology for all work occurring
in federal ocean waters, and mitigation measures to protect marine habitats and
species. The final decision from BOEM was needed to move the project toward the
start of construction, and with the decision received, South Fork has now
entered the construction phase.

•On October 1, 2021, CL&P entered into a settlement agreement with the DEEP,
Office of Consumer Counsel (OCC), Office of the Attorney General (AG) and the
Connecticut Industrial Energy Consumers, resolving certain issues that arose in
then-pending regulatory proceedings initiated by the PURA. PURA approved the
settlement agreement on October 27, 2021. In the settlement agreement, CL&P
agreed to provide a total of $65 million of customer credits, which were
distributed based on customer sales over a two-month billing period from
December 1, 2021 to January 31, 2022. CL&P also agreed to irrevocably set aside
$10 million in a fund to provide bill payment assistance to certain existing
non-hardship and hardship customers carrying arrearages, as approved by the
PURA. In exchange for the $75 million of customer credits and assistance, PURA's
interim rate reduction docket was resolved without findings. As a result of the
settlement agreement, neither the 90 basis point reduction to CL&P's return on
equity introduced in PURA's storm-related decision issued April 28, 2021, nor
the 45 basis point reduction to CL&P's return on equity included in PURA's
decision issued September 14, 2021 in the interim rate reduction docket, will be
implemented. Additionally, CL&P agreed to withdraw its pending appeals related
to the $28.6 million storm performance penalty imposed in PURA's April 28, 2021
and July 14, 2021 decisions. CL&P has also agreed to freeze its current base
distribution rates until no earlier than January 1, 2024. The cumulative pre-tax
impact of the October 1, 2021 settlement agreement and the Storm Isaias penalty
imposed by PURA totaled $103.6 million, and the after-tax earnings impact was
$86.1 million, or $0.25 per share, in 2021.

Revenue overview


Consolidated:  Below is a summary of our earnings by business, which also
reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and
EPS, as well as EPS by business, to the most directly comparable GAAP measures
of consolidated Net Income Attributable to Common Shareholders and diluted EPS.

                                                                            

For the years ended the 31st of December,

                                                        2021                                   2020                                   2019
(Millions of Dollars, Except Per Share
Amounts)                                     Amount            Per Share            Amount            Per Share            Amount            Per Share
Net Income Attributable to Common
Shareholders (GAAP)                       $ 1,220.5          $     3.54     

$1,205.2 $3.55 $909.1 $2.81


Regulated Companies (non-GAAP)            $ 1,342.4          $     3.89     

$1,223.3 $3.60 $1,105.3 $3.43
Parent company of Eversource and other companies (non-GAAP)

                                    (12.2)              (0.03)              14.0                0.04                8.2                0.02
Non-GAAP Earnings                         $ 1,330.2          $     3.86     

$1,237.3 $3.64 $1,113.5 $3.45
Impact of CL&P regulations (after tax) (1) (86.1)

              (0.25)                 -                   -                  -                   -
Acquisition and Transition Costs
(after-tax) (2)                               (23.6)              (0.07)             (32.1)              (0.09)                 -                   -
Impairment of Northern Pass Transmission
(after-tax)                                       -                   -                  -                   -             (204.4)              (0.64)
Net Income Attributable to Common
Shareholders (GAAP)                       $ 1,220.5          $     3.54          $ 1,205.2          $     3.55          $   909.1          $     2.81



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Regulated Companies:  Our regulated companies comprise the electric
distribution, electric transmission, natural gas distribution and water
distribution segments. A summary of our segment earnings and EPS is as follows:

                                                                                        For the Years Ended December 31,
                                                               2021                                   2020                                   2019
(Millions of Dollars, Except Per Share Amounts)     Amount            Per Share            Amount            Per Share            Amount            

Earnings per share – Regulated companies (GAAP) $1,256.3 $3.64 $1,221.8 $3.60 $900.9 $

2.79


Electric Distribution, excluding CL&P Settlement
Impacts
  (Non-GAAP)                                     $   556.2          $     

1.61 $544.0 $1.60 $513.3 $

1.59

Electric Transmission, excluding Impairment of
Northern Pass
  Transmission (Non-GAAP)                            544.6                1.58              502.5                1.48              460.9              

1.43

Natural Gas Distribution, excluding
Acquisition-Related Costs
 (Non-GAAP)                                          204.8                0.59              135.6                0.40               96.2                0.30
Water Distribution                                    36.8                0.11               41.2                0.12               34.9                0.11

Net income – Regulated companies (excluding GAAP) $1,342.4 $3.89 $1,223.3 $3.60 $1,105.3 $

3.43

CL&P Settlement Impacts (after-tax) (1)              (86.1)              (0.25)                 -                   -                  -             

Acquisition-Related Costs (after-tax) (2)                -                   -               (1.5)                  -                  -                

Impairment of Northern Pass Transmission
(after-tax)                                              -                   -                  -                   -             (204.4)              

(0.64)

Net income – Regulated companies (GAAP) $1,256.3 $3.64 $1,221.8 $3.60 $900.9 $

     2.79



(1) The 2021 after-tax costs are associated with the CL&P settlement agreement
approved by PURA on October 27, 2021, which included a pre-tax $65 million
charge to earnings for customer credits provided to customers over a two-month
billing period from December 1, 2021 to January 31, 2022 and a $10 million
charge to earnings to establish a fund to provide bill payment assistance to
certain existing non-hardship and hardship customers carrying arrearages. The
2021 after-tax costs also include charges recorded at CL&P as a result of the
April 28, 2021 and July 14, 2021 PURA decisions, which included a $28.4 million
penalty for storm performance results and is currently being provided as credits
to customer bills and a $0.2 million fine to the State of Connecticut's general
fund. As a result of the October 1, 2021 settlement agreement, CL&P agreed to
withdraw its pending appeals related to the storm performance penalty imposed in
PURA's April 28, 2021 and July 14, 2021 decisions. Management views these
collective charges as not directly related to the ongoing operations of the
business and therefore not an indicator of baseline operating performance.

(2) The 2021 costs are for the transition of systems as a result of our purchase
of the assets of CMA on October 9, 2020 and costs associated with our December
1, 2021 water business acquisition. The 2020 acquisition costs are associated
with our CMA acquisition. We expect integration costs in 2022 as a result of
continuing to transition the CMA assets onto Eversource's systems.

Our electric distribution segment earnings decreased $73.9 million in 2021, as
compared to 2020, due primarily to CL&P's settlement agreement on October 1,
2021 resulting in a $75 million pre-tax charge to earnings and a $28.6 million
pre-tax charge to earnings at CL&P for a storm performance penalty imposed by
PURA as a result of CL&P's preparation for and response to Tropical Storm Isaias
in August 2020 that was recorded in 2021. The after-tax impact of the CL&P
settlement agreement and CL&P storm performance penalty imposed by the PURA was
$86.1 million, or $0.25 per share. For further information, see "Regulatory
Developments and Rate Matters - Connecticut" included in this Management's
Discussion and Analysis. Excluding those charges, electric distribution segment
earnings increased $12.2 million due primarily to base distribution rate
increases at NSTAR Electric effective January 1, 2021, at PSNH effective January
1, 2021 and August 1, 2021, and at CL&P effective May 1, 2020, and higher
earnings from CL&P's capital tracker mechanism due to increased electric system
improvements. Those earnings increases were partially offset by higher
operations and maintenance expense driven by higher employee-related expenses
and higher vegetation management costs, higher depreciation expense, higher
property tax expense, and higher interest expense.

Our electric transmission segment earnings increased $42.1 million in 2021, as
compared to 2020, due primarily to a higher transmission rate base as a result
of our continued investment in our transmission infrastructure.

Our natural gas distribution segment earnings increased $70.7 million in 2021,
as compared to 2020, due primarily to the incremental impact of EGMA earnings of
$43.0 million. Additionally, the earnings increase was due to base distribution
rate increases at NSTAR Gas effective November 1, 2021 and 2020 and at Yankee
Gas effective January 1, 2021 (with changes to customer rates beginning March 1,
2021), and higher earnings from capital tracker mechanisms due to continued
investments in natural gas infrastructure. The earnings increase was partially
offset by higher depreciation expense, higher property tax expense and higher
interest expense.

Our water distribution segment earnings decreased $4.4 million in 2021, as
compared to 2020, due primarily to the absence in 2021 of an after-tax gain of
$3.5 million and lower revenues both as a result of the sale of the water system
and treatment plant in Hingham, Massachusetts in July 2020.

Eversource Parent and Other Companies:  Eversource parent and other companies
had an increased loss of $19.2 million in 2021, as compared to 2020, due
primarily to a higher effective tax rate and higher employee-related costs. The
higher loss was partially offset by a decrease of $7.0 million in acquisition
and transition costs of EGMA recorded at Eversource parent and a higher return
at Eversource Service as a result of increased investments in property, plant
and equipment.

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Impact of COVID-19


COVID-19 has adversely affected customers, workers and the U.S. economy. We
provide a critical service to our customers and have taken extensive measures to
maintain its safety and reliability. We continue to address the impacts of the
COVID-19 pandemic and how the related developments affect Eversource. By the end
of 2021, we completed the re-entry phase of our pandemic response plan for those
of our employees that were working remotely. We have not experienced significant
impacts directly related to the pandemic that have materially affected our
current operations, our workforce, or results of operations. The extent of the
impact to us in the future will vary, and depend on the duration, scope and
severity of the pandemic and the resulting impact on economic, health care and
capital market conditions. The future impact will also depend on the outcome of
future proceedings before our state regulatory commissions to recover our
incremental costs associated with COVID-19, which include uncollectible customer
receivable expenses.

The current and expected future financial impacts of COVID-19 as it relates to
our businesses primarily relate to collectability of customer receivables and
customer payment plans and increased expenses for cleaning and supplies for
personal protective equipment.

As of December 31, 2021, our allowance for uncollectible customer receivable
balance of $417.4 million, of which $226.1 million relates to hardship accounts
that are specifically recovered in rates charged to customers, adequately
reflected the collection risk and net realizable value for our receivables. Our
evaluation of the uncollectible allowance has shown that our operating companies
have experienced an increase in aged receivables and lower cash collections from
customers because of the length of the moratorium on disconnections in
Connecticut and Massachusetts, and the economic slowdown resulting from the
COVID-19 pandemic. In Connecticut, the moratorium on disconnections of
commercial and non-hardship residential customers ended in June 2021 and
September 2021, respectively, but is still in place for hardship residential
customers. In Massachusetts, the moratorium on disconnections of commercial
customers and residential customers ended in September 2020 and July 2021,
respectively. Disconnection activities have resumed after these moratoria have
expired, which has resulted in recent improved collection experience, more
customers applying for, and receiving, hardship status, and higher write-offs of
aged receivable amounts. On July 7, 2021, the NHPUC issued an order to New
Hampshire utilities that concluded that recovery of incremental bad debt or
waived late fees related to the COVID-19 pandemic would be addressed in a future
rate case to the extent those costs are relevant at that time. As a result of
the order, PSNH removed its $0.6 million deferral of net incremental COVID-19
costs in 2021. In New Hampshire, the moratorium on disconnections of
non-hardship residential and commercial customers ended in late 2020 and for
hardship residential customers ended in May 2021 and PSNH has resumed
disconnection activities, which has resulted in improved collection of
outstanding customer receivable balances.

Based upon the evaluation performed, for the year ended December 31, 2021,
management increased the allowance for uncollectible accounts for amounts
incurred as a result of COVID-19 by $24.1 million for Eversource (increase of
$20.1 million for CL&P and $6.6 million at our natural gas businesses, and
decrease of $1.3 million at NSTAR Electric). The COVID-19 related uncollectible
amounts were deferred either as incremental regulatory costs at our Connecticut
and Massachusetts utilities or deferred through existing regulatory tracking
mechanisms that recover uncollectible energy supply costs, as management
believes it is probable that these costs will ultimately be recovered from
customers in future rates. As of December 31, 2021, the total amount incurred as
a result of COVID-19 included in the allowance for uncollectible accounts was
$55.3 million at Eversource ($23.9 million at CL&P, $9.0 million at NSTAR
Electric, and $21.4 million at our natural gas businesses). Based on the status
of our COVID-19 regulatory dockets, communications with our state regulatory
commissions, and policies and practices in the jurisdictions in which we
operate, we believe our state regulatory commissions in Connecticut and
Massachusetts will allow us to recover our incremental costs associated with
COVID-19, which include uncollectible customer receivable expenses, while
balancing the impact on our customers' bills and our operating cash flows.

We worked closely with our state regulatory commissions and consumer advocates
on customer assistance measures, including payment plan options as well as
financial hardship and arrearage management programs, in order to mitigate the
impact on customer rates in the future. We developed these long-term solutions
for customers in order to help minimize the extent of the impact of COVID-19 on
customer receivable balances and customers' affordability in light of the
current financial impact they may experience.

For the year ended December 31, 2021, net incremental costs incurred as a result
of COVID-19 totaled $20.8 million, and related to uncollectible expense that
impacts earnings, facilities and fleet cleaning, sanitizing costs and supplies
for personal protective equipment, net of cost savings and benefits under the
CARES Act. In 2021, we deferred $15.8 million of these net incremental COVID-19
costs on the balance sheet. Net incremental COVID-19 expenses that reduced
pre-tax earnings totaled $5.0 million on the statement of income in 2021.

As of December 31, 2021, a total of $39.8 million of net deferred incremental
COVID-19 costs were recorded on the balance sheet, of which $33.0 million of
that deferral related to uncollectible expense that impacts earnings and
$6.8 million related to cleaning and supplies for personal protective equipment.

Liquidity


Sources and Uses of Cash: Eversource's regulated business is capital intensive
and requires considerable capital resources. Eversource's regulated companies'
capital resources are provided by cash flows generated from operations,
short-term borrowings, long-term debt issuances, capital contributions from
Eversource parent, and existing cash, and are used to fund their liquidity and
capital requirements. Eversource's regulated companies typically maintain
minimal cash balances and use short-term borrowings to meet their working
capital needs and other cash requirements. Short-term borrowings are also used
as a bridge to long-term debt financings. The levels of short-term borrowing may
vary significantly over the course of the year due to the impact of fluctuations
in cash flows from operations, dividends paid, capital contributions received
and the timing of long-term debt financings.

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Eversource, CL&P, Electric NSTAR and PSNH each uses its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other obligations of the company, such as pension contributions.

 Eversource's regulated companies recover their electric, natural gas and water
distribution construction expenditures as the related project costs are
depreciated over the life of the assets.  This impacts the timing of the revenue
stream designed to fully recover the total investment plus a return on the
equity and debt used to finance the investments.  Eversource's regulated
companies' spend a significant amount of cash on capital improvements and
construction projects that have a long-term return on investment and recovery
period. In addition, Eversource's investments in its offshore wind business are
recognized as long-term assets. These factors have resulted in current
liabilities exceeding current assets by $2.58 billion, $537.0 million, and
$165.0 million at Eversource, NSTAR Electric and PSNH, respectively, as of
December 31, 2021.

As of December 31, 2021, $1.18 billion of Eversource's long-term debt, including
$750.0 million at Eversource parent, $400.0 million at NSTAR Electric, $20.0
million at Yankee Gas, and $5.4 million at Aquarion, will mature within the next
12 months. Eversource, with its strong credit ratings, has several options
available in the financial markets to repay or refinance these maturities with
the issuance of new long-term debt. Eversource, CL&P, NSTAR Electric and PSNH
will reduce their short-term borrowings with operating cash flows or with the
issuance of new long-term debt, determined by considering capital requirements
and maintenance of Eversource's credit rating and profile.

We expect the future operating cash flows of Eversource, CL&P, NSTAR Electric
and PSNH, along with our existing borrowing availability and access to both debt
and equity markets, will be sufficient to meet any working capital and future
operating requirements, and capital investment forecasted opportunities.

Totaled cash $66.8 million from December 31, 2021compared to $106.6 million
from December 31, 2020.


Short-Term Debt - Commercial Paper Programs and Credit Agreements: Eversource
parent has a $2.00 billion commercial paper program allowing Eversource parent
to issue commercial paper as a form of short-term debt. Eversource parent, CL&P,
PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut are
parties to a five-year $2.00 billion revolving credit facility, which terminates
on October 15, 2026. This revolving credit facility serves to backstop
Eversource parent's $2.00 billion commercial paper program.

NSTAR Electric has a $650 million commercial paper program allowing NSTAR
Electric to issue commercial paper as a form of short-term debt. NSTAR Electric
is also a party to a five-year $650 million revolving credit facility, which
terminates on October 15, 2026. The revolving credit facility serves to backstop
NSTAR Electric's $650 million commercial paper program.

The amount of borrowings outstanding and available under the commercial paper
programs were as follows:

                                       Borrowings Outstanding                Available Borrowing Capacity            Weighted-Average Interest Rate as of
                                          as of December 31,                      as of December 31,                             December 31,
(Millions of Dollars)                  2021                  2020               2021               2020                   2021                      2020
Eversource Parent Commercial
Paper Program                   $    1,343.0             $ 1,054.3          $    657.0          $ 945.7                          0.31  %              0.25  %
NSTAR Electric Commercial Paper
Program                                162.5                 195.0               487.5            455.0                          0.14  %              0.16  %


There was no outstanding borrowing under the revolving credit facilities at
December 31, 2021 or 2020.


CL&P and PSNH have uncommitted line of credit agreements totaling $450 million
and $300 million, respectively, which will expire on May 12, 2022. There are no
borrowings outstanding on either the CL&P or PSNH uncommitted line of credit
agreements as of December 31, 2021.

Amounts outstanding under the commercial paper programs are included in Notes
Payable and classified in current liabilities on the Eversource and NSTAR
Electric balance sheets, as all borrowings are outstanding for no more than 364
days at one time.

Intercompany Borrowings: Eversource parent uses its available capital resources
to provide loans to its subsidiaries to assist in meeting their short-term
borrowing needs. Eversource parent records intercompany interest income from its
loans to subsidiaries, which is eliminated in consolidation. Intercompany loans
from Eversource parent to its subsidiaries are eliminated in consolidation on
Eversource's balance sheets. As of December 31, 2021, there were intercompany
loans from Eversource parent to PSNH of $110.6 million. As of December 31, 2020,
there were intercompany loans from Eversource parent to PSNH of $46.3 million,
and to a subsidiary of NSTAR Electric of $21.3 million. Intercompany loans from
Eversource parent are included in Notes Payable to Eversource Parent and
classified in current liabilities on the respective subsidiary's balance sheets.

Availability under Long-Term Debt Issuance Authorizations: On March 31, 2021,
the DPU approved NSTAR Electric's request for authorization to issue up to
$1.60 billion in long-term debt through December 31, 2023. On September 10,
2021, the DPU approved EGMA's request for authorization to issue up to $725.0
million in long-term debt through December 31, 2023. The remaining Eversource
operating companies, including CL&P and PSNH, have utilized the long-term debt
authorizations in place with the respective regulatory commissions.

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Issues and redemptions of long-term debt: The following table summarizes the issues and redemptions of long-term debt:

                                                                     Issue Date or                                     Use of Proceeds for Issuance/
(Millions of Dollars)                 Issuance/(Repayment)           Repayment Date            Maturity Date               Repayment Information
CL&P:
                                                                                                                      Repaid short-term debt, paid
                                                                                                                      capital expenditures and
2.05% Series A First Mortgage Bonds $               425.0              June 2021                 July 2031            working capital
                                                                                                                      Paid on par call date in
4.38% Series A PCRB                                (120.5)           September 2021           September 2028          advance of maturity
NSTAR Electric:
                                                                                                                      Refinanced investments in
                                                                                                                      eligible green
                                                                                                                      expenditures, which were
                                                                                                                      previously financed in 2019 and
3.10% 2021 Debentures                               300.0               May 2021                 June 2051            2020
                                                                                                                      Paid on par call date in
3.50% Series F Senior Notes                        (250.0)             June 2021              September 2021          advance of maturity
                                                                                                                      Repaid short-term debt, paid
                                                                                                                      capital expenditures and
1.95% 2021 Debentures                               300.0             August 2021               August 2031           working capital
PSNH:
                                                                                                                      Paid on par call date in
4.05% Series Q First Mortgage Bonds                (122.0)             March 2021                June 2021            advance of maturity
                                                                                                                      Paid on par call date in
3.20% Series R First Mortgage Bonds                (160.0)             June 2021              September 2021          advance of maturity
                                                                                                                      Repaid short-term debt,
                                                                                                                      including short-term debt used
                                                                                                                      to redeem Series R First
                                                                                                                      Mortgage Bonds, paid capital
                                                                                                                      expenditures and working
2.20% Series V First Mortgage Bonds                 350.0              June 2021                 June 2031            capital

Other:

Eversource Parent 2.50% Series I                                                                                      Paid on par call date in
Senior Notes                                       (450.0)           February 2021              March 2021            advance of maturity
                                                                                                                      Repaid short-term debt,
Eversource Parent 2.55% Series S                                                                                      including short-term debt used
Senior Notes                                        350.0              March 2021               March 2031            to redeem Series I Senior 

Remarks

Eversource Parent 1.40% Series U
Senior Notes                                        300.0             August 2021               August 2026           Repaid short-term debt
Eversource Parent Variable Rate
Series T Senior Notes (1)                           350.0             August 2021               August 2023           Repaid short-term debt
                                                                                                                      Repaid 5.50% Notes, repaid
Aquarion Water Company of                                                                                             short-term debt, paid capital
Connecticut 3.31%                                                                                                     expenditures and working
  Senior Notes                                      100.0              April 2021               April 2051            capital
Aquarion Water Company of
Connecticut 5.50% Notes                             (40.0)             April 2021               April 2021            Paid at maturity
Yankee Gas 1.38% Series S First
Mortgage Bonds                                       90.0             August 2021               August 2026           (2)
Yankee Gas 2.88% Series T First
Mortgage Bonds                                       35.0             August 2021               August 2051           (2)
EGMA 2.11% Series A First Mortgage
Bonds                                               310.0            September 2021            October 2031           (2)
EGMA 2.92% Series B First Mortgage
Bonds                                               240.0            September 2021            October 2051           (2)
NSTAR Gas 2.25% Series T First
Mortgage Bonds                                       40.0             October 2021             November 2031          (2)
NSTAR Gas 3.03% Series U First
Mortgage Bonds                                       40.0             October 2021             November 2051          (2)



(1) On August 13, 2021, Eversource Parent issued $350 million of floating rate
Series T Senior Notes with a maturity date of August 15, 2023. The notes have a
coupon rate based on Compounded SOFR plus 0.25%. The notes had an interest rate
of 0.30% as of December 31, 2021.

(2) The use of proceeds from these various issues refinanced existing debt, funded capital expenditures and was used for general corporate purposes. EGMA’s indebtedness that was refinanced included $309.4 million long-term debt.


Rate Reduction Bonds: PSNH's RRB payments consist of principal and interest and
are paid semi-annually. PSNH paid $43.2 million of RRB principal payments and
$18.9 million of interest payments in 2021, and paid $43.2 million of RRB
principal payments and $20.2 million of interest payments in 2020.

Cash Flows:  Cash flows from operating activities primarily result from the
transmission and distribution of electricity, and the distribution of natural
gas and water. Cash flows provided by operating activities totaled $1.96 billion
in 2021, compared with $1.68 billion in 2020. Changes in Eversource's cash flows
from operations were generally consistent with changes in its results of
operations, as adjusted by changes in working capital in the normal course of
business and as further discussed. Operating cash flows were favorably impacted
by improvements in the timing of cash collections on our accounts receivable,
the timing of collections for regulatory tracking mechanisms, and the timing of
other working capital items. These favorable impacts were partially offset by
the timing of cash payments made on our accounts payable, a $93.8 million
increase in cost of removal expenditures, a $72.7 million increase in income tax
payments made in 2021, as compared to 2020, and a $70.8 million increase in
Pension and PBOP contributions made in 2021, as compared to 2020.

In 2021, we paid cash dividends of $805.4 million and issued non-cash dividends
of $22.9 million in the form of treasury shares, totaling dividends of $828.3
million, or $2.41 per common share. In 2020, we paid cash dividends of $744.7
million and issued non-cash dividends of $22.8 million in the form of treasury
shares, totaling dividends of $767.5 million, or $2.27 per common share. Our
quarterly common share dividend payment was $0.6025 per share in 2021, as
compared to $0.5675 per share in 2020.  On February 2, 2022, our Board of
Trustees approved a common share dividend payment of $0.6375 per share, payable
on March 31, 2022 to shareholders of record as of March 3, 2022.

Eversource issues treasury stock to satisfy awards under the Company’s incentive plans, shares issued under the dividend reinvestment and stock purchase plan and matching contributions under the plan Eversource 401k.

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In 2021, CL&P, Electric NSTAR and PSNH paid $341.4 million, $283.2 million and
$260.8 millionrespectively, in common stock dividends to Eversource’s parent company.


Investments in Property, Plant and Equipment on the statements of cash flows do
not include amounts incurred on capital projects but not yet paid, cost of
removal, AFUDC related to equity funds, and the capitalized and deferred
portions of pension and PBOP expense.  In 2021, investments for Eversource,
CL&P, NSTAR Electric and PSNH were $3.18 billion, $790.1 million, $960.9 million
and $326.4 million, respectively.  Capital expenditures were primarily for
continuing projects to maintain and improve infrastructure and operations,
including enhancing reliability to the transmission and distribution systems.

Contractual Obligations: For information regarding our cash requirements from
contractual obligations and payment schedules, see Note 9, "Long-Term Debt,"
Note 10, "Rate Reduction Bonds and Variable Interest Entities," Note 11A,
"Employee Benefits - Pension Benefits and Postretirement Benefits Other Than
Pension," Note 13, "Commitments and Contingencies," and Note 14, "Leases," to
the financial statements.

Estimated interest payments on existing long-term fixed-rate debt are calculated
by multiplying the coupon rate on the debt by its scheduled notional amount
outstanding for the period of measurement as of December 31, 2021 and are as
follows:
(Millions of Dollars)     2022         2023         2024         2025         2026        Thereafter        Total
Eversource              $ 583.8      $ 551.3      $ 509.4      $ 463.1      $ 433.2      $  4,923.0      $ 7,463.8
CL&P                      159.7        154.7        149.7        138.6        135.6         1,784.8        2,523.1



Our commitments to make payments in addition to these contractual obligations
include other liabilities reflected on our balance sheets, future funding of our
offshore wind equity method investment, and guarantees of certain obligations
primarily associated with our offshore wind investment.

For information regarding our projected capital expenditures over the next five
years, see "Business Development and Capital Expenditures - Projected Capital
Expenditures" and for projected investments in our offshore wind business, see
Business Development and Capital Expenditures - Offshore Wind Business" included
in this Management's Discussion and Analysis of Financial Condition and Results
of Operations.

Credit Ratings: A summary of our corporate credit ratings and outlook by S&P, Moody’s and Fitch is as follows:

                              S&P                        Moody's                        Fitch
                     Current       Outlook       Current         Outlook       Current         Outlook
Eversource Parent      A-          Stable         Baa1           Negative       BBB+           Stable
CL&P                    A          Stable          A3            Negative        A-           Negative
NSTAR Electric          A          Stable          A1             Stable         A             Stable
PSNH                    A          Stable          A3             Stable         A-            Stable



A summary of the current credit ratings and outlooks by S&P, Moody's, and Fitch
for senior unsecured debt of Eversource parent and NSTAR Electric, and senior
secured debt of CL&P and PSNH is as follows:

                              S&P                        Moody's                        Fitch
                     Current       Outlook       Current         Outlook       Current         Outlook
Eversource Parent     BBB+         Stable         Baa1           Negative       BBB+           Stable
CL&P                   A+          Stable          A1            Negative        A+           Negative
NSTAR Electric          A          Stable          A1             Stable         A+            Stable
PSNH                   A+          Stable          A1             Stable         A+            Stable


Business development and capital expenditures


Our consolidated capital expenditures, including amounts incurred but not paid,
cost of removal, AFUDC, and the capitalized and deferred portions of pension and
PBOP expense (all of which are non-cash factors), totaled $3.54 billion in 2021,
$3.06 billion in 2020, and $3.06 billion in 2019.  These amounts included $238.0
million in 2021, $239.1 million in 2020, and $239.0 million in 2019 related to
information technology and facilities upgrades and enhancements, primarily at
Eversource Service and The Rocky River Realty Company.

Electric Transmission Business: Capital expenditures for our consolidated electric transmission business increased by $151.7 million in 2021, compared to 2020.

 A summary of electric transmission capital expenditures by company is as
follows:

                                               For the Years Ended December 31,
(Millions of Dollars)                          2021               2020          2019
CL&P                                  $       400.0             $ 402.9      $   459.5
NSTAR Electric                                480.3               366.8          379.7
PSNH                                          235.0               193.9          190.4
NPT                                               -                   -            9.8
Total Electric Transmission Segment   $     1,115.3             $ 963.6     

$1,039.4

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Our transmission projects are designed to improve the reliability of the
electric grid, meet customer demand for power, strengthen the electric grid's
resilience against extreme weather and other safety and security threats, and
increase access to clean power generation from renewable sources, such as solar
and offshore wind. In Connecticut, Massachusetts and New Hampshire, our
transmission projects include transmission line upgrades, the installation of
new transmission lines, and substation enhancements.

Our transmission projects in Massachusetts include electric transmission
upgrades in the greater Boston metropolitan area. Two of these upgrades, the
Mystic-Woburn and the Wakefield-Woburn reliability projects, are under
construction and are expected to be placed in service by the second quarter of
2023. The last remaining upgrade, the Sudbury-Hudson Reliability Project,
received siting approval, however one appeal remains pending with expected
resolution in the first quarter of 2022. We spent $53 million during 2021 and we
expect to make additional capital expenditures of approximately $170 million on
these remaining transmission upgrades. There are also several transmission
projects underway in southeastern Massachusetts, including Cape Cod, required to
reinforce the Southeastern Massachusetts transmission system and bring the
system into compliance with applicable national and regional reliability
standards. We spent $20 million during 2021 and we expect to make additional
capital expenditures of approximately $140 million on these transmission
upgrades.

Distribution activity: A summary of distribution capital expenditure is as follows:

For the years ended the 31st of December,

                                                 NSTAR                               Total
(Millions of Dollars)          CL&P            Electric            PSNH            Electric             Natural Gas           Water              Total
2021
Basic Business              $ 256.2          $   179.9          $  56.0          $    492.1          $       206.1          $  16.5          $   714.7
Aging Infrastructure          178.0              219.1             67.7               464.8                  509.6            127.1            1,101.5
Load Growth and Other          80.2              170.5             37.1               287.8                   83.3              0.6              371.7
Total Distribution            514.4              569.5            160.8             1,244.7                  799.0            144.2            2,187.9
Solar                             -               (0.6)               -                (0.6)                     -                -               (0.6)
Total                       $ 514.4          $   568.9          $ 160.8          $  1,244.1          $       799.0            144.2          $ 2,187.3

2020
Basic Business              $ 233.4          $   195.1          $  52.4          $    480.9          $        88.2          $  10.9          $   580.0
Aging Infrastructure          179.9              237.1             80.2               497.2                  391.3            115.5            1,004.0
Load Growth and Other          77.8              110.8             21.3               209.9                   65.6              0.8              276.3
Total Distribution            491.1              543.0            153.9             1,188.0                  545.1            127.2            1,860.3
Solar                             -                1.4                -                 1.4                      -                -                1.4
Total                       $ 491.1          $   544.4          $ 153.9          $  1,189.4          $       545.1          $ 127.2          $ 1,861.7

2019
Basic Business              $ 228.7          $   201.0          $  47.3          $    477.0          $        71.2          $  15.0          $   563.2
Aging Infrastructure          224.5              255.5             90.8               570.8                  315.2             93.9              979.9
Load Growth and Other          59.6               89.4             16.8               165.8                   66.8              1.5              234.1
Total Distribution            512.8              545.9            154.9             1,213.6                  453.2            110.4            1,777.2
Solar and Other                   -                7.5                -                 7.5                      -                -                7.5
Total                       $ 512.8          $   553.4          $ 154.9          $  1,221.1          $       453.2          $ 110.4          $ 1,784.7



For the electric distribution business, basic business includes the purchase of
meters, tools, vehicles, information technology, transformer replacements,
equipment facilities, and the relocation of plant. Aging infrastructure relates
to reliability and the replacement of overhead lines, plant substations,
underground cable replacement, and equipment failures. Load growth and other
includes requests for new business and capacity additions on distribution lines
and substation additions and expansions.

For the natural gas distribution business, basic business addresses daily
operational needs including meters, pipe relocations due to public works
projects, vehicles, and tools. Aging infrastructure projects seek to improve the
reliability of the system through enhancements related to cast iron and bare
steel replacement of main and services, corrosion mediation, and station
upgrades. Load growth and other reflects growth in existing service territories
including new developments, installation of services, and expansion.

For the water distribution business, basic business addresses daily operational
needs including periodic meter replacement, water main relocation, facility
maintenance, and tools. Aging infrastructure relates to reliability and the
replacement of water mains, regulators, storage tanks, pumping stations,
wellfields, reservoirs, and treatment facilities. Load growth and other reflects
growth in our service territory, including improvements of acquisitions,
installation of new services, and interconnections of systems.

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Projected Capital Expenditures:  A summary of the projected capital expenditures
for the regulated companies' electric transmission and for the total electric
distribution, natural gas distribution and water distribution for 2022 through
2026, including information technology and facilities upgrades and enhancements
on behalf of the regulated companies, is as follows:

                                                                                 Years
                                                                                                                          2022 - 2026
(Millions of Dollars)                2022             2023             2024             2025              2026               Total
CL&P Transmission                 $   381          $   240          $   218          $    207          $    201          $    1,247
NSTAR Electric Transmission           459              462              382               459               446               2,208
PSNH Transmission                     278              277              261               168               161               1,145
 Total Electric Transmission      $ 1,118          $   979          $   861          $    834          $    808          $    4,600
Electric Distribution             $ 1,450          $ 1,469          $ 1,391          $  1,372          $  1,338          $    7,020
Natural Gas Distribution              921              849              926               895               938               4,529
 Total Electric and Natural Gas
Distribution                      $ 2,371          $ 2,318          $ 2,317 

$2,267 $2,276 $11,549
Water supply

                $   154          $   163          $   176          $    190          $    206          $      889
Information Technology and All
Other                             $   254          $   224          $   208          $    203          $    214          $    1,103
Total                             $ 3,897          $ 3,684          $ 3,562          $  3,494          $  3,504          $   18,141


The projections do not include investments related to offshore wind projects.

Actual capital expenditures may differ from amounts projected for the businesses and years above.


Acquisition of New England Service Company: Following receipt of all required
approvals, on December 1, 2021, Aquarion acquired New England Service Company
(NESC), pursuant to a definitive agreement entered into on April 8, 2021. The
acquisition was structured as a stock-for-stock merger and Eversource issued
462,517 treasury shares at closing for a purchase price of $38.1 million. NESC's
utility subsidiaries provided regulated water service to approximately 10,000
customers in Connecticut, Massachusetts, and New Hampshire.

Offshore Wind Business: Our offshore wind business includes a 50 percent
ownership interest in North East Offshore, which holds PPAs and contracts for
the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as
offshore leases issued by BOEM. Our offshore wind projects are being developed
and constructed through a joint and equal partnership with Ørsted. This
partnership also participates in new procurement opportunities for offshore wind
energy in the Northeast U.S.

The offshore leases include a 257 square-mile ocean lease off the coasts of
Massachusetts and Rhode Island and a separate, adjacent 300-square-mile ocean
lease located approximately 25 miles south of the coast of Massachusetts. In
aggregate, these ocean lease sites jointly-owned by Eversource and Ørsted could
eventually develop at least 4,000 MW of clean, renewable offshore wind energy.

The following table provides a summary of major Eversource and Ørsted projects with announced contracts:


     Wind Project           State Servicing        Size (MW)    Term (Years)     Price per MWh             Pricing Terms            Contract 

Status

                                                                                                   Fixed price contract; no price
   Revolution Wind            Rhode Island            400            20              $98.43                  escalation                 Approved
                                                                                                     Fixed price contracts; no
   Revolution Wind            Connecticut             304            20         $98.43 - $99.50           price escalation              Approved
                                                                                                      2 percent average price
   South Fork Wind          New York (LIPA)            90            20             $160.33                  escalation                 Approved
                                                                                                      2 percent average price
   South Fork Wind          New York (LIPA)            40            20              $86.25                  escalation                 Approved
                                                                                                   Fixed price contract; no price
     Sunrise Wind          New York (NYSERDA)       924 (1)          25           $110.37 (2)                escalation                 Approved


(1) Contracted capacity increased from 880 MW to 924 MW, as permitted by the initial agreement with NYSERDA. (2) Strike price of the Offshore Wind Renewable Energy Certificate (OREC) Index.


As of December 31, 2021 and 2020, Eversource's total equity investment balance
in its offshore wind business was $1.21 billion and $887 million, respectively.
This equity investment includes capital expenditures for the three projects, as
well as capitalized costs related to future development, acquisition costs of
offshore lease areas, and capitalized interest.

Our offshore wind projects are subject to receipt of federal, state and local
approvals necessary to construct and operate the projects. The federal
permitting process is led by BOEM, and state approvals are required from New
York, Rhode Island and Massachusetts. Significant delays in the siting and
permitting process resulting from the timeline for obtaining approval from BOEM
and the state and local agencies could adversely impact the timing of these
projects' in-service dates.

Federal Siting and Permitting Process: The federal siting and permitting process
for each of our offshore wind projects commence with the filing of a
Construction and Operations Plan (COP) application with BOEM. The first major
milestone in the BOEM review process is an issuance of a Notice of Intent (NOI)
to complete an Environmental Impact Statement (EIS). BOEM then provides a final
review schedule for the project's COP approval. BOEM conducts environmental and
technical reviews of the COP. The EIS assesses the environmental, social, and
economic impacts of constructing the project and recommends measures to minimize
impacts. The Final EIS will inform BOEM in deciding whether to approve the
project or to approve with modifications and BOEM will then issue its Record of
Decision. BOEM issues its final approval of the COP following the Record of
Decision.

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South Fork Wind filed its COP application with BOEM in 2018 and BOEM issued the
NOI in 2018. In August 2020, South Fork Wind received the final review schedule
from BOEM regarding its COP approval. In January 2021, BOEM released its Draft
EIS for the South Fork Wind project and in August 2021, BOEM released its Final
EIS. On November 24, 2021, BOEM issued its Record of Decision, which concluded
BOEM's environmental review of the project and identified the recommended
configuration. The Record of Decision supported South Fork Wind's proposed
turbine layout. On January 18, 2022, South Fork Wind received BOEM's final
approval of its COP. The COP approval outlines the project's one nautical mile
turbine spacing, the requirements on the construction methodology for all work
occurring in federal ocean waters, and mitigation measures to protect marine
habitats and species.

Revolution Wind and Sunrise Wind filed their COP applications with BOEM in March
2020 and September 2020, respectively. On April 30, 2021, Revolution Wind
received BOEM's NOI to prepare an EIS for the review of the COP submitted by
Revolution Wind. For Revolution Wind, a final EIS is expected in the first
quarter of 2023, the Record of Decision in the second quarter of 2023, and final
approval is expected in the third quarter of 2023. On August 31, 2021, Sunrise
Wind received BOEM's NOI to prepare an EIS for the review of the COP. For
Sunrise Wind, a final EIS and Record of Decision is expected in the third
quarter of 2023, and final approval is expected in the fourth quarter of 2023.

South Fork Wind, Revolution Wind and Sunrise Wind are each referred to as “Covered project” in accordance with Title 41 of Fixing America’s Surface Transportation Act (FAST41) and a Major infrastructure project under section 3(e) of Executive Order 13807, which gives greater federal attention to meeting project approval timelines.


State and Local Siting and Permitting Process: South Fork Wind commenced the New
York state siting process in 2018. On September 17, 2020, South Fork Wind filed
a Joint Proposal in the New York State Article VII siting application. Among
other things, the Joint Proposal included proposed mitigation for certain
environmental, community and construction impacts associated with constructing
the project. South Fork Wind was joined by PSEG Long Island and several citizens
advocacy organizations. On October 9, 2020, the Joint Proposal was signed by the
New York Departments of Public Service, Environmental Conservation,
Transportation and State as well as the Office of Parks, Recreation and Historic
Preservation. On March 18, 2021, the New York Public Service Commission approved
an order adopting the Joint Proposal and granting a Certificate of Environmental
Compatibility and Public Need. Two petitions for re-hearing of the New York
Public Service Commission decision have been filed, and South Fork Wind
responded on May 3, 2021 opposing the re-hearing requests. In April 2021, South
Fork Wind filed its Environmental Management and Construction Plan (EM&CP) with
the New York Public Service Commission, which details the plans on how the
project will be constructed in accordance with the conditions of the approved
Joint Proposal. Comments from reviewing agencies and parties have been received
and South Fork Wind has responded to and addressed those comments in the plan
which was re-submitted in September 2021. The project received approval of the
EM&CP in November 2021.

On September 10, 2020, the Town of East Hampton and the East Hampton Town
Trustees announced that they had reached an agreement with South Fork Wind to
issue the necessary easements and other real estate rights necessary to
construct the South Fork Wind project. The Town approved the easements on
January 21, 2021, and Trustees approved the real estate lease on January 25,
2021.

State permitting applications in Rhode Island for Revolution Wind and in New
York for Sunrise Wind were filed in December 2020. The Revolution Wind state
siting application was deemed complete on January 22, 2021, and the preliminary
hearing was completed on March 22, 2021. On April 26, 2021, the Rhode Island
Energy Facilities Siting Board issued a Preliminary Decision and Order on
scheduling with Advisory Opinions for local and state agencies. All advisory
opinions were received in August, in accordance with the expedited schedule, and
evidentiary hearings began in October 2021. The Sunrise Wind state siting
application was deemed complete on July 1, 2021, initiating the formal review
process, and Sunrise Wind filed a formal notice of intent to commence settlement
negotiations towards a Joint Proposal on August 31, 2021. Settlement
negotiations are ongoing.

Construction Process - South Fork Wind: South Fork Wind has received all
required approvals to start construction and the project has now entered the
construction phase. Site preparation and onshore activities for the project's
underground onshore transmission line and construction of the onshore
interconnection facility located in East Hampton, New York will be the first to
begin. Offshore installation, including the project's monopile foundations,
11-megawatt wind turbines, and offshore substation, is expected to occur in
2023. Construction-related purchase agreements with third-party contractors and
materials contracts have largely been secured. South Fork Wind faces several
challenges and appeals of New York State agency approvals, however it believes
it will be able to overcome these challenges.

Projected In-Service Dates: We expect the South Fork Wind project to be
in-service by the end of 2023. For Revolution Wind and Sunrise Wind, based on
the BOEM permit schedule included in each respective NOI outlining when BOEM
will complete its review of the COP, we currently expect in-service dates in
2025 for both projects, and are continuing to analyze the overall project
schedules.

Projected Investments: For Revolution Wind and Sunrise Wind, we are preparing
our final project designs and advancing the appropriate federal, state, and
local siting and permitting processes along with our offshore wind partner,
Ørsted. Construction of South Fork Wind is now underway. Construction-related
purchase agreements with third-party contractors and materials contracts are
approximately 80 percent secured. Subject to advancing our final project designs
and federal, state and local permitting processes and construction schedules, we
currently expect to make investments in our offshore wind business between $0.9
billion and $1.0 billion in 2022 and expect to make investments for our three
projects in total between $3.0 billion and $3.6 billion from 2023 through 2026.
These estimates assume that the three projects are completed and are in-service
by the end of 2025, as planned.

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FERC Regulatory Matters


FERC ROE Complaints: Four separate complaints were filed at the FERC by
combinations of New England state attorneys general, state regulatory
commissions, consumer advocates, consumer groups, municipal parties and other
parties (collectively, the Complainants). In each of the first three complaints,
filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively,
the Complainants challenged the NETOs' base ROE of 11.14 percent that had been
utilized since 2005 and sought an order to reduce it prospectively from the date
of the final FERC order and for the separate 15-month complaint periods. In the
fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs'
base ROE billed of 10.57 percent and the maximum ROE for transmission incentive
(incentive cap) of 11.74 percent, asserting that these ROEs were unjust and
unreasonable.

The ROE originally billed during the period October 1, 2011 (beginning of the
first complaint period) through October 15, 2014 consisted of a base ROE of
11.14 percent and incentives up to 13.1 percent. On October 16, 2014, the FERC
set the base ROE at 10.57 percent and the incentive cap at 11.74 percent for the
first complaint period. This was also effective for all prospective billings to
customers beginning October 16, 2014. This FERC order was vacated on April 14,
2017 by the U.S. Court of Appeals for the D.C. Circuit (the Court).

All amounts associated with the first complaint period have been refunded.
Eversource has recorded a reserve of $39.1 million (pre-tax and excluding
interest) for the second complaint period as of both December 31, 2021 and 2020.
This reserve represents the difference between the billed rates during the
second complaint period and a 10.57 percent base ROE and 11.74 percent incentive
cap. The reserve consisted of $21.4 million for CL&P, $14.6 million for NSTAR
Electric and $3.1 million for PSNH as of both December 31, 2021 and 2020.

On October 16, 2018, FERC issued an order on all four complaints describing how
it intends to address the issues that were remanded by the Court. FERC proposed
a new framework to determine (1) whether an existing ROE is unjust and
unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs
were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019
and reply briefs were filed on March 8, 2019. The NETOs' brief was supportive of
the overall ROE methodology determined in the October 16, 2018 order provided
the FERC does not change the proposed methodology or alter its implementation in
a manner that has a material impact on the results.

The FERC order included illustrative calculations for the first complaint using
FERC's proposed frameworks with financial data from that complaint. Those
illustrative calculations indicated that for the first complaint period, for the
NETOs, which FERC concludes are of average financial risk, the preliminary just
and reasonable base ROE is 10.41 percent and the preliminary incentive cap on
total ROE is 13.08 percent. If the results of the illustrative calculations were
included in a final FERC order for each of the complaint periods, then a 10.41
percent base ROE and a 13.08 percent incentive cap would not have a significant
impact on our financial statements for all of the complaint periods. These
preliminary calculations are not binding and do not represent what we believe to
be the most likely outcome of a final FERC order.

On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending
transmission ROE complaints against the Midcontinent ISO (MISO) transmission
owners, in which FERC adopted a new methodology for determining base ROEs.
Various parties sought rehearing. On December 23, 2019, the NETOs filed
supplementary materials in the NETOs' four pending cases to respond to this new
methodology because of the uncertainty of the applicability to the NETOs' cases.

On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing
of the MISO transmission owners' cases, in which FERC again changed its
methodology for determining the MISO transmission owners' base ROEs. On November
19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No.
569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A.
The new methodology differs significantly from the methodology proposed by FERC
in its October 16, 2018 order to determine the NETOs' base ROEs in its four
pending cases. FERC Opinion Nos. 569-A and 569-B are currently under appeal with
the Court.

Given the significant uncertainty regarding the applicability of the FERC
opinions in the MISO transmission owners' two complaint cases to the NETOs'
pending four complaint cases, Eversource concluded that there is no reasonable
basis for a change to the reserve or recognized ROEs for any of the complaint
periods at this time. As well, Eversource cannot reasonably estimate a range of
any gain or loss for any of the four complaint proceedings at this time.

Eversource, CL&P, NSTAR Electric and PSNH currently record revenues at the 10.57
percent base ROE and incentive cap at 11.74 percent established in the October
16, 2014 FERC order.

A change of 10 basis points to the base ROE used to establish the reserves would
impact Eversource's after-tax earnings by an average of approximately $3 million
for each of the four 15-month complaint periods. Prospectively from the date of
a final FERC order implementing a new base ROE, based off of estimated 2021 rate
base, a change of 10 basis points to the base ROE would impact Eversource's
future annual after-tax earnings by approximately $5 million per year, and will
increase slightly over time as we continue to invest in our transmission
infrastructure.

FERC Notice of Inquiry on ROE: On March 21, 2019, FERC issued a Notice of
Inquiry (NOI) seeking comments from all stakeholders on FERC's policies for
evaluating ROEs for electric public utilities, and interstate natural gas and
oil pipelines. On June 26, 2019, the NETOs jointly filed comments supporting the
methodology established in the FERC's October 16, 2018 order with minor
enhancements going forward. The NETOs jointly filed reply comments in the FERC
ROE NOI on July 26, 2019. On May 12, 2020, the NETOs filed supplemental comments
in the NOI ROE docket. At this time, Eversource cannot predict how this
proceeding will affect its transmission ROEs.

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FERC Notice of Inquiry and Proposed Rulemaking on Transmission Incentives: On
March 21, 2019, FERC issued an NOI seeking comments on FERC's policies for
implementing electric transmission incentives. On June 26, 2019, Eversource
filed comments requesting that FERC retain policies that have been effective in
encouraging new transmission investment and remain flexible enough to attract
investment in new and emerging transmission technologies. Eversource filed reply
comments on August 26, 2019. On March 20, 2020, FERC issued a Notice of Proposed
Rulemaking (NOPR) on transmission incentives. The NOPR intends to revise FERC's
electric transmission incentive policies to reflect competing uses of
transmission due to generation resource mix, technological innovation and shifts
in load patterns. FERC proposes to grant transmission incentives based on
measurable project economics and reliability benefits to consumers rather than
its current project risks and challenges framework.  On July 1, 2020, Eversource
filed comments generally supporting the NOPR.

On April 15, 2021, FERC issued a Supplemental NOPR that proposes to eliminate
the existing 50 basis point return on equity for utilities that have been
participating in a regional transmission organization (RTO ROE incentive) for
more than three years. On June 25, 2021, the NETOs jointly filed comments
strongly opposing the Commission's proposal. On July 26, 2021, the NETOs filed
Supplemental NOPR reply comments responding to various parties advocating for
the elimination of the RTO Adder. If the FERC issues a final order eliminating
the RTO ROE incentive as proposed in the Supplemental NOPR, the estimated annual
impact (using 2021 estimated rate base) on Eversource's after-tax earnings is
approximately $17 million. The Supplemental NOPR contemplates an effective date
30 days from the final order.

At this time, Eversource cannot predict the final outcome of these proceedings, including possible appellate review, and the resulting impact on its transmission incentives.

Regulatory developments and pricing issues


Electric, Natural Gas and Water Utility Retail Tariff Rates: Each Eversource
utility subsidiary is subject to the regulatory jurisdiction of the state in
which it operates:  CL&P, Yankee Gas and Aquarion operate in Connecticut and are
subject to PURA regulation; NSTAR Electric, NSTAR Gas, EGMA and Aquarion operate
in Massachusetts and are subject to DPU regulation; and PSNH and Aquarion
operate in New Hampshire and are subject to NHPUC regulation.  The regulated
companies' distribution rates are set by their respective state regulatory
commissions, and their tariffs include mechanisms for periodically adjusting
their rates for the recovery of specific incurred costs.

Base Distribution Rates:  In Connecticut, electric and natural gas utilities are
required to file a distribution rate case within four years of the last rate
case. CL&P's and Yankee Gas' distribution rates were each established in 2018
PURA-approved rate case settlement agreements. On October 27, 2021, PURA
approved a settlement agreement at CL&P that included a current base
distribution rate freeze until no earlier than January 1, 2024. The approval of
the settlement agreement satisfies the Connecticut statute of rate review
requirements that requires electric utilities to file a distribution rate case
within four years of the last rate case. Aquarion is not required to initiate a
rate review with the PURA on a set schedule. Aquarion rates were established in
a 2013 PURA-approved rate case.

In Massachusetts, electric distribution companies are required to file at least
one distribution rate case every five years, and natural gas local distribution
companies to file at least one distribution rate case every 10 years, and those
companies are limited to one settlement agreement in any 10-year period. NSTAR
Electric's distribution rates were established in a 2017 DPU-approved rate case.
On January 14, 2022, NSTAR Electric filed an application with the DPU for an
increase in base distribution rates, effective January 1, 2023. NSTAR Gas'
distribution rates were established in an October 2020 DPU-approved rate case.
EGMA's distribution rates were established in an October 2020 DPU-approved rate
settlement agreement. Aquarion is not required to initiate a rate review with
the DPU. Aquarion rates were established in a 2018 DPU-approved rate case.

In New Hampshire, PSNH's distribution rates were established in a December 2020
NHPUC-approved rate case settlement agreement. Aquarion rates were established
in a 2013 NHPUC-approved rate case, further revised in 2016. On December 18,
2020, Aquarion filed an application with the NHPUC for a permanent increase in
base rates and a decision by the NHPUC is expected in the second quarter of
2022.

Rate Reconciling Mechanisms: The Eversource electric distribution companies
obtain and resell power to retail customers who choose not to buy energy from a
competitive energy supplier.  The natural gas distribution companies procure
natural gas for firm and seasonal customers. These energy supply procurement
costs are recovered from customers in energy supply rates that are approved by
the respective state regulatory commission.  The rates are reset periodically
and are fully reconciled to their costs.  Each electric and natural gas
distribution company fully recovers its energy supply costs through approved
regulatory rate mechanisms on a timely basis and, therefore, such costs have no
impact on earnings.

The electric and natural gas distribution companies also recover certain other
costs in retail rates on a fully reconciling basis through regulatory
commission-approved cost tracking mechanisms and, therefore, recovery of these
costs has no impact on earnings. Costs recovered through cost tracking
mechanisms include, among others, electric retail transmission charges, energy
efficiency program costs, electric restructuring and stranded cost recovery
revenues (including securitized RRB charges), certain capital tracking
mechanisms for infrastructure improvements, and additionally for the
Massachusetts utilities, pension and PBOP benefits, net metering for distributed
generation, and solar-related programs. The reconciliation filings compare the
total actual costs allowed to revenue requirements related to these services and
the difference between the costs incurred (or the rate recovery allowed) and the
actual costs allowed is deferred and included, to be either recovered or
refunded, in future customer rates.  These cost tracking mechanisms also include
certain incentives earned, return on capital tracking mechanisms, and carrying
charges that are billed in rates to customers, which do impact earnings.
                                       38
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Excess ADIT Amortization: Eversource amortized excess ADIT (EDIT) of
$69.1 million in 2021, $48.7 million in 2020 and $37.4 million in 2019. In 2021,
EDIT amortization was $9.8 million at CL&P, $43.2 million at NSTAR Electric, and
$10.5 million at PSNH. Of the 2021 total EDIT amortized, the Company's
transmission businesses amortized $15.4 million pursuant to FERC orders issued
on December 22, 2021 and December 30, 2021 that approved the refund of EDIT to
its transmission customers ($1.6 million at CL&P, $12.0 million at NSTAR
Electric and $1.8 million at PSNH). The effective date of these FERC orders was
January 27, 2020, resulting in catch-up amortization recorded in 2021. EDIT
amortization in 2020 and 2019 pertained solely to the Company's distribution
businesses. The refund of these EDIT regulatory liabilities to customers will
generally be made over the same period as the remaining useful lives of the
underlying assets that gave rise to the ADIT liabilities. The refund to
customers and resulting amortization of the EDIT regulatory liabilities results
in lower revenues (for the amortization of the EDIT and the tax gross up
portion) and lower income tax expense (for the amortization of EDIT and lower
current tax benefits from the tax gross up portion) on the statement of income.
The refund of EDIT results in a lower effective tax rate and no impact on net
income.

Connecticut:

CL&P Deferred Storm Costs: In 2021 and 2020, multiple tropical and severe storms
caused extensive damage to CL&P's electric distribution systems and customer
outages, along with significant pre-staging costs. These storms resulted in
deferred pre-staging and storm restoration costs at CL&P of $232 million for
2021 storms and $344 million for 2020 storms, including the catastrophic impact
of Tropical Storm Isaias in August 2020, among others. Management believes that
all of these storm costs were prudently incurred and meet the criteria for
specific cost recovery. As part of CL&P's October 1, 2021 settlement agreement
described below, it agreed to freeze its current base distribution rates
(including storm costs) until no earlier than January 1, 2024.

CL&P Tropical Storm Isaias Costs: On August 4, 2020, Tropical Storm Isaias
caused catastrophic damage to our electric distribution system, which resulted
in significant numbers and durations of customer outages, primarily in
Connecticut. In terms of customer outages, this storm was one of the worst in
CL&P's history. PURA will investigate the prudency of costs incurred by CL&P to
restore service in response to Tropical Storm Isaias. That investigation is
expected to occur either in a separate proceeding not yet initiated or as part
of CL&P's next rate review proceeding. Tropical Storm Isaias resulted in
deferred storm restoration costs of approximately $234 million at CL&P and
$251 million at Eversource as of December 31, 2021. Although PURA found that
CL&P's performance in its preparation for and response to Tropical Storm Isaias
fell below applicable performance standards in certain instances, CL&P believes
it will be able to present credible evidence in a future proceeding
demonstrating there is no reasonably close causal connection between the alleged
sub-standard performance and the storm costs incurred. While it is possible that
some amount of storm costs may be disallowed by the PURA in a future proceeding,
any such amount cannot be estimated at this time. Eversource and CL&P continue
to believe that these storm restoration costs associated with Tropical Storm
Isaias were prudently incurred and meet the criteria for cost recovery; and as a
result, management does not expect the storm cost review by the PURA to have a
material impact on the financial position or results of operations of Eversource
or CL&P.

CL&P Tropical Storm Isaias Response Investigation: In August 2020, PURA opened a
docket to investigate the preparation for and response to Tropical Storm Isaias
by Connecticut utilities, including CL&P. On April 28, 2021, PURA issued a final
decision on CL&P's compliance with its emergency response plan that concluded
CL&P failed to comply with certain storm performance standards and was imprudent
in certain instances. Specifically, PURA concluded that CL&P did not satisfy the
performance standards for managing its municipal liaison program, timely
removing electrical hazards from blocked roads, communicating critical
information to its customers, or meeting its obligation to secure adequate
external contractor and mutual aid resources in a timely manner. Based on its
findings, PURA ordered CL&P to adjust its future rates in a pending or future
rate proceeding to reflect a monetary penalty in the form of a downward
adjustment of 90 basis points in its allowed rate of return on equity (ROE),
which is currently 9.25 percent. In its decision, PURA explained that additional
monetary penalties and further enforcement orders pursuant to Connecticut
statute would be considered in a separate proceeding that was initiated on May
6, 2021.

On May 6, 2021, as part of the penalty proceeding, PURA issued a notice of
violation that included an assessment of $30 million, consisting of a
$28.4 million civil penalty for non-compliance with storm performance standards
to be provided as credits on customer bills and a $1.6 million fine for
violations of accident reporting requirements to be paid to the State of
Connecticut's general fund. On July 14, 2021, PURA issued a final decision in
this penalty proceeding that included an assessment of $28.6 million,
maintaining the $28.4 million performance penalty and reducing the $1.6 million
fine for accident reporting to $0.2 million. The $28.4 million performance
penalty is currently being credited to customers on electric bills beginning on
September 1, 2021 over a one-year period. The $28.4 million is the maximum
statutory penalty amount under applicable Connecticut law in effect at the time
of Tropical Storm Isaias, which is 2.5 percent of CL&P's annual distribution
revenues. The liability for the performance penalty was recorded as a current
regulatory liability on CL&P's balance sheet and as a reduction to Operating
Revenues on the year ended December 31, 2021 statement of income. The after-tax
earnings impact of this charge was $0.07 per share.

PURA New Rate Design and Rate Review Proceeding: Pursuant to an October 2020
Connecticut law, PURA opened a proceeding related to new
rate designs to consider the implementation of an interim rate decrease,
low-income and economic development rates for electric customers, and a
review of that rate design implementation process. The proceeding has separate
phases. In the first phase, PURA issued a final decision on June
23, 2021 directing CL&P to offer new rates to certain small commercial and
industrial customers that will reduce demand charges and instead
include volumetric charges for electricity based on kWh used. Customers can
elect to transition to these new offered rates, which became effective
November 1, 2021. PURA's decision in the first phase of the proceeding is not
expected to have a material impact on CL&P's earnings,
financial position, or cash flows. The second phase of this proceeding was
addressed in PURA's September 14, 2021 decision, and would have resulted in an
interim rate decrease associated with a 45 basis point reduction in CL&P's
authorized ROE. This phase of the proceeding was resolved as a result of the
October 2021 settlement agreement, described below. In addition, PURA is also
investigating low-income and other economic development rates. A procedural
schedule for this part of the proceeding has not yet been set by the PURA.

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CL&P Settlement Agreement: On October 1, 2021, CL&P entered into a settlement
agreement with the DEEP, Office of Consumer Counsel (OCC), Office of the
Attorney General (AG) and the Connecticut Industrial Energy Consumers, resolving
certain issues that arose in then-pending regulatory proceedings initiated by
the PURA. PURA approved the settlement agreement on October 27, 2021. In the
settlement agreement, CL&P agreed to provide a total of $65 million of customer
credits, which were distributed based on customer sales over a two-month billing
period from December 1, 2021 to January 31, 2022. CL&P also agreed to
irrevocably set aside $10 million to provide bill payment assistance to certain
existing non-hardship and hardship customers carrying arrearages, as approved by
the PURA, with the objective of disbursing the funds prior to April 30, 2022.
CL&P recorded a current regulatory liability of $75 million on the balance sheet
associated with the provisions of the settlement agreement, with a $65 million
pre-tax charge as a reduction to Operating Revenues associated with the customer
credits and a $10 million charge to Operations and Maintenance expense
associated with the customer assistance fund on the year ended December 31, 2021
statement of income.

In exchange for the $75 million of customer credits and assistance, PURA's
interim rate reduction docket was resolved without findings. As a result of the
settlement agreement, neither the 90 basis point reduction to CL&P's return on
equity introduced in PURA's storm-related decision issued April 28, 2021, nor
the 45 basis point reduction to CL&P's return on equity included in PURA's
decision issued September 14, 2021 in the interim rate reduction docket, will be
implemented.

CL&P has also agreed to freeze its current base distribution rates, subject to
the customer credits described above, until no earlier than January 1, 2024. The
rate freeze applies only to base distribution rates (including storm costs) and
not to other rate mechanisms such as the retail rate components, rate
reconciling mechanisms, formula rates and any other adjustment mechanisms. The
rate freeze also does not apply to any cost recovery mechanism outside of the
base distribution rates with regard to grid-modernization initiatives or any
other proceedings, either currently pending or that may be initiated during the
rate freeze period, that may place additional obligations on CL&P. The approval
of the settlement agreement satisfies the Connecticut statute of rate review
requirements that requires electric utilities to file a distribution rate case
within four years of the last rate case.

As part of the settlement agreement, CL&P agreed to withdraw with prejudice its
pending appeals of PURA's decisions dated April 28, 2021 and July 14, 2021
related to Storm Isaias and agreed to waive its right to file an appeal and seek
a judicial stay of the September 14, 2021 decision in the interim rate reduction
docket. The settlement agreement assures that CL&P will have the opportunity to
petition for and demonstrate the prudency of the storm costs incurred to respond
to customer outages associated with Storm Isaias in a future ratemaking
proceeding.

The cumulative pre-tax impact of the settlement agreement and the Storm Isaias
assessment imposed in PURA's April 28, 2021 and July 14, 2021 decisions totaled
$103.6 million, and the after-tax earnings impact was $86.1 million, or $0.25
per share, for the year ended December 31, 2021.

CL&P Rate Adjustment Mechanisms (RAM) Filing: On July 31, 2020, PURA temporarily
suspended its June 26, 2020 approval of certain delivery rate components
effective July 1, 2020, and ordered CL&P to restore rates to those in effect as
of June 30, 2020 in order to allow PURA time to reexamine the rates. Rates were
adjusted effective August 1, 2020. On December 2, 2020, PURA issued a final
decision in which it adjusted the timing of the annual rate adjustments for the
Transmission Adjustment Clause (TAC) charge, the Non-Bypassable Federally
Mandated Congestion Charge (NBFMCC), the Electric System Improvements Tracker
(ESI), Competitive Transition Assessment (CTA), System Benefits Charge (SBC) and
Revenue Decoupling Mechanism (RDM) so that these rates take effect on May 1st of
each year. On April 28, 2021, PURA issued its interim decision on CL&P's
proposal that accepted the May 1, 2021 rate proposals for the CTA, TAC, ESI and
RDM, but ordered that these rate changes go into effect on June 1, 2021, as
opposed to May 1, 2021. Further, PURA elected to keep in place the current rates
for the NBFMCC and SBC until further review of the costs being recovered in
those rates could be performed. Finally, PURA indicated it would further review
CL&P's proposal to begin recovery of 2020 under-recoveries associated with these
rates on October 1, 2021.

On September 15, 2021, PURA issued its final decision in the 2020 RAM
reconciliation filing, which required no adjustment to the GSC, BFMCC, NBFMCC,
SBC, CTA, ESI and base distribution rates, but resulted in changes to the TAC
and RDM rates effective October 1, 2021. As part of this decision, PURA also
approved the recovery of cumulative under-recoveries associated with the NBMFCC,
TAC, and RDM of $193 million effective October 1, 2021. The NBFMCC and TAC
under-recoveries will be recovered over a 31-month period and the RDM
under-recovery will be recovered over a 15-month period.

CL&P Impact of 2021 Rate Changes (Excluding Supply Rates): On June 1, 2021, CL&P
implemented an overall rate increase of $0.00411 per kWh for residential
customers. The rate increase included delivery rate changes for the CTA, TAC,
ESI and RDM charges. Partially offsetting the rate increase was a base
distribution rate decrease, which was driven by a reduction to storm cost
amortization resulting from a 2019 PURA decision. For residential customers with
700 kWh monthly usage, the impact of the June 1, 2021 rate changes equated to an
increase of $2.88 on monthly customer bills.

On September 1, 2021, CL&P adjusted its rates for the $28.4 million penalty
imposed by the PURA for non-compliance with performance standards that is being
provided as credits on customer bills over a one-year period. On October 1,
2021, CL&P implemented new TAC and RDM delivery rates. In total, CL&P
implemented an overall net rate increase of $0.00174 per kWh for residential
Rate 1 customers for these rate component charges, net of the rate decrease for
the storm penalty credit. The impact of the September 1 and October 1, 2021 rate
changes equated to an increase of $1.22 on monthly customer bills for
residential customers with 700 kWh monthly usage.

On December 1, 2021, CL&P adjusted its rates for the $65 million of customer
credits resulting from the October settlement agreement that were distributed
based on customer sales over a two-month period from December 1, 2021 to January
31, 2022. For residential customers with 700 kWh monthly usage, the impact of
the settlement credit equated to $34.25 for the two-month period.

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Residential Customer Bill Credits and Reimbursements for Storm-Related Outages:
On June 30, 2021, in accordance with an October 2020
Connecticut law, PURA issued a final decision establishing standards and
procedures for residential customers to receive bill credits and other
compensation for spoiled food and medicine from Connecticut utilities, including
CL&P, after future weather-related emergencies. The PURA
decision requires, effective after July 1, 2021, that Connecticut utilities
provide customers with a $25 bill credit for each 24-hour time period
following the initial 96 consecutive hours of an electric distribution outage
after a major storm or emergency. The decision also authorizes residential
customers to submit a claim to receive up to $250 in compensation for any
medication and food that expired or spoiled due to an electric distribution
outage lasting longer than 96 consecutive hours. The decision also establishes a
process by which the electric utilities (i) can elect to submit a filing within
seven days of a storm event that proposes when the 96-hour time period commenced
for that storm event based on relevant weather data, when it was safe to deploy
crews into the field, and the other relevant factors identified in the decision;
and (ii) can elect to seek within 14 days of a storm event a waiver from
providing customer bill credits, for reasons such as line worker safety and
continuing emergency or potentially hazardous conditions that prevented or
delayed restoration activities.

CL&P Performance Based Rate Making: On May 26, 2021, in accordance with an
October 2020 Connecticut law, PURA opened a proceeding to begin to evaluate and
eventually implement performance based regulation for electric distribution
companies. PURA will conduct the proceeding in two phases, with a draft decision
on the first phase and procedural schedule established for the second phase
expected in March 2023. At this time, we cannot predict the ultimate outcome of
this proceeding and the resulting impact to CL&P.

CL&P Advanced Metering Infrastructure Filing: On July 31, 2020, CL&P submitted
to PURA its proposed $512 million Advanced Metering Infrastructure investment
and implementation plan for the years 2021 through 2027. On August 17, 2021,
PURA issued a Notice of Request for Amended EDC Advanced Metering Infrastructure
Proposal. CL&P submitted an Amended Proposal in response to this request on
November 8, 2021, which included additional information as required by the PURA.
As required, the plan includes a full deployment of advanced metering
functionality and a composite business case in support of the Advanced Metering
Infrastructure plan. A procedural schedule in this proceeding has not been
issued by the PURA.

Massachusetts:

NSTAR electricity distribution tariffs: under an inflation-based mechanism,
Electric NSTAR filed its fourth annual performance-based rate adjustment filing on November 10, 2021 and on December 22, 2021the DPU approved a $36.8 million increase in basic distribution rates for the effect on
January 1, 2022.


NSTAR Electric Distribution Rate Case: On January 14, 2022, NSTAR Electric filed
an application with the DPU for approval of an $89 million increase in base
distribution rates, with new rates anticipated to be effective January 1, 2023.
As part of this filing, NSTAR Electric is requesting a renewal of the
performance-based ratemaking plan originally authorized in its last rate case
for up to a ten-year term, alignment with state electrification policy, storm
fund refinements, and Advanced Metering Infrastructure tariff approval. A final
decision from the DPU is expected on December 1, 2022.

NSTAR Electric Grid Modernization and Advanced Metering Infrastructure Filing:
On July 1, 2021, NSTAR Electric submitted for DPU approval its four-year $198.8
million grid modernization plan for the years 2022 through 2025 and proposed
$620 million Advanced Metering Infrastructure investment and implementation plan
for the years 2023 through 2028. As required, the plan includes a ten-year
vision, five-year strategic plan, including a full deployment of advanced
metering functionality, separate four-year grid-facing and customer-facing
short-term investment plans, and a composite business case in support of the
Advanced Metering Infrastructure plan. NSTAR Electric has requested expedited
approval of $38.3 million of the $198.8 million grid modernization plan for
previously approved continuing investments that are currently in process and are
expected to be spent in 2022 so these activities will not be interrupted pending
full plan approval. NSTAR Electric expects DPU guidance for all investment years
by the second quarter of 2022. For Advanced Metering Infrastructure investments,
additional review of the cost recovery mechanism will be conducted in NSTAR
Electric's base distribution rate case that was filed on January 14, 2022 with a
decision expected on December 1, 2022.

NSTAR Electric Storm Threshold Filing: On December 22, 2021, the DPU approved
NSTAR Electric to defer for future recovery the storm cost threshold amounts
associated with six qualifying major storm events that occurred during 2020,
totaling $7.2 million. The DPU approved the deferral of threshold costs that
exceeded four storms (those recovered in base rates plus one additional storm)
until the next rate case proceeding, at which time the DPU will determine the
appropriate level of recovery of storm threshold amounts. In its January 14,
2022 distribution rate case filing, NSTAR Electric is also seeking recovery of
the deferral of threshold costs for an additional seven storms in 2021. The
pre-tax benefit to earnings for the deferral as a regulatory asset of threshold
costs for both the 2020 and 2021 major storms was $15.6 million and was recorded
in the fourth quarter of 2021.

NSTAR Gas and EGMA Distribution Rates and Mitigation Filings: As part of an
inflation-based mechanism, NSTAR Gas submitted its first annual Performance
Based Rate Adjustment filing on September 15, 2021, for rates effective November
1, 2021. As established in the October 7, 2020 EGMA Rate Settlement Agreement,
EGMA filed for its first base distribution rate increase on September 17, 2021,
for rates effective November 1, 2021. Subsequent to those base distribution rate
filings, on October 6, 2021, NSTAR Gas and EGMA made filings with the DPU to
defer recovery of certain costs for the purpose of mitigating November 1, 2021
bill impacts associated with the new delivery rates as a result of increases in
natural gas supply costs, thereby providing rate relief to customers. These
adjustments to rates do not impact the recovery of costs, only the timing of
when the costs are collected in rates. For NSTAR Gas and EGMA, these adjustments
included delaying the decoupling revenue requirement, the recovery of certain
prior period under-collections, and portions of the base distribution rate
change for NSTAR Gas, until November 1, 2022. These adjustments delay recovery
of $16.7 million for NSTAR Gas and $19.7 million for EGMA for a one-year period.
These adjustments result in the under-recovery of costs beginning November 1,
2021, with no material impact on the statement of income.

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For NSTAR Gas, the DPU approved a $13.6 million increase to base distribution
rates on October 29, 2021, effective November 1, 2021. For EGMA, the DPU
approved a $13 million increase to base distribution rates on October 28, 2021,
effective November 1, 2021.

New Hampshire:

PSNH Distribution Rates: In connection with an October 9, 2020 settlement
agreement, the NHPUC approved a permanent rate increase of $45.0 million
effective January 1, 2021. PSNH was also permitted three step increases,
effective January 1, 2021, August 1, 2021, and August 1, 2022, to reflect plant
additions in calendar years 2019, 2020 and 2021, respectively. On December 23,
2020, the NHPUC approved the first step adjustment for 2019 plant in service to
recover a revenue requirement of $10.6 million, effective January 1, 2021. On
July 30, 2021, the NHPUC approved the second step adjustment for 2020 plant in
service to recover a revenue requirement of $11.0 million, subject to
reconciliation after completion of an audit, with rates effective August 1,
2021.

COVID Regulatory Docket: On July 7, 2021, the NHPUC issued an order to New
Hampshire utilities that concluded that recovery of incremental bad debt or
waived late fees related to the COVID-19 pandemic would be addressed in the
context of the utility's next rate case when related costs, to the extent those
costs remain relevant under test year based rate-setting, would be considered in
the context of the utility's full revenue requirement and overall rate of
return. The NHPUC concluded that New Hampshire utilities would not be permitted
to establish a regulatory asset for these items. As a result of the order, in
the second quarter of 2021, PSNH removed its $0.6 million deferral of net
incremental COVID-19 costs.

Energy Efficiency Plan: On November 12, 2021, the NHPUC issued an order
rejecting the proposed 2021 through 2023 energy efficiency plan and
significantly reduced funding and operational functions of the program. PSNH
made programmatic adjustments in late November and December 2021 to ensure
utilization of the 2021 budget and achievement of the 2021 performance
incentive. The order eliminated the recovery of performance incentives beginning
in 2022. PSNH sought rehearing of the order and was denied. There is state
legislation pending that would undo the most impactful effects of the order.
PSNH, as well as various other parties, have appealed the order to the New
Hampshire Supreme Court. The energy efficiency rate for 2022 went into effect
January 1, 2022 at a level that is 29 percent lower than the 2021 rate. However,
effective March 1, 2022, the energy efficiency rate will be restored to the 2021
level. Given the pending legislation that has already passed the New Hampshire
Senate and the four Supreme Court appeals filed, it is likely that at least some
of the provisions of the NHPUC order will be undone. At this time, PSNH cannot
predict the ultimate outcome of this order, and the resulting impact on its
financial statements.

Legislative and policy issues


Federal: On November 5, 2021, Congress passed the Infrastructure Investment and
Jobs Act. The Act provided spending of more than $500 billion on roads,
highways, bridges, public transit, and utilities. For water and sewer utilities,
the Act restored the exclusion from a corporation's income for contributions in
aid of construction where the corporation is a water or sewer utility eliminated
by the Tax Cuts and Jobs Act of 2017. Under the Act, a regulated public utility
that provides water or sewage disposal services can treat money or property
received from any person as a tax-free contribution to capital if it meets
certain criteria for contributions made after 2020. The Act did not have a
material impact on Eversource in 2021.

Massachusetts: On March 26, 2021, Governor Baker signed into law a climate
change bill which permits electric or natural gas distribution companies to
assist Massachusetts municipalities in responding to the risks of climate change
by owning solar facilities equal to up to 10 percent of the total installed
solar generating capacity in Massachusetts as of July 31, 2020. Such facilities
may be paired with energy storage where feasible to do so. This law will allow
each of Eversource's Massachusetts operating companies to own up to
approximately 280 MWs of solar generating facilities in addition to the 70 MWs
previously constructed at NSTAR Electric.

Critical accounting policies


The preparation of financial statements in conformity with GAAP requires
management to make estimates, assumptions and, at times, difficult, subjective
or complex judgments. Changes in these estimates, assumptions and judgments, in
and of themselves, could materially impact our financial position, results of
operations or cash flows. Our management discusses with the Audit Committee of
our Board of Trustees significant matters relating to critical accounting
policies. Our critical accounting policies are discussed below. See the combined
notes to our financial statements for further information concerning the
accounting policies, estimates and assumptions used in the preparation of our
financial statements.

Regulatory Accounting:  Our regulated companies are subject to rate regulation
that is based on cost recovery and meets the criteria for application of
accounting guidance for rate-regulated operations, which considers the effect of
regulation on the timing of the recognition of certain revenues and expenses.
The regulated companies' financial statements reflect the effects of the
rate-making process. The rates charged to the customers of our regulated
companies are designed to collect each company's costs to provide service, plus
a return on investment.

The application of accounting guidance for rate-regulated enterprises results in
recording regulatory assets and liabilities. Regulatory assets represent the
deferral of incurred costs that are probable of future recovery in customer
rates. Regulatory assets are amortized as the incurred costs are recovered
through customer rates. In some cases, we record regulatory assets before
approval for recovery has been received from the applicable regulatory
commission. We must use judgment to conclude that costs deferred as regulatory
assets are probable of future recovery. We base our conclusion on certain
factors, including, but not limited to, regulatory precedent.

Regulatory liabilities represent either revenues received from customers to fund
expected costs that have not yet been incurred or probable future refunds to
customers. We make judgments regarding the future outcome of regulatory
proceedings that involve potential future refund to
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customers and record liabilities for these loss contingencies when probable and
reasonably estimable based upon available information. Regulatory liabilities
are recorded at the best estimate, or at a low end of the range of possible
loss. The amount recorded may differ from when the uncertainty is resolved. Such
differences could have a significant impact on our financial statements.

We use judgment when recording regulatory assets and liabilities; however,
regulatory commissions can reach different conclusions about the recovery of
costs, and those conclusions could have a material impact on our financial
statements. The ultimate outcome of regulatory rate proceedings could have a
significant effect on our ability to recover costs or earn an adequate return.
Established rates are also often subject to subsequent prudency reviews by state
regulators, whereby various portions of rates could be adjusted, subject to
refund or disallowed. We have approximately $1 billion of storm restoration and
pre-staging costs that are subject to prudency reviews from our regulators. We
believe that our storm costs were prudently incurred and are probable of
recovery.

We continually assess whether the regulatory assets and liabilities continue to
meet the criteria for probable future recovery or refund. This assessment
includes consideration of recent orders issued by regulatory commissions, the
passage of new legislation, historical regulatory treatment for similar costs in
each of our jurisdictions, discussions with legal counsel, the status of any
appeals of regulatory decisions, and changes in applicable regulatory and
political environments. We believe that we will continue to be able to defer and
recover prudently incurred costs, including additional storm costs, based on the
legal and regulatory framework.

We believe it is probable that each of our regulated companies will recover its
respective investments in long-lived assets and the regulatory assets that have
been recorded. If we determine that we can no longer apply the accounting
guidance applicable to rate-regulated enterprises, or that we cannot conclude it
is probable that costs will be recovered from customers in future rates, the
applicable costs would be charged to net income in the period in which the
determination is made.

Pension, SERP and PBOP: We sponsor pension, SERP and PBOP plans to provide retirement benefits to our employees. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit cost. These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progress rate, and mortality and retirement assumptions. We evaluate these assumptions at least once a year and adjust them if necessary.

Changes in these assumptions could have a material impact on our financial condition, results of operations or cash flows.


Expected Long-Term Rate of Return on Plan Assets:  In developing the expected
long-term rate of return, we consider historical and expected returns, as well
as input from our consultants.  Our expected long-term rate of return on assets
is based on assumptions regarding target asset allocations and corresponding
expected rates of return for each asset class.  We routinely review the actual
asset allocations and periodically rebalance the investments to the targeted
asset allocations.  For the year ended December 31, 2021, our expected long-term
rate-of-return assumption used to determine our pension and PBOP expense was
8.25 percent for the Eversource Service plans and 7 percent for the Aquarion
plans.  For the forecasted 2022 pension and PBOP expense, an expected long-term
rate of return of 8.25 percent for the Eversource Service plans and 7 percent
for the Aquarion plans will be used reflecting our target asset allocations.

Discount Rate:  Payment obligations related to the Pension, SERP and PBOP Plans
are discounted at interest rates applicable to the expected timing of each
plan's cash flows.  The discount rate that was utilized in determining the
pension, SERP and PBOP obligations was based on a yield-curve approach.  This
approach utilizes a population of bonds with an average rating of AA based on
bond ratings by Moody's, S&P and Fitch, and uses bonds with above median yields
within that population.  As of December 31, 2021, the discount rates used to
determine the funded status were within a range of 2.8 percent to 3.0 percent
for the Pension and SERP Plans, and within a range of 2.91 percent to 2.92
percent for the PBOP Plans.  As of December 31, 2020, the discount rates used
were within a range of 2.4 percent to 2.7 percent for the Pension and SERP
Plans, and within a range of 2.5 percent to 2.6 percent for the PBOP Plans. 

the

increase in the discount rates used to calculate the funded status resulted in a
decrease to the Pension and PBOP Plans' liability of $286.8 million and $29.8
million, respectively, as of December 31, 2021.

The Company uses the spot rate methodology for the service and interest cost
components of Pension, SERP and PBOP expense because it provides a relatively
precise measurement by matching projected cash flows to the corresponding spot
rates on the yield curve.  The discount rates used to estimate the 2021 expense
were within a range of 1.5 percent to 3.0 percent for the Pension and SERP
Plans, and within a range of 1.8 percent to 3.1 percent for the PBOP Plans.

Mortality Assumptions:  Assumptions as to mortality of the participants in our
Pension, SERP and PBOP Plans are a key estimate in measuring the expected
payments a participant may receive over their lifetime and the corresponding
plan liability we need to record. In 2021, a revised scale for the mortality
table was released, and we utilized it in our measurements.

Compensation/Progression Rate:  This assumption reflects the expected long-term
salary growth rate, including consideration of the levels of increases built
into collective bargaining agreements, and impacts the estimated benefits that
Pension and SERP Plan participants receive in the future.  As of December 31,
2021 and 2020, the compensation/progression rates used to determine the funded
status were within a range of 3.5 percent to 4.0 percent.

Health Care Cost: The Eversource Service PBOP Plan is not subject to health care
cost trends. As of December 31, 2021, for the Aquarion PBOP Plan, the health
care trend rate for pre-65 retirees is 6.5 percent, with an ultimate rate of 5
percent in 2028, and for post-65 retirees, the health care trend rate and
ultimate rate is 3.5 percent.

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Actuarial Determination of Expense:  Pension, SERP and PBOP expense is
determined by our actuaries and consists of service cost and prior service cost,
interest cost based on the discounting of the obligations, and amortization of
actuarial gains and losses, offset by the expected return on plan assets.
Actuarial gains and losses represent the amortization of differences between
assumptions and actual information or updated assumptions. Pre-tax net periodic
benefit expense for the Pension and SERP Plans was $23.6 million, $56.9 million
and $63.7 million for the years ended December 31, 2021, 2020 and 2019,
respectively.  For the PBOP Plans, there was net periodic PBOP income of $60.5
million, $51.6 million and $41.5 million for the years ended December 31, 2021,
2020 and 2019, respectively.

The expected return on plan assets is determined by applying the assumed long-term rate of return to the pension plan and PBOP plan asset balances. This calculated expected return is compared to the actual return or loss of plan assets at the end of each year to determine the investment gains or losses to be reflected immediately in unamortized actuarial gains and losses.


Forecasted Expenses and Expected Contributions:  We estimate that income in 2022
for the Pension and SERP Plans will be approximately $177 million and income in
2022 for the PBOP Plans will be approximately $80 million. Pension, SERP and
PBOP expense for subsequent years will depend on future investment performance,
changes in future discount rates and other assumptions, and various other
factors related to the populations participating in the plans.

Our policy is to fund the Pension Plans annually in an amount at least equal to
the amount that will satisfy all federal funding requirements.  We contributed
$180.0 million to the Pension Plans in 2021.  We currently estimate contributing
between $100 million to $175 million to the Pension Plans in 2022, however,
there is no minimum funding requirement for our Pension Plans for 2022, and
therefore the planned contribution is discretionary and subject to change.  It
is our policy to fund the PBOP Plans annually through tax deductible
contributions to external trusts.  We contributed $2.3 million to the PBOP Plans
in 2021.  We currently estimate contributing $2.4 million to the PBOP Plans in
2022.

Sensitivity Analysis:  The following represents the hypothetical increase to the
Pension Plans' (excluding the SERP Plans) reported annual cost and a decrease to
the PBOP Plans' reported annual income as a result of a change in the following
assumptions by 50 basis points:

(Millions of Dollars)                      Increase in Pension Plan Cost                 Decrease in PBOP Plan Income
Assumption Change                        For the Years Ended December 31,              For the Years Ended December 31,
Eversource                                   2021                   2020                   2021                  2020
Lower expected long-term rate of      $           26.5          $     25.0          $           4.8          $      4.5
return
Lower discount rate                               27.0                25.4                      2.6                 1.7
Higher compensation rate                           9.9                 8.8                         N/A                 N/A



Goodwill:  We recorded goodwill on our balance sheet associated with previous
mergers and acquisitions, all of which totaled $4.48 billion as of December 31,
2021. We have identified our reporting units for purposes of allocating and
testing goodwill as Electric Distribution, Electric Transmission, Natural Gas
Distribution and Water Distribution.  Electric Distribution and Electric
Transmission reporting units include carrying values for the respective
components of CL&P, NSTAR Electric and PSNH.  The Natural Gas Distribution
reporting unit includes the carrying values of NSTAR Gas, Yankee Gas and EGMA.
The Water Distribution reporting unit includes the Aquarion water utility
businesses.  As of December 31, 2021, goodwill was allocated to the reporting
units as follows: $2.54 billion to Electric Distribution, $577 million to
Electric Transmission, $451 million to Natural Gas Distribution and $905 million
to Water Distribution.

We recorded $51.9 million of goodwill arising from the acquisition of CMA on
October 9, 2020, which included measurement period adjustments in 2021. This
goodwill was allocated to the Natural Gas Distribution reporting unit. We
recorded $21.7 million of goodwill arising from the acquisition of NESC on
December 1, 2021, which was allocated to the Water Distribution reporting unit.

We are required to test goodwill balances for impairment at least annually by
considering the fair values of the reporting units, which requires us to use
estimates and judgments. Additionally, we monitor all relevant events and
circumstances during the year to determine if an interim impairment test is
required. We have selected October 1st of each year as the annual goodwill
impairment test date. Goodwill impairment is deemed to exist if the carrying
amount of a reporting unit exceeds its estimated fair value. If goodwill were
deemed to be impaired, it would be written down in the current period to the
extent of the impairment.

In assessing goodwill for impairment, an entity is permitted to first assess
qualitatively whether it is more likely than not that goodwill impairment exists
as of the annual impairment test date. A quantitative impairment test is
required only if it is concluded that it is more likely than not that a
reporting unit's fair value is less than it's carrying amount.

We performed an impairment test of goodwill as of October 1, 2021 for the
Electric Distribution, Electric Transmission, Natural Gas Distribution and Water
Distribution reporting units. Our qualitative evaluation included an evaluation
of multiple factors that impact the fair value of the reporting units, including
general, macroeconomic and market conditions, and entity-specific assumptions
that affect the future cash flows of the reporting units. Key considerations
include discount rates, utility sector market performance and merger transaction
multiples, the Company's share price and credit ratings, analyst reports,
financial performance, cost and risk factors, internal estimates and projections
of future cash flows and net income, long-term strategy, the timing and outcome
of rate cases, and recent regulatory and legislative proceedings.

The 2021 goodwill impairment assessment resulted in a conclusion that goodwill
is not impaired and no reporting unit is at risk of a goodwill impairment. We
believe that the fair value of the reporting units was substantially in excess
of carrying value. Adverse regulatory actions, changes in the regulatory and
political environment, or changes in significant assumptions could potentially
result in future goodwill impairment indicators.

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Long-Lived Assets: Impairment evaluations of long-lived assets, including
property, plant and equipment and other assets, involve a significant degree of
estimation and judgment, including identifying circumstances that indicate an
impairment may exist. Impairment analysis is required when events or changes in
circumstances indicate that the carrying value of a long-lived asset may not be
recoverable. Indicators of potential impairment include a deteriorating business
climate, unfavorable regulatory action, decline in value that is other than
temporary in nature, plans to dispose of a long-lived asset significantly before
the end of its useful life, and accumulation of costs that are in excess of
amounts allowed for recovery. The review of long-lived assets for impairment
utilizes significant assumptions about operating strategies and external
developments, including assessment of current and projected market conditions
that can impact future cash flows.

Equity Method Investments: Investments in affiliates where we have the ability
to exercise significant influence, but not control, over an investee are
initially recognized as an equity method investment at cost. Any differences
between the cost of an investment and the amount of underlying equity in net
assets of an investee are considered basis differences and are determined based
upon the estimated fair values of the investee's identifiable assets and
liabilities. For our offshore wind equity method investment, basis differences
are related to intangible assets for PPAs that will be amortized over the term
of the PPAs, and equity method goodwill that is not amortized. Capitalized
interest associated with our offshore wind equity method investment is included
in the investment balance.

Equity method investments are assessed for impairment when conditions exist that
indicate that the fair value of the investment is less than book value.  If the
decline in value is considered to be other-than-temporary, the investment is
written down to its estimated fair value, which establishes a new cost basis in
the investment. Impairment evaluations involve a significant degree of judgment
and estimation, including identifying circumstances that indicate an impairment
may exist and developing an estimate of undiscounted future cash flows.

Income Taxes: Income tax expense is estimated for each of the jurisdictions in
which we operate and is recorded each quarter using an estimated annualized
effective tax rate. This process to record income tax expense involves
estimating current and deferred income tax expense or benefit and the impact of
temporary differences resulting from differing treatment of items for financial
reporting and income tax return reporting purposes. Such differences are the
result of timing of the deduction for expenses, as well as any impact of
permanent differences, non-tax deductible expenses, or other items that directly
impact income tax expense as a result of regulatory activity (flow-through
items). The temporary differences and flow-through items result in deferred tax
assets and liabilities that are included in the balance sheets.

We also account for uncertainty in income taxes, which applies to all income tax
positions previously filed in a tax return and income tax positions expected to
be taken in a future tax return that have been reflected on our balance sheets.
The determination of whether a tax position meets the recognition threshold
under applicable accounting guidance is based on facts and circumstances
available to us.

The interpretation of tax laws and associated regulations involves uncertainty
since tax authorities may interpret the laws differently. Ultimate resolution or
clarification 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.

Significant management judgment is required in determining the provision for
income taxes, primarily due to the uncertainty related to tax positions taken,
as well as deferred tax assets and liabilities and valuation allowances. We
evaluate the probability of realizing deferred tax assets by reviewing a
forecast of future taxable income and our intent and ability to implement tax
planning strategies, if necessary, to realize deferred tax assets. We also
assess negative evidence, such as the expiration of historical operating loss or
tax credit carryforwards, that could indicate the inability to realize the
deferred tax assets. Valuation allowances are provided to reduce deferred tax
assets to the amount that will more likely than not be realized in future
periods. This requires management to make judgments and estimates regarding the
amount and timing of the reversal of taxable temporary differences, expected
future taxable income, and the impact of tax planning strategies.

Actual income taxes could vary from estimated amounts due to the future impacts
of various items, including future changes in income tax laws, not realizing
expected tax planning strategy amounts, as well as results of audits and
examinations of filed tax returns by taxing authorities.

Accounting for Environmental Reserves:  Environmental reserves are accrued when
assessments indicate it is probable that a liability has been incurred and an
amount can be reasonably estimated. Increases to estimates of environmental
liabilities could have an adverse impact on earnings. We estimate these
liabilities based on findings through various phases of the assessment,
considering the most likely action plan from a variety of available remediation
options (ranging from no action required to full site remediation and long-term
monitoring), current site information from our site assessments, remediation
estimates from third party engineering and remediation contractors, and our
prior experience in remediating contaminated sites.  If a most likely action
plan cannot yet be determined, we estimate the liability based on the low end of
a range of possible action plans. A significant portion of our environmental
sites and reserve amounts relate to former MGP sites that were operated several
decades ago and manufactured natural gas from coal and other processes, which
resulted in certain by-products remaining in the environment that may pose a
potential risk to human health and the environment, for which we may have
potential liability.  Estimates are based on the expected remediation plan. Our
estimates are subject to revision in future periods based on actual costs or new
information from other sources, including the level of contamination at the
site, the extent of our responsibility or the extent of remediation required,
recently enacted laws and regulations or a change in cost estimates.

Fair Value Measurements:  We follow fair value measurement guidance that defines
fair value as the price that would be received for the sale of an asset or paid
to transfer a liability in an orderly transaction between market participants at
the measurement date (an exit price).  We have applied this guidance to our
Company's derivative contracts that are not elected or designated as "normal
purchases or normal sales" (normal), to marketable securities held in trusts,
and to our investments in our Pension and PBOP Plans. Fair value measurements
are also incorporated into the accounting for goodwill, long-lived assets,
equity method investments, and AROs, and in the valuation of the acquisition of
CMA in 2020. The fair value measurement guidance was also applied in estimating
the fair value of preferred stock, long-term debt and RRBs.

                                       45
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Changes in the fair value of our derivative contracts are recorded as regulatory assets or liabilities as we recover the costs of these contracts in the rates charged to customers. These valuations are sensitive to the prices of energy-related products in the years to come and to the assumptions used.


We use quoted market prices when available to determine the fair value of
financial instruments.  When quoted prices in active markets for the same or
similar instruments are not available, we value derivative contracts using
models that incorporate both observable and unobservable inputs.  Significant
unobservable inputs utilized in the models include energy-related product prices
for future years for long-dated derivative contracts and market volatilities.
 Discounted cash flow valuations incorporate estimates of premiums or discounts,
reflecting risk-adjusted profit that would be required by a market participant
to arrive at an exit price, using available historical market transaction
information. Valuations of derivative contracts also reflect our estimates of
nonperformance risk, including credit risk.
                                       46
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           RESULTS OF OPERATIONS - EVERSOURCE ENERGY AND SUBSIDIARIES

The following sets out the amounts and variances of revenue and expense items in Eversource’s statements of operations for the years ended December 31, 2021 and 2020 included in this Annual Report on Form 10-K:


                                                               For the Years Ended December 31,
(Millions of Dollars)                             2021                    2020               Increase/(Decrease)
Operating Revenues                          $      9,863.1          $     8,904.4          $              958.7
Operating Expenses:
Purchased Power, Fuel and Transmission             3,372.3                2,987.8                         384.5
Operations and Maintenance                         1,739.7                1,480.3                         259.4
Depreciation                                       1,103.0                  981.4                         121.6
Amortization                                         232.0                  177.7                          54.3
Energy Efficiency Programs                           592.8                  535.8                          57.0
Taxes Other Than Income Taxes                        830.0                  752.7                          77.3

Total Operating Expenses                           7,869.8                6,915.7                         954.1
Operating Income                                   1,993.3                1,988.7                           4.6
Interest Expense                                     582.4                  538.4                          44.0
Other Income, Net                                    161.3                  108.6                          52.7
Income Before Income Tax Expense                   1,572.2                1,558.9                          13.3
Income Tax Expense                                   344.2                  346.2                          (2.0)
Net Income                                         1,228.0                1,212.7                          15.3
Net Income Attributable to Noncontrolling
Interests                                              7.5                    7.5                             -
Net Income Attributable to Common
Shareholders                                $      1,220.5          $     1,205.2          $               15.3



Eversource's consolidated financial information includes the results of EGMA
beginning on October 9, 2020. The natural gas distribution assets acquired from
CMA on October 9, 2020 were assigned to EGMA.

Operating Revenues
Sales Volumes: A summary of our retail electric GWh sales volumes, our firm
natural gas MMcf sales volumes, and our water MG sales volumes, and percentage
changes, is as follows:

                                                      Electric                                                   Firm Natural Gas                                                    Water
                                     Sales Volumes (GWh)                 Percentage                Sales Volumes (MMcf)                 Percentage                 Sales Volumes (MG)                 Percentage
                                    2021               2020               Increase                2021                2020               Increase                2021               2020               Decrease
Traditional                          7,782             7,675                    1.4  %                  -                 -                      -  %             1,256             2,011                  (37.5) %
Decoupled and Special
Contracts (1)(2)                    43,228            42,531                    1.6  %            150,145           147,123                    2.1  %            22,099            23,122                   (4.4) %
Total Sales Volumes                 51,010            50,206                    1.6  %            150,145           147,123                    2.1  %            23,355            25,133                   (7.1) %


(1) Special contracts are specific to Yankee Gas natural gas distribution customers who obtain supply under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of customer usage.

(2) Eversource acquired the natural gas distribution assets of CMA on October 9, 2020. Sales volumes from previous years have been presented for comparison purposes.


Weather, fluctuations in energy supply costs, conservation measures (including
utility-sponsored energy efficiency programs), and economic conditions affect
customer energy usage and water consumption. Industrial sales volumes are less
sensitive to temperature variations than residential and commercial sales
volumes. In our service territories, weather impacts both electric and water
sales volumes during the summer and both electric and natural gas sales volumes
during the winter; however, natural gas sales volumes are more sensitive to
temperature variations than electric sales volumes. Customer heating or cooling
usage may not directly correlate with historical levels or with the level of
degree-days that occur.

Fluctuations in retail electric sales volumes at PSNH impact earnings
("Traditional" in the table above). For CL&P, NSTAR Electric, NSTAR Gas, EGMA,
Yankee Gas, and our Connecticut water distribution business, fluctuations in
retail sales volumes do not materially impact earnings due to their respective
regulatory commission-approved distribution revenue decoupling mechanisms
("Decoupled" in the table above). These distribution revenues are decoupled from
their customer sales volumes, which breaks the relationship between sales
volumes and revenues recognized.

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Operating Revenues: Operating Revenues by segment increased in 2021, as compared
to 2020, as follows:

(Millions of Dollars)       Increase/(Decrease)
Electric Distribution      $              291.3
Natural Gas Distribution                  580.9
Electric Transmission                      98.5
Water Distribution                         (4.1)
Other                                     118.1
Eliminations                             (126.0)
Total Operating Revenues   $              958.7



Electric and Natural Gas (excluding EGMA) Distribution Revenues:
Base Distribution Revenues:
•Base electric distribution revenues increased $28.8 million in 2021, as
compared to 2020, due primarily to the impact of base distribution rate
increases at NSTAR Electric effective January 1, 2021, at PSNH effective January
1, 2021 and August 1, 2021, and at CL&P effective May 1, 2020. These increases
were partially offset by a base distribution rate decrease at CL&P implemented
June 1, 2021. The decrease in the CL&P base distribution rate on June 1, 2021
was due primarily to the completion of the recovery of certain storm cost
amortization and therefore the base rate decrease did not impact earnings.

•Base natural gas distribution revenues increased $62.8 million in 2021, as
compared to 2020, due primarily to base distribution rate increases at NSTAR Gas
effective November 1, 2021 and November 1, 2020, which includes a shift of
recovery into base rates of certain GSEP investments, and at Yankee Gas
effective January 1, 2021. Although new rates at Yankee Gas were implemented on
March 1, 2021 to customers, the provisions of the base distribution rate
increase were effective January 1, 2021.

Electric distribution revenues at CL&P also decreased $93.4 million in 2021, as
compared to 2020, due to a reserve established to provide bill credits to
customers as a result of CL&P's settlement agreement on October 1, 2021 and a
storm performance penalty assessed by PURA in 2021. In the settlement agreement,
CL&P agreed to provide a total of $65 million of customer credits, which were
distributed based on customer sales over a two-month billing period from
December 1, 2021 to January 31, 2022. CL&P recorded a $28.4 million reserve in
2021 for a civil penalty for non-compliance with storm performance standards
that is currently being credited to customers on electric bills beginning on
September 1, 2021 over a one-year period. CL&P recorded these reserves as a
current regulatory liability and a reduction to Operating Revenues. As of
December 31, 2021, the remaining reserve that has not yet been issued as
customer credits and not yet reflected in rates totaled $71.1 million. For
further information, see "Regulatory Developments and Rate Matters -
Connecticut" included in this Management's Discussion and Analysis.

Tracked Distribution Revenues: Tracked distribution revenues consist of certain
costs that are recovered from customers in retail rates through regulatory
commission-approved cost tracking mechanisms and therefore, recovery of these
costs has no impact on earnings. Revenues from certain of these cost tracking
mechanisms also include certain incentives earned, return on capital tracking
mechanisms, and carrying charges that are billed in rates to customers, which do
impact earnings. Costs recovered through cost tracking mechanisms include, among
others, energy supply and natural gas supply procurement and other
energy-related costs, electric retail transmission charges, energy efficiency
program costs, electric restructuring and stranded cost recovery revenues
(including securitized RRB charges), certain capital tracking mechanisms for
infrastructure improvements, and additionally for the Massachusetts utilities,
pension and PBOP benefits, net metering for distributed generation, and
solar-related programs. Tracked revenues also include wholesale market sales
transactions, such as sales of energy and energy-related products into the
ISO-NE wholesale electricity market, sales of natural gas to third party
marketers, and the sale of RECs to various counterparties.

Tracked distribution revenues increased/(decreased) in 2021, compared to 2020, mainly due to the following:


(Millions of Dollars)                           Electric Distribution          Natural Gas Distribution
Retail Tariff Tracked Revenues:
Energy supply procurement                     $               (152.1)         $                   70.0
Retail transmission                                            222.2                                 -
Other distribution tracking mechanisms                          47.3                              11.7
Wholesale Market Sales Revenue                                 248.5                               4.9



The decrease in energy supply procurement within electric distribution in 2021
as compared to 2020, was driven primarily by lower average supply-related sales
volumes and lower average prices. The increase in energy supply procurement
within natural gas distribution in 2021, as compared to 2020, was driven
primarily by higher average prices and higher average supply-related sales
volumes.

Fluctuations in retail electric transmission revenues are driven by the recovery
of the costs of our wholesale transmission business, such as those billed by
ISO-NE and Local and Regional Network Service charges. For further information,
see "Purchased Power and Transmission Expense" below.

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The increase in electric distribution wholesale market sales revenue was due
primarily to higher average electricity market prices received for
wholesale sales in 2021, as compared to 2020. ISO-NE average market prices
received for CL&P's wholesale sales increased approximately 95 percent in 2021,
as compared to 2020, driven primarily by higher natural gas prices in New
England. Volumes sold into the market were primarily from the sale of output
generated by the Millstone PPA that CL&P entered into in 2019, as required by
regulation. The increase in electric distribution wholesale market sales
revenues was also driven by higher proceeds from a one-year sale of transmission
rights, effective June 2021, under CL&P's, NSTAR Electric's and PSNH's
Hydro-Quebec transmission support agreements. Proceeds from these sales are
credited back to customers.

EGMA Natural Gas Distribution Revenues: The incremental impact of EGMA increased the total revenue of the Natural Gas Distribution segment by
$431.5 million in 2021, compared to 2020.


Electric Transmission Revenues:  Electric transmission revenues increased $98.5
million in 2021, as compared to 2020, due primarily to a higher transmission
rate base as a result of our continued investment in our transmission
infrastructure.

Other Revenues and Eliminations: Other revenues primarily include the revenues
of Eversource's service company, most of which are eliminated in consolidation.
Eliminations are also primarily related to the Eversource electric transmission
revenues that are derived from ISO-NE regional transmission charges to the
distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs
of the wholesale transmission business in rates charged to their customers.

Purchased Power, Fuel and Transmission expense includes costs associated with
purchasing electricity and natural gas on behalf of our customers and the cost
of energy purchase contracts, as required by regulation.  These electric and
natural gas supply costs and other energy-related costs are recovered from
customers in rates through commission-approved cost tracking mechanisms, which
have no impact on earnings (tracked costs).  Purchased Power, Fuel and
Transmission expense increased in 2021, as compared to 2020, due primarily to
the following:

(Millions of Dollars)                            Increase/(Decrease)
Purchased Power Costs                           $              (56.7)
Natural Gas Costs                                              313.4
Transmission Costs                                             225.2
Eliminations                                                   (97.4)
Total Purchased Power, Fuel and Transmission    $              384.5



The decrease in purchased power expense at the electric distribution business in
2021, as compared to 2020, was driven primarily by lower expense related to the
procurement of energy supply resulting from lower average supply-related sales
volumes and lower average prices. The lower energy supply expense was partially
offset by higher long-term contractual energy-related costs that are recovered
in the NBFMCC mechanism at CL&P and higher net metering costs at NSTAR Electric.

The increase in costs at the natural gas distribution segment in 2021, as
compared to 2020, was due primarily to the incremental impact of EGMA natural
gas supply costs of $145.0 million, as well as higher average prices and higher
average supply-related sales volumes.

The increase in transmission costs in 2021, as compared to 2020, was primarily
the result of an increase in costs billed by ISO-NE that support regional grid
investments and an increase resulting from the retail transmission cost
deferral, which reflects the actual costs of transmission service compared to
estimated amounts billed to customers. This was partially offset by a decrease
in Local Network Service charges, which reflects the cost of transmission
service provided by Eversource over our local transmission network.

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Operations and Maintenance expense includes tracked costs and costs that are
part of base electric, natural gas and water distribution rates with changes
impacting earnings (non-tracked costs).  Operations and Maintenance expense
increased in 2021, as compared to 2020, due primarily to the following:

(Millions of Dollars)                                                       

Increase decrease)

Base Electric Distribution (Non-Tracked Costs):
Employee-related expenses, including labor and benefits                          $               47.9

Company shared costs (including amortization of computer software at Eversource

                   21.6

A service)

Vegetation Management                                                                            19.1

Funding of CL&P storm reserve as part of June 1, 2021 rate change (compensated by

                     16.0
lower Amortization expense; no earnings impact)
CL&P charge to fund customer assistance initiatives associated with the                          10.0
settlement agreement on October 1, 2021
Storm restoration costs                                                                         (24.2)

Operating expenses, including vehicles and outside services

                       3.1
Other non-tracked operations and maintenance                                                      8.5
Total Base Electric Distribution (Non-Tracked Costs)                                            102.0
Tracked Costs (Electric Distribution and Electric Transmission) - Increase due
primarily to higher transmission expenses of $6.5 million and increase of $16.3
million due to higher pension tracking mechanism at NSTAR Electric                               30.3
Total Electric Distribution and Electric Transmission                                           132.3
Natural Gas Distribution:
Base (Non-Tracked) Costs, excluding EGMA                                                          3.5
Tracked Costs, excluding EGMA                                                                     7.3
EGMA Operations and Maintenance                                                                 123.1
Total Natural Gas Distribution                                                                  133.9
Water Distribution:
Absence in 2021 of gain on sale of Hingham water system in July 2020                             16.0
Other                                                                                            (1.1)
Total Water Distribution                                                                         14.9
Parent and Other Companies and Eliminations:
Eversource Parent and Other Companies - other operations and maintenance                        106.9
Acquisition and Transition Costs                                                                 (9.7)
  Eliminations                                                                                 (118.9)
Total Operations and Maintenance                                                 $              259.4



Depreciation expense increased in 2021, as compared to 2020, due to higher
utility plant in service balances, the incremental impact of EGMA utility plant
balances of $36.8 million and new depreciation rates effective January 1, 2021
resulting from PSNH's 2020 distribution rate settlement agreement.

Amortization expense includes the deferral of energy supply, energy-related
costs and other costs that are included in certain regulatory
commission-approved cost tracking mechanisms. This deferral adjusts expense to
match the corresponding revenues compared to the actual costs incurred. Energy
supply and energy-related costs are recovered from customers in rates and have
no impact on earnings. Amortization expense also includes the amortization of
certain costs as those costs are collected in rates.

Amortization increased in 2021, as compared to 2020, due primarily to the
deferral adjustment of energy supply, energy-related and other tracked costs,
which can fluctuate from period to period based on the timing of costs incurred
and related rate changes to recover these costs. The increase was partially
offset by a decrease in storm amortization expense at CL&P related to the
completion of the amortization period of certain storm costs deferred assets.

Energy Efficiency Programs expense increased in 2021, as compared to 2020, due
primarily to the incremental impact of EGMA energy efficiency program costs of
$48.0 million. The increase was also due to the deferral adjustment at NSTAR
Electric, which reflects the actual costs of energy efficiency programs compared
to the amounts billed to customers, and the timing of the recovery of energy
efficiency costs. The costs for the majority of the state energy policy
initiatives and expanded energy efficiency programs are recovered from customers
in rates and have no impact on earnings.

Taxes Other Than Income Taxes expense increased in 2021, as compared to 2020,
due primarily to an increase in property taxes as a result of higher utility
plant balances, the incremental impact of EGMA property and other taxes of $23.5
million, higher Connecticut gross earnings taxes, and the absence in 2021 of a
benefit at NSTAR Gas in 2020 relating to the resolution of disputed property
taxes for prior years.

Interest Expense increased in 2021, as compared to 2020, due primarily to an
increase in interest on long-term debt as a result of new debt issuances ($29.5
million), an increase in interest expense on regulatory deferrals ($12.2
million), the absence in 2021 of a benefit at NSTAR Gas in 2020 relating to the
resolution of disputed property taxes and interest thereon for prior years ($5.7
million), and higher amortization of debt discounts and premiums, net ($0.8
million), partially offset by a decrease in interest on notes payable ($3.4
million), a decrease in RRB interest expense ($1.3 million), and an increase in
capitalized AFUDC related to debt funds and other capitalized interest ($1.1
million).

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Other Income, Net increased in 2021, as compared to 2020, due primarily to an
increase related to pension, SERP and PBOP non-service income components ($40.0
million) and an increase in interest income primarily from regulatory deferrals
($20.8 million), partially offset by lower AFUDC related to equity funds ($4.7
million) and investment losses in 2021 compared to investment income in 2020
driven by market volatility ($1.3 million).

Income Tax Expense decreased in 2021, as compared to 2020, due primarily to the
absence of the sale of the Hingham water system ($12.5 million), an increase in
amortization of EDIT ($20.4 million), the CL&P settlement agreement ($17.5
million), a decrease in items that impact our tax rate as a result of regulatory
treatment (flow-through items) and permanent differences ($0.6 million), and a
decrease in valuation allowance ($17.6 million), partially offset by higher
pre-tax earnings excluding the CL&P settlement agreement charges and gain on
Hingham sale ($27.8 million), higher state taxes ($31.6 million), lower
share-based payment excess tax benefits ($2.6 million), and a lower return to
provision adjustment ($4.6 million).
                                       51
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                            RESULTS OF OPERATIONS -
                    THE CONNECTICUT LIGHT AND POWER COMPANY
                     NSTAR ELECTRIC COMPANY AND SUBSIDIARY
            PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and
expense line items in the statements of income for CL&P, NSTAR Electric and PSNH
for the years ended December 31, 2021 and 2020 included in this Annual Report on
Form 10-K:

                                                                                                                                For the Years Ended December 31,
                                                                         CL&P                                                            NSTAR Electric                                                            PSNH
(Millions of Dollars)                            2021               2020             Increase/(Decrease)              2021               2020             Increase/(Decrease)              2021               2020             Increase/(Decrease)
Operating Revenues                           $ 3,637.4          $ 3,547.5          $               89.9           $ 3,056.4          $ 2,941.1          $              115.3           $ 1,177.2          $ 1,079.1          $               98.1
Operating Expenses:
Purchased Power and Transmission               1,393.0            1,369.2                          23.8               932.5              879.2                          53.3               370.3              364.1                           6.2
Operations and Maintenance                       644.2              572.9                          71.3               563.2              534.1                          29.1               237.7              219.3                          18.4
Depreciation                                     338.9              320.7                          18.2               337.5              319.5                          18.0               120.1              100.4                          19.7
Amortization of Regulatory Assets, Net            99.0               58.4                          40.6                55.8               83.2                         (27.4)               86.8               52.8                          34.0
Energy Efficiency Programs                       129.6              141.5                         (11.9)              288.6              264.0                          24.6                38.7               37.6                           1.1
Taxes Other Than Income Taxes                    363.8              344.4                          19.4               216.7              206.8                           9.9                91.5               81.6                           9.9
Total Operating Expenses                       2,968.5            2,807.1                         161.4             2,394.3            2,286.8                         107.5               945.1              855.8                          89.3
Operating Income                                 668.9              740.4                         (71.5)              662.1              654.3                           7.8               232.1              223.3                           8.8
Interest Expense                                 166.1              153.6                          12.5               146.0              130.5                          15.5                57.0               58.1                          (1.1)
Other Income, Net                                 30.2               20.8                           9.4                74.8               52.0                          22.8                14.6               13.8                           0.8
Income Before Income Tax Expense                 533.0              607.6                         (74.6)              590.9              575.8                          15.1               189.7              179.0                          10.7
Income Tax Expense                               131.3              149.7                         (18.4)              114.3              130.8                         (16.5)               39.4               31.7                           7.7
Net Income                                   $   401.7          $   457.9          $              (56.2)          $   476.6          $   445.0          $               31.6           $   150.3          $   147.3          $                3.0



Operating Revenues
Sales Volumes: A summary of our retail electric GWh sales volumes is as follows:
                                                                    For the Years Ended December 31,
                                         2021                       2020                   Increase               Percentage Increase
CL&P                                         20,501                   20,113                     388                             1.9  %
NSTAR Electric                               22,727                   22,418                     309                             1.4  %
PSNH                                          7,782                    7,675                     107                             1.4  %



Fluctuations in retail electric sales volumes at PSNH impact earnings.  For CL&P
and NSTAR Electric, fluctuations in retail electric sales volumes do not impact
earnings due to their respective regulatory commission-approved distribution
revenue decoupling mechanisms.

Operating Revenues: Operating Revenues, which consist of base distribution
revenues and tracked revenues further described below, increased $89.9 million
at CL&P, $115.3 million at NSTAR Electric, and $98.1 million at PSNH in 2021, as
compared to 2020.

Base Distribution Revenues:
•CL&P's distribution revenues decreased $12.0 million due primarily to the base
distribution rate decrease implemented June 1, 2021. The decrease in the base
distribution rate on June 1, 2021 was due primarily to the completion of the
recovery of certain storm cost amortization and therefore the base rate decrease
did not impact earnings. Excluding the reduction to revenue resulting from the
completion of certain storm cost amortization, base distribution revenues
increased due to the impact of a base distribution rate increase effective May
1, 2020.
•NSTAR Electric's distribution revenues increased $9.3 million due primarily to
the impact of its base distribution rate increase effective January 1, 2021.
•PSNH's distribution revenues increased $31.5 million due primarily to the
impact of its base distribution rate increases effective January 1, 2021 and
August 1, 2021.

Electric distribution revenues at CL&P also decreased $93.4 million in 2021, as
compared to 2020, due to a reserve established to provide bill credits to
customers as a result of CL&P's settlement agreement on October 1, 2021 and a
storm performance penalty assessed by PURA in 2021. In the settlement agreement,
CL&P agreed to provide a total of $65 million of customer credits, which were
distributed based on customer sales over a two-month billing period from
December 1, 2021 to January 31, 2022. CL&P recorded a $28.4 million reserve in
2021 for a civil penalty for non-compliance with storm performance standards
that is currently being credited to customers on electric bills beginning on
September 1, 2021 over a one-year period. CL&P recorded these reserves as a
current regulatory liability and a reduction to Operating Revenues. As of
December 31, 2021, the remaining reserve that has not yet been issued as
customer credits and not yet reflected in rates totaled $71.1 million. For
further information, see "Regulatory Developments and Rate Matters -
Connecticut" included in this Management's Discussion and Analysis.

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Tracked Revenues: Tracked distribution revenues consist of certain costs that
are recovered from customers in retail rates through regulatory
commission-approved cost tracking mechanisms and therefore, recovery of these
costs has no impact on earnings. Revenues from certain of these
cost tracking mechanisms also include certain incentives earned, return on
capital tracking mechanisms, and carrying charges that are billed in
rates to customers, which do impact earnings. Costs recovered through cost
tracking mechanisms include, among others, energy supply
procurement and other energy-related costs, retail transmission charges, energy
efficiency program costs, electric restructuring and stranded cost
recovery revenues (including securitized RRB charges), certain capital tracking
mechanisms for infrastructure improvements, and additionally for NSTAR Electric,
pension and PBOP benefits, net metering for distributed generation, and
solar-related programs. Tracked revenues also include wholesale market sales
transactions, such as sales of energy and energy-related products into the
ISO-NE wholesale electricity market and the sale of RECs to various
counterparties.

Tracked revenue increased/(decreased) in 2021, compared to 2020, primarily due to:


(Millions of Dollars)                       CL&P        NSTAR Electric      

HPNH

Retail Tariff Tracked Revenues:
Energy supply procurement                 $ (30.5)     $        (124.8)     $ 3.2
Retail transmission                          47.0                138.5      

36.7

Other distribution tracking mechanisms       (6.4)                40.6      

13.1

Wholesale Market Sales Revenue              178.7                 50.8      

19.0




The decrease in energy supply procurement at CL&P was driven primarily by lower
average prices, partially offset by higher average supply-related sales volumes.
The decrease in energy supply procurement at NSTAR Electric was driven by lower
average supply-related sales volumes, partially offset by higher average prices.
The increase in energy supply procurement at PSNH was driven primarily by higher
average supply-related sales volumes, partially offset by lower average prices.
Fluctuations in retail transmission revenues are driven by the recovery of the
costs of our wholesale transmission business, such as those billed by ISO-NE and
Local and Regional Network Service charges. For further information, see
"Purchased Power and Transmission Expense" below.

The increase in wholesale market sales revenue was due primarily to higher
average electricity market prices received for wholesale sales at CL&P, NSTAR
Electric and PSNH in 2021, as compared to 2020. ISO-NE average market prices
received for CL&P's wholesale sales increased approximately 95 percent for the
year ended December 31, 2021, as compared to 2020, driven primarily by higher
natural gas prices in New England. Volumes sold into the market were primarily
from the sale of output generated by the Millstone PPA that CL&P entered into in
2019, as required by regulation. The increase in wholesale market sales revenues
at CL&P, NSTAR Electric and PSNH was also driven by higher proceeds from a
one-year sale of transmission rights, effective June 2021, under CL&P's, NSTAR
Electric's and PSNH's Hydro-Quebec transmission support agreements. Proceeds
from these sales are credited back to customers.

Transmission Revenues: Transmission revenues increased $42.6 million at CL&P,
$30.1 million at NSTAR Electric and $25.8 million at PSNH in 2021, as compared
to 2020, due primarily to a higher transmission rate base as a result of our
continued investment in our transmission infrastructure.

Eliminations: Eliminations are primarily related to the Eversource electric
transmission revenues that are derived from ISO-NE regional transmission charges
to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the
costs of the wholesale transmission business in rates charged to their
customers. The impact of eliminations decreased revenues by $27.8 million at
CL&P, $29.1 million at NSTAR Electric and $29.5 million at PSNH in 2021, as
compared to 2020.

Purchased Power and Transmission expense includes costs associated with
purchasing electricity on behalf of CL&P, NSTAR Electric and PSNH's customers
and the cost of energy purchase contracts, as required by regulation.  These
energy supply and other energy-related costs are recovered from customers in
rates through commission-approved cost tracking mechanisms, which have no impact
on earnings (tracked costs). Purchased Power and Transmission expense increased
in 2021, as compared to 2020, due primarily to the following:

(Millions of Dollars)                       CL&P       NSTAR Electric       PSNH
Purchased Power Costs                     $  2.1      $        (55.5)     $ (3.3)
Transmission Costs                          48.2               138.0        39.0
Eliminations                               (26.5)              (29.2)      (29.5)

Total power purchased and transmission $23.8 $53.3

6.2




Purchased Power Costs: Included in purchased power costs are the costs
associated with providing electric generation service supply to all customers
who have not migrated to third party suppliers and the cost of energy purchase
contracts, as required by regulation.

•The increase at CL&P was due primarily to higher long-term contractual
energy-related costs that are recovered in the NBFMCC mechanism, partially
offset by lower expense related to the procurement of energy supply resulting
from lower average prices.
•The decrease at NSTAR Electric was due primarily to lower expense related to
the procurement of energy supply resulting from lower average supply-related
sales volumes, partially offset by higher net metering costs.
•The decrease at PSNH was due primarily to lower stranded costs resulting from
higher Regional Greenhouse Gas Initiative (RGGI) proceeds received, which are
credited back to customers. The higher RGGI proceeds resulted from an increase
in RGGI auction clearing prices for allowances in 2021 as compared to 2020.
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Transmission Costs: Included in transmission costs are charges that recover the
cost of transporting electricity over high-voltage lines from generation
facilities to substations, including costs allocated by ISO-NE to maintain the
wholesale electric market.

•The increase in transmission costs at CL&P was due primarily to an increase in
costs billed by ISO-NE that support regional grid investments. This was
partially offset by a decrease resulting from the retail transmission cost
deferral, which reflects the actual costs of transmission service compared to
estimated amounts billed to customers, and a decrease in Local Network Service
charges, which reflect the cost of transmission service provided by Eversource
over our local transmission network.
•The increase in transmission costs at NSTAR Electric and PSNH was due primarily
to an increase in costs billed by ISO-NE, an increase resulting from the retail
transmission cost deferral, and an increase in costs billed by ISO-NE that
support regional grid investments. This was partially offset by a decrease in
Local Network Service charges.

Operations and Maintenance expense includes tracked costs and costs that are
part of base distribution rates with changes impacting earnings (non-tracked
costs).  Operations and Maintenance expense increased in 2021, as compared to
2020, due primarily to the following:

(Millions of Dollars)                                         CL&P             NSTAR Electric            PSNH
Base Electric Distribution (Non-Tracked Costs):
Employee-related expenses, including labor and benefits    $   17.2         

$14.3 $7.9
Shared enterprise costs (including amortization of computer software at Eversource Service)

                             6.9                     12.7               2.0
Vegetation Management                                           6.8                     (0.8)             13.1

Funding of CL&P storm reserve as part of June 1, 2021 rate change (compensated by a decrease

 Amortization expense; no earnings impact)                     16.0                        -                 -

CL&P fees to fund customer support initiatives associated with the settlement agreement

                       10.0                        -                 -
Storm restoration costs                                        (6.9)                   (15.3)             (2.0)

Operating expenses, including vehicles and outside services

                                                4.8                     (0.7)             (1.0)
Other non-tracked operations and maintenance                    6.4                     (3.9)              1.0
Total Base Electric Distribution (Non-Tracked Costs)           61.2                      6.3              21.0
Tracked Costs:
Transmission expenses                                          (1.2)                     1.9               5.8
Other tracked operations and maintenance                       11.3                     20.9              (8.4)
Total Tracked Costs                                            10.1                     22.8              (2.6)
Total Operations and Maintenance                           $   71.3         

$29.1 $18.4




Depreciation expense increased in 2021, as compared to 2020, for CL&P, NSTAR
Electric and PSNH due to higher net plant in service balances. The increase at
PSNH was also due to new depreciation rates effective January 1, 2021 resulting
from the 2020 distribution rate settlement agreement.

Amortization of Regulatory Assets, Net expense includes the deferral of energy
supply, energy-related costs and other costs that are included in certain
regulatory-approved cost tracking mechanisms. This deferral adjusts expense to
match the corresponding revenues compared to the actual costs incurred. Energy
supply and energy-related costs are recovered from customers in rates and have
no impact on earnings. Amortization expense also includes the amortization of
certain costs as those costs are collected in rates. Amortization of Regulatory
Assets, Net increased/decreased in 2021, as compared to 2020, due primarily to
the following:

•The increase at CL&P was due primarily to the deferral adjustment of energy
supply, energy-related and other tracked costs, which can fluctuate from period
to period based on the timing of costs incurred and related rate changes to
recover these costs. The increase was partially offset by a decrease in storm
amortization expense related to the completion of the amortization period of
certain storm cost deferred assets.
•The decrease at NSTAR Electric was due to the deferral adjustment of energy
supply, energy-related costs and other tracked costs, which can fluctuate from
period to period based on the timing of costs incurred and related rate changes
to recover these costs.
•The increase at PSNH was due to the deferral adjustment of energy-related and
other tracked costs, which can fluctuate from period to period based on the
timing of costs incurred and related rate changes to recover these costs.

Energy Efficiency Programs expense includes costs of various state energy policy
initiatives and expanded energy efficiency programs that are recovered from
customers in rates, most of which have no impact on earnings. Energy Efficiency
Programs expense increased/decreased in 2021, as compared to 2020, due primarily
to the following:

•The decrease at CL&P was due to the deferral adjustment, which reflects actual
costs of energy efficiency programs compared to the estimated amounts billed to
customers, and the timing of the recovery of energy efficiency costs.
•The increases at NSTAR Electric and PSNH were due to the deferral adjustment,
which reflects actual costs of energy efficiency programs compared to the
estimated amounts billed to customers, and the timing of the recovery of energy
efficiency costs.

Taxes other than income taxes increased in 2021 compared to 2020, mainly due to the following items:


•The increase at CL&P was related to higher property taxes as a result of a
higher utility plant balance and higher gross earnings taxes.
•The increases at NSTAR Electric and PSNH were due to higher property taxes as a
result of higher utility plant balances.
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Interest expense increased/decreased in 2021 compared to 2020 mainly due to:


•The increase at CL&P was due primarily to higher interest on long-term debt
($5.4 million), an increase in interest expense on regulatory deferrals ($3.7
million), a decrease in AFUDC related to debt funds ($3.7 million), and higher
amortization of debt discounts and premiums, net ($0.9 million).
•The increase at NSTAR Electric was due primarily to an increase in interest
expense on regulatory deferrals ($7.6 million), higher interest on long-term
debt ($6.0 million), and higher amortization of debt discounts and premiums, net
($0.4 million).
•The decrease at PSNH was due primarily to a decrease in RRB interest expense
($1.3 million), lower amortization of debt discounts and premiums, net ($0.7
million), and lower interest on long-term debt ($0.5 million), partially offset
by a decrease in AFUDC related to debt funds ($1.3 million) and an increase in
interest expense on regulatory deferrals ($0.4 million).

Other net income increased in 2021 compared to 2020, mainly due to the following:


•The increase at CL&P was due primarily to an increase related to pension, SERP
and PBOP non-service income components ($11.4 million), higher interest income
($3.9 million), and an increase in investment income ($0.2 million), partially
offset by a decrease in AFUDC related to equity funds ($6.1 million).
•The increase at NSTAR Electric was due primarily to higher interest income
($12.5 million) and an increase related to pension, SERP and PBOP non-service
income components ($10.9 million), partially offset by a decrease in AFUDC
related to equity funds ($1.1 million).
•The increase at PSNH was due primarily to an increase related to pension, SERP
and PBOP non-service income components ($3.3 million), partially offset by a
decrease in AFUDC related to equity funds ($2.6 million).

Income tax expense increased/decreased in 2021, compared to 2020, mainly due to the following:


•The decrease at CL&P was due primarily to the CL&P settlement agreement ($17.5
million), a decrease in valuation allowance ($17.0 million), and a decrease in
items that impact our tax rate as a result of regulatory treatment (flow-through
items) and permanent differences ($9.8 million), partially offset by higher
pre-tax earnings excluding the settlement agreement charges ($6.2 million),
higher state taxes ($18.9 million) and lower share-based payment excess tax
benefits ($0.8 million).
•The decrease at NSTAR Electric was due primarily to an increase in amortization
of EDIT ($22.8 million), partially offset by higher pre-tax earnings ($3.2
million), higher state taxes ($1.4 million), an increase in items that impact
our tax rate as a result of regulatory treatment (flow-through items) and
permanent differences ($0.8 million), and lower share-based payment excess tax
benefits ($0.9 million).
•The increase at PSNH was due primarily to a decrease in amortization of EDIT
($4.9 million), higher state taxes ($0.4 million), higher pre-tax earnings ($2.2
million), and an increase in items that impact our tax rate as a result of
regulatory treatment (flow-through items) and permanent differences ($0.2
million).

WINNING SUMMARY


CL&P's earnings decreased $56.2 million in 2021, as compared to 2020, due
primarily to the settlement agreement on October 1, 2021 resulting in a total
$75 million pre-tax charge to earnings and a $28.6 million pre-tax charge to
earnings for a storm performance penalty imposed by the PURA as a result of
CL&P's preparation for and response to Tropical Storm Isaias in August 2020 that
was recorded in 2021. The after-tax impact of the settlement agreement and storm
performance penalty was $86.1 million. Earnings were also unfavorably impacted
by higher operations and maintenance expense primarily driven by higher
employee-related expenses, higher shared corporate costs, and higher vegetation
management costs, higher depreciation expense, higher property tax expense, and
higher interest expense. The earnings decrease was partially offset by higher
earnings from its capital tracker mechanism due to increased electric system
improvements, the base distribution rate increase effective May 1, 2020, an
increase in transmission earnings driven by a higher transmission rate base, and
an increase in the non-service income components of pension, SERP and PBOP net
periodic benefit plan cost.

NSTAR Electric's earnings increased $31.6 million in 2021, as compared to 2020,
due primarily to an increase in transmission earnings driven by a higher
transmission rate base, the base distribution rate increase effective January 1,
2021, a lower effective tax rate, and the earnings benefit in 2021 associated
with the deferral of threshold costs for certain 2020 and 2021 major storms. The
earnings increase was partially offset by higher operations and maintenance
expense primarily driven by higher employee-related expenses and higher shared
corporate costs, higher depreciation expense, and higher interest expense.

PSNH's earnings increased $3.0 million in 2021, as compared to 2020, due
primarily to the base distribution rate increases effective January 1, 2021 and
August 1, 2021, an increase in transmission earnings driven by a higher
transmission rate base, and the impact in 2021 of a new tracker mechanism at
PSNH approved as part of the 2020 rate settlement agreement. The earnings
increase was partially offset by higher operations and maintenance expense
primarily driven by higher vegetation management costs and higher
employee-related expenses, higher depreciation expense, and higher property tax
expense.
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LIQUIDITY


Cash Flows: CL&P had cash flows provided by operating activities of $612.9
million in 2021, as compared to $397.1 million in 2020.  The increase in
operating cash flows was due primarily to the timing of collections for
regulatory tracking mechanisms, the timing of cash collections on our accounts
receivable, the timing of cash payments made on our accounts payable, and the
timing of other working capital items. These favorable impacts were partially
offset by a $75.7 million increase in pension contributions made in 2021, as
compared to 2020, a $38.4 million increase in cost of removal expenditures, and
a $27.5 million increase in income tax payments made in 2021, as compared to
2020.

NSTAR Electric had cash flows provided by operating activities of $700.9 million
in 2021, as compared to $525.8 million in 2020.  The increase in operating cash
flows was due primarily to the timing of collections for regulatory tracking
mechanisms, the timing of other working capital items, a $36.5 million decrease
in income tax payments made in 2021, as compared to 2020, the timing of cash
collections on our accounts receivable, and the timing of cash payments made on
our accounts payable. These favorable impacts were partially offset by a $29.4
million increase in pension contributions made in 2021, as compared to 2020, and
a $19.8 million increase in cost of removal expenditures.

PSNH had cash flows provided by operating activities of $336.1 million in 2021,
as compared to $218.7 million in 2020. The increase in operating cash flows was
due primarily to the timing of collections for regulatory tracking mechanisms,
the timing of other working capital items, and the absence in 2021 of pension
contributions of $19.5 million made in 2020. These favorable impacts were
partially offset by the timing of cash payments made on our accounts payable, a
$16.9 million increase in income tax payments made in 2021, as compared to 2020,
and an $8.7 million increase in cost of removal expenditures.

For further information on CL&P's, NSTAR Electric's and PSNH's liquidity and
capital resources, see "Liquidity" and "Business Development and Capital
Expenditures" included in this Management's Discussion and Analysis of Financial
Condition and Results of Operations.

Item 7A. Quantitative and qualitative information on market risk

Market risk information


Commodity Price Risk Management:  Our regulated companies enter into energy
contracts to serve our customers, and the economic impacts of those contracts
are passed on to our customers.  Accordingly, the regulated companies have no
exposure to loss of future earnings or fair values due to these market
risk-sensitive instruments.  Eversource's Energy Supply Risk Committee,
comprised of senior officers, reviews and approves all large-scale energy
related transactions entered into by its regulated companies.

Other risk management activities


We have an Enterprise Risk Management (ERM) program for identifying the
principal risks of the Company.  Our ERM program involves the application of a
well-defined, enterprise-wide methodology designed to allow our Risk Committee,
comprised of our senior officers of the Company, to identify, categorize,
prioritize, and mitigate the principal risks to the Company.  The ERM program is
integrated with other assurance functions throughout the Company including
Compliance, Auditing, and Insurance to ensure appropriate coverage of risks that
could impact the Company.  In addition to known risks, ERM identifies emerging
risks to the Company, through participation in industry groups, discussions with
management and in consultation with outside advisers.  Our management then
analyzes risks to determine materiality, likelihood and impact, and develops
mitigation strategies.  Management broadly considers our business model, the
utility industry, the global economy, climate change, sustainability and the
current environment to identify risks.  The Finance Committee of the Board of
Trustees is responsible for oversight of the Company's ERM program and
enterprise-wide risks as well as specific risks associated with insurance,
credit, financing, investments, pensions and overall system security including
cyber security.  The findings of the ERM process are periodically discussed with
the Finance Committee of our Board of Trustees, as well as with other Board
Committees or the full Board of Trustees, as appropriate, including reporting on
how these issues are being measured and managed.  However, there can be no
assurances that the ERM process will identify or manage every risk or event that
could impact our financial position, results of operations or cash flows.

Interest Rate Risk Management:  We manage our interest rate risk exposure in
accordance with our written policies and procedures by maintaining a mix of
fixed and variable rate long-term debt.  As of December 31, 2021, approximately
98 percent of our long-term debt was at a fixed interest rate. The remaining
long-term debt is at variable interest rates and is subject to interest rate
risk that could result in earnings volatility. Assuming a one percentage point
increase in our variable interest rates, annual interest expense would have
increased by a pre-tax amount of $3.5 million.

Credit Risk Management:  Credit risk relates to the risk of loss that we would
incur as a result of non-performance by counterparties pursuant to the terms of
our contractual obligations.  We serve a wide variety of customers and transact
with suppliers that include IPPs, industrial companies, natural gas and electric
utilities, oil and natural gas producers, financial institutions, and other
energy marketers.  Margin accounts exist within this diverse group, and we
realize interest receipts and payments related to balances outstanding in these
margin accounts.  This wide customer and supplier mix generates a need for a
variety of contractual structures, products and terms that, in turn, require us
to manage the portfolio of market risk inherent in those transactions in a
manner consistent with the parameters established by our risk management
process.

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Our regulated companies are subject to credit risk from certain long-term or
high-volume supply contracts with energy marketing companies.  Our regulated
companies manage the credit risk with these counterparties in accordance with
established credit risk practices and monitor contracting risks, including
credit risk.  As of December 31, 2021, our regulated companies held collateral
(letters of credit or cash) of $210.9 million from counterparties related to our
standard service contracts. As of December 31, 2021, Eversource had
$34.6 million of cash posted with ISO-NE related to energy transactions. For
further information on cash collateral deposited and posted with counterparties,
see Note 1O, "Summary of Significant Accounting Policies - Supplemental Cash
Flow Information," to the financial statements.

If the respective unsecured debt ratings of Eversource or its subsidiaries were
reduced to below investment grade by either Moody's or S&P, certain of
Eversource's contracts would require additional collateral in the form of cash
to be provided to counterparties and independent system operators.  Eversource
would have been and remains able to provide that collateral.

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