14SEP201110485170
2019
Annual Report
Report to Shareholders
Dear Fellow Shareholder:
In the present crisis, many of us are reminded of Winston Churchill during World War II.
Churchill had been, of course, an early and outspoken advocate for taking the Nazi threat seriously and
being prepared. (His newspaper columns from that time are collected in his book, Step by Step: Political
Writings: 1936-1939.)(1)
Before he became Prime Minister he said:
‘‘... let pre-war feuds die; let personal quarrels be forgotten, and let us keep our hatreds for
the common enemy. Let party interest be ignored, let all our energies be harnessed, let the whole
ability and forces of the nation be hurled into the struggle, and let all the strong horses be pulling
on the collar.’’
Churchill was a great statesman. We’ll do our best to heed his call in today’s crisis.
In this letter I will address several key areas of our business before concluding with a look
forward. A more detailed summary of the business and financial highlights of the past year follows this
letter.
PEOPLE
On March 9, we sent an email to our corporate staff in Dedham, Massachusetts, indicating that
those who were uncomfortable coming into the office should work remotely. Two days later we
reiterated that advice during the day. That evening at midnight I sent an email strongly encouraging
people to work from home beginning the next day. Our office essentially has been in work-from-home
mode since March 12.
While our corporate office employees could readily shift to working from home, our plant
employees could not for the most part. Our business is power generation. Keeping the lights on is an
essential service. Our employees have been given letters from various states and provinces to allow
them to travel to work. To date, we are fortunate that none of our employees has tested positive for
coronavirus. Where there has been potential exposure, people have self-quarantined. Our plants have
continued to operate without interruption. Our plant employees are among the many heroes at work
today in the United States and Canada.
On March 13, we sent an email to all our employees announcing that there would be no layoffs,
salary cuts, or benefit reductions due to the pandemic. Our financial strength—hard won after years of
paying down debt and reducing corporate overhead—means we came into the crisis well positioned to
navigate a perfect storm. Our financial strength is also benefiting our shareholders.
CAPITAL ALLOCATION
As I noted in our March 18 press release:
‘‘We have highly contracted EBITDA(2) and operating cash flow. More than 95% of our
cumulative EBITDA(2) and operating cash flow through 2024 is generated under PPAs (Power
Purchase Agreements) with an average remaining term of approximately six years. These PPAs are
predominantly with investment-grade counterparties. We plan to continue allocating the majority of
this strong cash flow to debt repayment, and expect to amortize the balance of our Term Loan by
the April 2025 maturity. During this five-year period we expect to generate significant discretionary
cash flow after debt repayment, as we noted on our fourth quarter 2019 conference call.’’
There are basically five things that a company can do with its discretionary capital—invest in its
own business; pay down debt; undertake mergers or acquisitions; repurchase equity securities; and pay
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common dividends. This is how we have allocated capital among those five potential uses during the
past five to seven years:
1.
Invest in the Business
In previous years we made significant discretionary investments in our power plants. These were
investments in excess of maintenance capital expenditures that were made to improve operating
efficiency, increase production, and/or reduce operating costs. The effort started before the current
management team was in place. From 2013 through 2016, we invested a total of $25 million. The
returns on these investments were attractive, but we have picked the low-hanging fruit and there is less
need for this type of investment today.
2.
Pay Down Debt
Debt reduction is not driven by the returns available on our debt, but rather the priority of
strengthening our balance sheet. We believe this is prudent given the nature of our business, our asset
profile, and the state of the power markets. We have reduced our consolidated debt by more than
$1.2 billion since year-end 2013. Cash interest savings resulting from this debt reduction and several
re-pricings of our credit facilities total approximately $89 million annualized. As a result of this balance
sheet improvement and commitment to further delevering, we have received several credit rating
upgrades from the rating agencies since late 2015, which also help to lower our cost of capital.
3. Mergers & Acquisitions
In thinking about capital allocation, we focus on intrinsic value per share, not the absolute size of
our business. We want to grow the business, of course, but when returns on internal uses of capital are
better than those available on external investments, we want to make the rational, disciplined choice in
terms of the impact on intrinsic value per share.
We are always looking for new investments, but from 2015 through 2017, we did not find anything
compelling. Then in 2018 and 2019, we invested a total of $45 million to acquire ownership interests in
a hydro facility and four biomass plants. The PPAs on these five plants expire between year-end 2027
and late 2043, so they extend our remaining average contract term and increase our long-term cash
flows. The acquisition of the 50% of the Koma Kulshan hydro facility that we did not already own was
in response to the other owner seeking to exit. The investment return was acceptable but not
outstanding, but we know the plant well and we think hydro has a long economic life beyond the PPA
term. In contrast, biomass is an unpopular technology that is more difficult to operate. Our returns on
the biomass acquisitions are expected to be in excess of 15% unlevered pre-tax. We have approximately
$523 million in net operating losses, and thus we do not expect to pay significant federal cash taxes in
either the United States or Canada for some time ahead.
We are also willing to sell assets when doing so represents the best outcome for our shareholders.
In 2019, we reached an agreement to sell our Manchief plant to the customer under the PPA in May
2022, following the expiration of the PPA. By retaining ownership of Manchief until then, we will
continue to realize the cash flows for the remaining PPA term. At closing, we will use the $45.2 million
of proceeds to further pay down debt.
4. Buy Back Shares
Since December 2015, we have invested $47.0 million in the repurchase of approximately
20.8 million common shares at an average price of $2.26 per share. Year to date, we have significantly
accelerated our repurchases of common shares. In addition, since June 2017, we have invested
Cdn$33.6 million (US$25.5 million equivalent) in the repurchase of more than 2.1 million preferred
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shares at an average discount to par of 37% and implied after-tax returns ranging between 10% and
12%.
5.
Pay Common Dividends
We paid $10 million of common dividends in 2015. We omitted the dividend in 2016 because we
believed then, and continue to believe, that payment of a common dividend is not consistent with the
characteristics of our business model or current market conditions.
As we consider potential options for the use of our discretionary capital, our preference is to
invest in our business, which we understand best. We pay down debt not based on the returns from
doing so, but from a desire to reduce risk and costs, and to right size our debt relative to our Project
Adjusted EBITDA(2) outlook.
External investments grow the overall size of the business, while share buybacks take cash out of
the business and return it to shareholders. Again, we are driven by intrinsic value per share. We will
shrink our balance sheet through buybacks if that creates more value for shareholders than making
acquisitions or new investments. We are laser focused on shareholder value.
I’ll have more to say on buybacks below, but briefly on common dividends—they can be a good
way to return cash to shareholders if a company has excess capital (and insufficient uses with attractive
returns) and it believes it can sustain the dividend through economic cycles. Today, we have a surfeit of
good things to do with our capital, along the lines of the things I noted above. Another consideration
for us is that our Project Adjusted EBITDA(2) will decline after 2022 as some of our more significant
PPAs begin to expire and the plants are re-contracted either at lower prices or not at all. The impact
on our operating cash flow is expected to be less, however, due to our continued repayment of debt,
which should reduce cash interest payments. While we expect to generate significant cash flow in excess
of our needs over the next five years, our Project Adjusted EBITDA(2) profile is not consistent with a
sustainable dividend policy.
SHARE BUYBACKS
Politicians and the media are in the process of politicizing share buybacks. When that happens,
intelligent investing goes out the window, to be replaced by ideology.
When a company repurchases shares, cash goes from the corporate treasury to shareholders who
choose to sell their shares. Those shareholders either spend the cash or invest the cash elsewhere.
Shareholders who choose not to sell their shares effectively increase their ownership in the company.
In some industries there is overcapacity and low or no growth. Other industries have a greater
need for capital for internal or external expansion. It is rational to return capital to shareholders when
an industry is oversupplied with capital or the financial profile of the individual business makes that an
attractive use of capital.
Warren Buffett popularized share buybacks in this country. (Although on this front, we’d have to
view Henry Singleton as the Samuel Johnson and Buffett as the James Boswell.) Buffett focuses on the
price-to-intrinsic value relationship. If a company repurchases shares below its estimate of intrinsic
value per share, then intrinsic value per remaining share increases. If repurchases are done at a
premium to intrinsic value per share, then intrinsic value per remaining share declines.
Our share buybacks are a function of the price-to-value relationship compared to other potential
uses of discretionary capital. We don’t buy back shares to send messages. I have never sold a share of
Atlantic Power stock and don’t intend to do so. If the share price moved above our estimates of
intrinsic value, we would consider issuing shares if we needed the capital. We would not buy shares at a
price in excess of our estimates of intrinsic value.
iii
Unfortunately, our country and the world are experiencing a health crisis. The economic
consequences will be severe. Fortunately, Atlantic Power’s conservative financial management and
disciplined approach allowed us to protect our employees in this crisis and to ramp up our return of
capital to shareholders.
EAT YOUR OWN COOKING
Since I joined the company as CEO in January 2015 through the end of March of this year,
executives and directors have bought nearly 2.3 million Atlantic Power common shares at a gross
purchase price of more than $5.1 million. These shares were purchased in the open market by those
individuals using personal funds and don’t include shares granted by the company as part of executive
or board compensation. In my view, a history of officers and directors taking money out of their savings
accounts to buy shares in the open market is the best evidence of managers aligning their interests with
those of shareholders. Insider ownership, which does include shares granted under compensation
programs, has increased from less than 1% of shares in 2014 to 3.4% today.
Meanwhile, the CEO and the two executive vice presidents have not had a base salary increase
since 2015 (or earlier). All three received less total compensation in 2019 than in the previous year due
to lower short-term bonuses and long-term equity incentives, despite 2019 being a highly successful year
in terms of growth and an excellent year in many other ways, as indicated by the financial results. In
both our portfolios and our executive compensation programs, we are trying to align our interests with
those of shareholders.
GOING FORWARD
I did say at the beginning of this letter that I would provide a look forward.
For us, the best case scenario—as measured in terms of intrinsic value per share—would be a
return to higher power prices. I have talked at length in past letters on power market fundamentals,
environmental policies, and the tough dynamics in the sector.
If we see some supply destruction resulting from significant cuts to exploration and production
budgets, then natural gas prices might actually rise. That would benefit our hydro projects as their
PPAs expire.
If we see some improved capital discipline from institutions after a period of financial crisis, we
might see a slowing of new investment in gas, wind, and solar plants, which in most cases are not
needed as markets are generally oversupplied. These additions have net negative environmental impacts
versus utilizing existing gas plants at higher than current levels of capacity. That development would be
good for us across the board.
If, on the other hand, things muddle along with the status quo in the power sector for years to
come, we have an average remaining PPA term of six years and our strong operating cash flow provides
the ability to pay off our Term Loan by its maturity in April 2025. If we did nothing else with our
excess cash flow, we would expect to reach a zero net debt position sometime in 2025. At that point,
we’d have hydro assets with long economic lives that are difficult to replace, gas plants that are more
economic, more reliable and on a holistic analysis probably better environmentally than wind, solar, and
batteries, and biomass plants with significant remaining PPA term—with no net debt. We don’t mind
being in that position. We think about the business as if we were a family office expecting to own it for
the long term, with potential upside from higher power and gas prices and investment opportunities
and a downside that seems reasonably well protected.
Over the next five years we expect to generate cumulative discretionary cash flow of $115 million
to $165 million after repaying $423 million of term loan and project debt during this period. In
addition, on March 31 of this year, we had liquidity of $150 million, consisting of $48 million in cash
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and $102 million in available capacity under our revolver. We have been using cash for the repurchases
of common and preferred shares and the acquisitions that we made in 2018 and 2019. Our revolver is
available through April 2025 for acquisitions.
Over the past several years, we have reshaped Atlantic Power to withstand hard economic times
with a stronger balance sheet and leaner cost structure. This is allowing us to react to the crisis as we
have, for both our employees and our shareholders. Although our remaining PPA life is not as long as
that of some other power companies in Canada, it is longer than most U.S. independent power
producers, and it provides us the cash flow to pay down debt and generate discretionary capital even in
a severe economic downturn.
We hope that both the pandemic and the economic fallout are short-lived, but we suspect there
will be some changes needed by many businesses to adapt their balance sheets and business models to
the new reality. Although we are small, we believe we are well positioned to use our liquidity when
hard and turbulent times hit. We’ll do our best to use that position wisely for our shareholders,
employees, customers, and the communities we serve.
If you have read this far, thank you for your interest in Atlantic Power. May you and your families
stay healthy and safe.
21APR201521422407
James J. Moore, Jr.
President and Chief Executive Officer
April 28, 2020
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Safety
2019 Business and Financial Highlights
Environmental, health, and safety performance. Safety remains our highest priority. Despite our
continued strong focus on this area, we had nine recordable injuries in 2019, up from four in 2018.
Fortunately, none resulted in hospitalizations. Three of the injuries resulted in lost time (versus one in
2018). In response to these developments, we increased behavioral safety training, rolled out a survey
to determine which areas required improvement, expanded sharing of best practices across our plants
and simplified a safety dashboard to better track injuries, safety training, and safety improvements.
Several of these recordable injuries were associated with cuts and pinches to hands and could be
attributable to improper hand protection, so our teams provided revised glove training for our staff and
ensured that all plants were equipped with the proper hand protection required for all tasks. In
addition, our environmental health and safety team increased its visits to our plants during scheduled
outages. In the first quarter of 2020, we had no recordable injuries. Looking at our safety performance
over a longer period, in 2019, nine of the 16 plants that we operate completed at least five consecutive
years of operation without a lost-time incident. We received two environmental notices of violation in
2019, both minor, which we responded to and corrected promptly. We did not receive any notices of
violation from either the Federal Energy Regulatory Commission or the North American Electric
Reliability Council.
Culture
Servant leadership. We continued to promote a culture of servant leadership throughout the
organization, emphasizing the need for leaders to act with respect, integrity, and honesty. We place very
high importance on this effort, as we believe a strong culture is the bedrock of building long-term
sustainable value. In 2019, we continued to roll out training to the plant level.
Operational
Plant availability.
In 2019, our plants had an availability factor of 94.0%, with strong performance
at most of our plants. The overall average declined from 96.5% in 2018 primarily due to extended
outages at our Moresby Lake hydro plant due to a main transformer failure and at our Cadillac
biomass plant due to a fire in September.
Continued focus on operating costs.
In 2019, we continued to advance our program to improve our
operation and maintenance performance. We rolled out Mainsaver (a maintenance management
system) to the South Carolina biomass plants that we acquired in July, to the Koma Kulshan hydro
plant, in which we acquired the remaining ownership interests in the third quarter of 2018, and to our
Piedmont biomass plant. We are continuing to focus on optimizing preventive maintenance programs
for all of our facilities. Another area of focus is avoiding equipment issues that result in unplanned
outages. To that end, we have installed predictive analytic maintenance software (‘‘PRiSM’’) at seven
plants over the past two years. To date, the system has had 32 ‘‘good catches’’ (potential equipment
problems that were avoided). We intend to roll PRiSM out to two more plants in 2020. Our operations
team continues to look for ways to improve the reliability and efficiency of our plants while ensuring
the effectiveness of our maintenance and capital expenditures.
Asset management.
In 2019, we successfully integrated the acquisition of the Allendale and
Dorchester biomass plants in South Carolina into our fleet. We began the process of decommissioning
our three plants in San Diego, with demolition expected to be completed in 2020. In the fourth quarter
of 2019, we rolled out a new system for testing and evaluating the condition of all plant step-up
transformers. Understanding the condition of these critical components will allow us to better predict
potential failures, plan for long-lead purchases, and avoid extended plant outages.
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Commercial
New contract for our Williams Lake plant.
In September 2019, we executed a new ten-year Energy
Purchase Agreement with BC Hydro for our Williams Lake biomass plant in British Columbia that
became effective October 1, 2019. Under the new contract, Williams Lake receives a fixed price per
megawatt-hour for energy produced. This price escalates annually in line with inflation, but does not
include a fuel cost pass-through. Given the state of the timber market in British Columbia, we believe
that the availability and cost of fuel will be the most significant variables determining the operational
and financial performance of the plant. Since executing the new contract, we have been focused on
rebuilding our fuel supply sources, including traditional mill waste and forest and roadside residuals.
We have entered into a new fuel supply arrangement with local First Nations, purchased and deployed
a new mobile fuel grinder, and entered into other short-term agreements with third parties to extend
supplies of mill waste and secure additional forest residuals. The grinder has been helpful in sourcing
and transporting wood waste from forest areas.
PPA extension for our Kenilworth plant.
In July 2019, Merck (the customer at our Kenilworth
plant) executed its option to extend the PPA for another year, to September 2021. This was the third
and final one-year extension option under the PPA. We continue to engage with Merck on short-term
and long-term options for their power supply needs beyond that date.
Closed two acquisitions.
In July 2019, we closed the acquisition of the Allendale and Dorchester
biomass plants in South Carolina from EDF Renewables. The plants, which each have a capacity of
20 megawatts (‘‘MW’’), operate under PPAs that run through late 2043. In August 2019, we closed the
acquisition of equity interests in two other biomass plants from AltaGas Power Holdings (U.S.) Inc. We
acquired a 50% interest in the 48 MW Craven plant in North Carolina and a 30% interest in the
37 MW Grayling plant in Michigan; both plants operate under PPAs that run through 2027.
Agreement for the sale of our Manchief plant.
In May 2019, we reached an agreement to sell our
Manchief gas-fired plant to Public Service Co. of Colorado for $45.2 million in May 2022 following the
expiration of the plant’s PPA. We view this as a positive outcome that will allow us to realize the cash
flows generated by the plant during the remaining contract term and further reduce debt upon closing
of the sale in 2022. All regulatory approvals required for the sale have been received.
Financial
Results in line with or better than guidance.
In 2019, cash provided by operating activities (a GAAP
measure) was $144.7 million. Excluding a net working capital benefit, cash flow was approximately
$128 million, which exceeded our estimated range of $115 million to $125 million (which was increased
from our initial estimate of $100 million to $115 million). Project Adjusted EBITDA(2) was
$196.1 million, which exceeded our guidance range of $185 million to $195 million (which was
increased from our initial guidance of $175 million to $190 million). (Project Adjusted EBITDA is a
non-GAAP measure; see Appendix A on page xii for a reconciliation to its nearest GAAP measure.)
Continued to significantly reduce debt.
In 2019, we repaid $72.3 million of term loan and
consolidated project debt from operating cash flow. In addition, in April 2019, we used discretionary
cash to redeem Cdn$24.7 million (US$18.5 million equivalent) of the remaining 6.00% Series D
convertible debentures that were scheduled to mature in December 2019. Our total consolidated debt
reduction of $90.8 million represented an approximate 11% reduction in debt from the year-end 2018
level. At year-end 2019, our consolidated leverage ratio(3) was 3.8 times, improved from 4.5 times at
year-end 2018. Since year-end 2013, we have reduced consolidated debt by $1.2 billion or approximately
65%.
Reduced interest payments.
In 2019, we reduced our cash interest payments by nearly $4 million
from the 2018 level. We achieved this as a result of continued debt repayment and the reductions in
vii
the spread on our credit facilities. Since 2013, consistent with the significant debt reduction during that
period, our cash interest payments have been reduced by more than $90 million. We also continue to
manage our exposure to increases in market interest rates. At year-end 2019, more than 99% of our
consolidated debt carried either a fixed rate or a variable rate that has been fixed through interest rate
swaps. We have hedged approximately 93% of our interest rate exposure on our Term Loan through
2021.
Credit rating upgrade.
In December 2019, S&P Global Ratings raised its issuer credit rating for
the Corporation to BB- (stable) from B+ (positive) based on our improving leverage profile. Ratings
on our Term Loan, Revolving Credit Facility and Medium-Term Notes were raised to BB from BB-.
S&P cited our highly contracted cash flow profile and demonstrated track record and commitment to
deleveraging. Since October 2015, we have received four rating upgrades, two each from S&P and
Moody’s.
Maintained strong liquidity. Our liquidity at year-end 2019 was $196.5 million, including
approximately $42 million of discretionary cash. Even after completing two acquisitions and
repurchasing a significant amount of common and preferred shares during 2019, our liquidity increased
slightly from the year-end 2018 level.
Maintained stable overhead costs. Our 2019 corporate general and administrative (‘‘G&A’’) costs of
$24 million were essentially unchanged from the 2018 level. G&A expense has been about flat since
2016, but is down approximately 56% from the 2013 level. Although the most significant cost
reductions are behind us, we continue to look for additional cost reduction opportunities.
Capital Allocation
Acquisitions of contracted assets. As noted, in 2019, we closed the acquisitions of two biomass
plants and equity interests in two other biomass plants for a total investment of $31.3 million. These
operating plants have long-dated PPAs that add to our capacity and extend our average remaining
contract life and which have been contributing to Project Adjusted EBITDA(2) and cash flow. (Project
Adjusted EBITDA is a non-GAAP measure; see Appendix A on page xii for a reconciliation to its
nearest GAAP measure.) Including the $13.6 million acquisition of a consolidating interest in our
Koma Kulshan hydro project in 2018, we invested $44.9 million in acquisitions in 2018 and 2019,
marking a significant reorientation toward growth initiatives after a multiyear restructuring effort. We
funded these acquisitions from discretionary cash.
Repurchases of common and preferred shares. During 2019, we repurchased and canceled nearly
1.1 million common shares at a total cost of $2.5 million, or an average price of $2.31 per share. We
made these purchases because we considered the trading price of our common shares to be at a
discount to our estimates of intrinsic value per share. We also repurchased and canceled approximately
676,000 preferred shares at a total cost of Cdn$10.6 million (US$8.0 million equivalent), representing
an approximate 38% discount to par value and an attractive after-tax yield of approximately 10% to
12%. We undertake repurchases of our securities when we believe that the returns from such
repurchases are more compelling than the returns available from other internal or external investments.
We funded these $10.5 million of repurchases from discretionary cash. From 2015 through 2019, we
repurchased a total of approximately 17.0 million common shares, representing an investment of
$38.8 million, and a total of nearly 1.6 million preferred shares, representing a total investment of
Cdn$24.7 million (US$19.1 million equivalent). Common shares outstanding have been reduced by
approximately 11% during this period.
viii
Q1 2020 Developments
Achieved favorable changes to credit facilities.
In the first quarter of 2020, we amended our credit
facilities to extend the maturity dates of our $380 million Term Loan and our Revolving Credit Facility
to April 2025. The capacity of the Revolving Credit Facility was reduced to $180 million from
$200 million, although we can seek an increase to a maximum of $210 million without a further
amendment, subject to conditions. In addition, the interest rate margin on these facilities was reduced
by 25 basis points to LIBOR plus 250 basis points. Since issuing the credit facilities in 2016, we have
re-priced the spread a total of five times, with a cumulative reduction in the margin of 250 basis points.
The margin will be reduced another 25 basis points if we achieve a consolidated leverage ratio(3) of 2.75
times.
ix
Notes
(1) Churchill, Winston S. Step by Step: Political Writings: 1936-1939. New York: Bloomsbury Academic,
2015.
(2) Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a
standardized meaning prescribed by GAAP, and is therefore unlikely to be comparable to similar
measures presented by other companies. Investors are cautioned that the Company may calculate
this non-GAAP measure in a manner that is different from other companies. The most directly
comparable GAAP measure is Project income (loss). Project Adjusted EBITDA is defined as
Project income (loss) plus interest, taxes, depreciation, and amortization (including non-cash
impairment charges), and changes in the fair value of derivative instruments. Management uses
Project Adjusted EBITDA at the project level to provide comparative information about project
performance and believes such information is helpful to investors. A reconciliation of Project
Adjusted EBITDA to Project income (loss) and to Net income (loss) on a consolidated basis is
provided in Appendix A on page xii. The Company has not provided guidance for Project income
or Net income because of the difficulty of making accurate forecasts and projections without
unreasonable efforts with respect to certain highly variable components of these comparable
GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange
gains or losses.
(3) Leverage ratio is defined as the ratio of Consolidated Debt to Adjusted EBITDA, calculated for
the trailing four quarters. Note that we calculate this ratio on a gross debt basis, not net of cash.
Cautionary Note Regarding Forward-Looking Statements
To the extent any statements made in this news release contain information that is not historical,
these statements are forward-looking statements within the meaning of Section 27A of the U.S.
Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as
amended, and under Canadian securities law (collectively, ‘‘forward-looking statements’’).
Certain statements in this news release may constitute forward-looking information or forward-
looking statements within the meaning of applicable securities laws (collectively, ‘‘forward-looking
statements’’), which reflect the expectations of management regarding the future growth, results of
operations, performance and business prospects and opportunities of the Company and its projects.
These statements, which are based on certain assumptions and describe the Company’s future plans,
strategies and expectations, can generally be identified by the use of the words ‘‘plans’’, ‘‘expects’’,
‘‘does not expect’’, ‘‘is expected’’, ‘‘budget’’, ‘‘estimates’’, ‘‘forecasts’’, ‘‘intends’’, ‘‘anticipates’’ or ‘‘does
not anticipate’’, ‘‘believes’’, ‘‘outlook’’, ‘‘objective’’, or ‘‘continue’’, or equivalents or variations, including
negative variations, of such words and phrases, or state that certain actions, events or results, ‘‘may’’,
‘‘could’’, ‘‘would’’, ‘‘should’’, ‘‘might’’ or ‘‘will’’ be taken, occur or be achieved. Examples of such
statements in this press release include, but are not limited to, statements with respect to the following:
(cid:129) that the Company’s financial strength means it is well positioned to navigate the COVID-19
crisis;
(cid:129) the Company’s plan to continue allocating its discretionary capital to debt repayment;
(cid:129) the Company’s expectation that it will pay off its term loan in full in April 2025;
(cid:129) the Company’s expectation that there is less need for discretionary investments in existing assets;
(cid:129) the Company’s expectation that the return on the biomass plants acquired in 2019 will be in
excess of 15% unlevered pre-tax;
x
(cid:129) the Company’s expectation that it will not pay U.S. federal or Canadian income taxes for some
time;
(cid:129) the Company’s plan to use the proceeds of the Manchief plant sale to pay down debt;
(cid:129) the Company’s expectation with respect to the impact of PPA expirations on its Project Adjusted
EBITDA and operating cash flow after 2022;
(cid:129) the Company’s expectation with respect to generation of cumulative discretionary cash flow over
the next five years;
(cid:129) the Company’s plan to roll out PRiSM to two more plants in 2020;
(cid:129) the Company’s plans to demolish the three San Diego plants;
(cid:129) the Company’s assessment of its credit profile and liquidity;
(cid:129) the Company’s view that the Koma Kulshan hydro facility has economic life beyond the PPA
term;
(cid:129) the Company’s expectation that the acquisition of the South Carolina biomass plants will extend
average remaining contract life and strengthen longer-term cash flows; and
(cid:129) the Company’s estimate that the repurchase of preferred shares yielded an after-tax return of
approximately 10% to 12%.
Forward-looking statements involve significant risks and uncertainties, should not be read as
guarantees of future performance or results, and will not necessarily be accurate indications of whether
or not or the times at or by which such performance or results will be achieved. Please refer to the
factors discussed under ‘‘Risk Factors’’ and ‘‘Forward-Looking Information’’ in the Company’s periodic
reports as filed with the U.S. Securities and Exchange Commission (the ‘‘SEC’’) from time to time for
a detailed discussion of the risks and uncertainties affecting the Company. Although the forward-
looking statements contained in this news release are based upon what are believed to be reasonable
assumptions, investors cannot be assured that actual results will be consistent with these forward-
looking statements, and the differences may be material. These forward-looking statements are made as
of the date of this news release and, except as expressly required by applicable law, the Company
assumes no obligation to update or revise them to reflect new events or circumstances.
xi
APPENDIX A
ATLANTIC POWER CORPORATION
RECONCILIATION OF NET (LOSS) INCOME (A GAAP MEASURE) TO PROJECT ADJUSTED
EBITDA FOR THE YEARS ENDED DECEMBER 31, 2019 AND DECEMBER 31, 2018
(UNAUDITED)
(in millions of U.S. dollars, except as otherwise stated)
2019
2018
Net (loss) income attributable to Atlantic Power Corporation . . . . . . . . . . . . . . . . . .
Net (loss) income attributable to preferred share dividends of a subsidiary company . .
($ 42.6) $ 36.8
0.4
(1.2)
Net (loss) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
($ 43.8) $ 37.2
0.2
9.8
(Loss) income from operations before income taxes . . . . . . . . . . . . . . . . . . . . . . . . .
Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign exchange loss (gain) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other expense (income), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(34.0)
23.9
44.0
11.9
1.0
37.4
23.9
52.7
(22.8)
(3.0)
Project income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 46.8
$ 88.2
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in the fair value of derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Insurance loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other expense (income), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 80.7
2.5
8.9
55.0
1.0
1.2
$ 99.7
3.4
(2.2)
—
—
(4.0)
Project Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$196.1
$185.1
xii
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(cid:95)
(cid:134)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2019
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the transition period from to
Commission file number 001-34691
ATLANTIC POWER CORPORATION
(Exact Name of Registrant as Specified in its Charter)
British Columbia, Canada
(State of Incorporation)
3 Allied Drive, Suite 155
Dedham, MA
(Address of Principal Executive Offices)
55-0886410
(I.R.S. Employer Identification No.)
02026
(Zip Code)
(617) 977-2400
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Shares, no par value per share, and
the associated Rights to Purchase Common Shares
Securities registered pursuant to Section 12(g) of the Act: None
Trading symbol
AT
Name of Each Exchange on which registered
The New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:134) No (cid:95)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:134) No (cid:95)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes (cid:95) No (cid:134)
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of
Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). (cid:95) Yes (cid:134) No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an
emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2
of the Exchange Act.
Large Accelerated Filer (cid:134)
Emerging growth company (cid:134)
Accelerated Filer (cid:95)
Non-Accelerated Filer (cid:134)
Smaller reporting company (cid:1409)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or
revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. (cid:134)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:134) No (cid:95)
As of June 30, 2019, the aggregate market value of the voting and nonvoting common equity held by non-affiliates of the registrant was $256.6 million based
upon the last reported sale price on the New York Stock Exchange. For purposes of the foregoing calculation only, all directors and executive officers of the registrant have
been deemed affiliates.
As of February 26, 2020, 106,932,375 of the registrant’s Common Shares were outstanding.
Portions of the registrant’s definitive Proxy Statement for its 2020 Annual Meeting of Shareholders, to be filed not later than 120 days after the end of the
registrant’s fiscal year, are incorporated by reference into Items 10 through 14 of Part III of this Annual Report on Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
4
17
38
38
38
38
39
41
43
75
78
79
79
79
80
80
80
80
80
81
85
TABLE OF CONTENTS
BUSINESS
PART I
ITEM 1.
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2.
ITEM 3.
ITEM 4. MINE SAFETY DISCLOSURES
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
PROPERTIES
LEGAL PROCEEDINGS
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
SELECTED FINANCIAL DATA
ITEM 6.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8.
ITEM 9.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 16. FORM 10-K SUMMARY
i
PART I
As used herein, the terms “Atlantic Power,” the “Company,” “we,” “our,” and “us” refer to Atlantic Power
Corporation, together with those entities owned or controlled by Atlantic Power Corporation, unless the context indicates
otherwise. All references to “Cdn$” and “Canadian dollars” are to the lawful currency of Canada and references to “$,”
“US$” and “U.S. dollars” are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars,
unless otherwise indicated.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the
meaning of the Private Securities Litigation Reform Act of 1995 and Canadian securities laws. Forward-looking
statements generally can be identified by the use of forward-looking terminology such as “outlook,” “objective,” “may,”
“will,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “should,” “plans,” “continue,” or similar expressions
suggesting future outcomes or events. Examples of such statements in this Annual Report on Form 10-K include, but are
not limited to, statements with respect to the following:
•
•
•
•
•
•
•
•
our ability to generate sufficient cash flow to service our debt obligations or implement our business
plan, including financing internal or external growth opportunities;
the outcome or impact of our business strategy to increase our intrinsic value on a per-share basis
through disciplined management of our balance sheet and cost structure and internal investments in our
fleet, external acquisitions and repurchases of debt, common and preferred securities;
our ability to renew or enter into new power purchase agreements (“PPAs”) on favorable terms or at
all after the expiration of our current agreements;
our ability to meet the financial covenants under our Credit Facilities (as defined herein) and other
indebtedness;
our ability to ensure that our plants operate safely and effectively;
expectations regarding maintenance and capital expenditures;
our belief that it is probable that insurance proceeds will cover the estimated plant write-down for the
damage to the Cadillac project; and
the impact of legislative, regulatory, competitive and technological changes.
Such forward-looking statements reflect our current expectations regarding future events and operating
performance and speak only as of the date of this Annual Report on Form 10-K. Such forward-looking statements are
based on a number of assumptions which may prove to be incorrect, including, but not limited to the assumption that the
projects will operate and perform in accordance with our expectations. Many of these risks and uncertainties can affect
our actual results and could cause our actual results to differ materially from those expressed or implied in any
forward-looking statement made by us or on our behalf.
Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of
future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by
which such performance or results will be achieved. In addition, a number of factors could cause actual results to differ
materially from the results discussed in the forward-looking statements, including, but not limited to, the factors included
in the filings Atlantic Power makes from time to time with the SEC and the risk factors described under “Item 1A. Risk
Factors” in this Annual Report on Form 10-K. Our business is both highly competitive and subject to various risks.
1
These risks include, without limitation:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the expiration or termination of PPAs and our ability to renew or enter into new PPAs on favorable terms
or at all;
the dependence of our projects on their electricity and thermal energy customers;
exposure of certain of our projects to fluctuations in the price of electricity or natural gas;
the dependence of our projects on third-party suppliers;
projects not operating according to plan;
risks inherent in the use of derivative instruments;
the effects of weather, which affects demand for electricity and fuel as well as operating conditions;
revenues from hydropower plants are highly dependent on precipitation and associated weather events;
the adequacy of our insurance coverage, the timeliness of our insurance payouts, and our estimates of
insurance coverage;
risks beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of
war, natural disasters, pandemics (including potentially in relation to the coronavirus) or other catastrophic
events;
increased competition, including for acquisitions;
our limited control over the operation of certain minority-owned projects;
transfer restrictions on our equity interests in certain projects;
the impact of hostile cyber intrusions;
labor disruptions;
our pension plan may require additional future contributions;
our ability to retain, motivate and recruit executives and other key employees;
the impact of significant energy, environmental and other regulations on our projects;
noncompliance with federal reliability standards may subject us and our projects to penalties;
additional regulatory requirements mandating limitations on greenhouse gas emissions or requiring
efficiency improvements;
the impact of Canadian and U.S. federal income tax laws on our business;
the impact of our failure to comply with the U.S. Foreign Corrupt Practices Act and/or Canadian
Corruption of Foreign Public Officials Act;
the impact of failure to fully comply with Section 404 of the Sarbanes-Oxley Act of 2002;
2
•
•
•
•
•
•
•
•
our ability to service our debt obligations or generate sufficient cash flow to pay preferred dividends;
our indebtedness and financing arrangements and the terms, covenants and restrictions included in our
Credit Facilities;
the discontinuation, reform or replacement of LIBOR;
exchange rate fluctuations;
the impact of downgrades in our credit rating or the credit rating of our outstanding debt securities, and
changes in our creditworthiness;
our ability to access liquidity for the ongoing operation of our business and the execution of our business
plan or any potential options, which may involve one or more of the use of cash on hand, the issuance of
additional corporate debt or equity securities and the incurrence of privately-placed bank or institutional
non-recourse operating level debt;
unstable capital and credit markets;
the anti-takeover protections in the British Columbia Business Corporations Act (the “BCBCA”) and our
Articles of Continuance;
• U.S., Canadian, and/or global economic uncertainty;
•
•
the impact of impairment of goodwill, long-lived assets or equity method investments; and
increasing competition.
Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the
forward-looking information include, without limitation, third-party projections of regional fuel and electric capacity and
energy prices based on assumptions about future economic conditions and courses of action, the general conditions of
the markets in which the Company operates, revenues, internal and external growth opportunities, the Company’s ability
to sell assets at favorable prices or at all and general financial market and interest rate conditions. Although the
forward-looking statements contained in this Annual Report on Form 10-K are based upon what are believed to be
reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking
statements, and the differences may be material. Certain statements included in this Annual Report on Form 10-K may
be considered “financial outlook” for the purposes of applicable securities laws, and such financial outlook may not be
appropriate for purposes other than this Annual Report on Form 10-K. These forward-looking statements are made as of
the date of this Annual Report on Form 10-K and, except as expressly required by applicable law, we assume no
obligation to update or revise them to reflect new events or circumstances.
3
ITEM 1. BUSINESS
GENERAL
Atlantic Power, a corporation continued under the laws of British Columbia, Canada is an independent power
producer that owns power generation assets in eleven states in the United States and two provinces in Canada. We were
incorporated in 2004. Our power generation projects, which are diversified by geography, fuel type, dispatch profile and
offtaker, sell electricity to utilities and other large customers predominantly under long-term PPAs, which seek to
minimize exposure to changes in commodity prices. As of December 31, 2019, our portfolio consisted of twenty-one
operating projects with an aggregate electric generating capacity of approximately 1,723 megawatts (“MW”) on a gross
ownership basis and approximately 1,327 MW on a net ownership basis. Sixteen of the projects are majority-owned by
the Company.
The following charts show, based on generation capacity in MW, the diversification of our portfolio by
geography and fuel type for our projects currently in operation:
Ontario, Canada
8%
BC, Canada
9%
Western
United
States
37%
Eastern
United
States
46%
Natural
Gas
66%
Biomass
16%
Coal
8%
Hydro
10%
We sell the majority of the capacity and energy from our power generation projects under PPAs to a variety of
utilities and other parties. Under the PPAs, which have expiration dates ranging from May 2020 to November 2043, we
receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for
electric generation capacity (known as capacity payments). We also sell steam from a number of our projects to
industrial purchasers under steam sales agreements. Sales of electricity are generally higher during the summer and
winter months, when temperature extremes create demand for either summer cooling or winter heating.
We directly operate and maintain the majority of our power generation projects. We also partner with
recognized leaders in the independent power industry to operate and maintain our other projects, including CMS Energy
Corporation (“CMS”), Heorot Power Management LLC (“Heorot”) and Purenergy LLC (“Purenergy”). Under these
operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance
and repair services.
BUSINESS STRATEGY
Our primary business is the acquisition, operation and ownership of power plants in the United States and
Canada. The power generation business is cyclical, capital-intensive, heavily regulated and commodity-priced. In
executing our strategy, we are focused on the following priorities:
• Debt reduction: We have reduced our consolidated debt by more than $1.2 billion in the past six years. By
significantly repaying debt, we have strengthened our balance sheet, improved our financial flexibility and
reduced our cash interest payments. We also have improved our credit profile, as reflected in two rating
upgrades over the past four-plus years from each of S&P and Moody’s. We expect to continue reducing debt
and improving our leverage ratio over the next several years. Debt reduction is not driven by the returns
available on our debt, but rather the priority of strengthening our balance sheet. We believe this is prudent given
4
the nature of our business, our asset profile and the state of the power markets.
• Capital allocation framework: We are focused on enhancing shareholder value while balancing risk and
reward. The key metric that we consider is the impact of capital allocation on our estimates of intrinsic value
per share. Developing these estimates is a complex process that relies on inherently uncertain forecasts of
power prices, market prices for assets, interest rates and other major factors outside of our control. We use these
estimates to provide us a rough guideline on how we can best impact intrinsic value per share via capital
allocation. Over the past five years we have invested discretionary capital in internal investments in our fleet,
external acquisitions and repurchases of debt, common and preferred securities.
•
Internal investments and share repurchases - Given the challenging supply and demand conditions in
the power sector in the United States and Canada, low returns currently available on contracted power
assets, and the superior returns that generally have been available on our internal uses of capital, we
have allocated the majority of our discretionary capital to investments in our fleet and share
repurchases. We invested $25 million to optimize our existing fleet in 2013 through 2016 and realized
attractive returns, but see less need for such investments at present. We have returned cash to
shareholders via common share repurchases, as we do not believe reinstating a common dividend
would be consistent with the characteristics of our business model or current market conditions. Our
key consideration in share repurchases (either common or preferred) is the price-to-value relationship.
We are willing to buy shares when doing so is accretive to our estimates of intrinsic value per share.
We are not interested in buying common shares above our estimates of intrinsic value per share. We
have repurchased preferred shares when we believed the cash returns were attractive.
• External investments - We invest externally only when we believe the returns are superior to those we
can achieve by investing internally in plants or in share repurchases. In 2018 and 2019, we made our
first significant external investments in more than five years, totaling approximately $45 million.
• Cost management: As we lack barriers to entry, we are keenly focused on efficiency and costs. Our existing
fleet is, on average, comprised of older, smaller and less efficient plants, which limits our ability to achieve
operating cost reductions. We have reduced our corporate overhead structure significantly and continue to
maintain a culture of frugality.
• Culture: We are laser focused on shareholder value. Being a good corporate citizen underpins that focus but we
also do not want to force our personal political views onto our employees or shareholders. In a commodity
business, operating our plants safely and staying focused on costs are paramount. In all aspects of our business,
we strive to follow a philosophy of servant leadership.
• Balanced portfolio: We have a balanced portfolio of technologies and fuel types including natural gas, biomass
and hydro, and we own an equity interest in one coal plant. This balance creates some hedging characteristics.
Higher gas prices ought to be beneficial for hydro plants but not necessarily for gas plants, for example.
• PPA renewals: We seek to renew or extend expiring PPAs where economically feasible, or make alternative
arrangements where possible. PPAs in our portfolio have expiration dates ranging from May 2020 to November
2043. We plan for PPA expirations by evaluating various options in the market. New arrangements may involve
responses to utility solicitations for capacity and energy, direct negotiations with the original purchasing utility
for PPA extensions, approaches by the projects to likely bilateral counterparties, including traditional PPAs,
tolling agreements with creditworthy energy trading firms or the use of derivatives to lock in value. The current
market for PPAs is challenging. When a PPA expires or is terminated, it is possible that the price received by
the project for power under subsequent arrangements, if any, may be reduced and in some cases, significantly.
We do not assume that revenues or operating margins under existing PPAs will necessarily be sustained after
PPA expirations, since most original PPAs included capacity payments related to return of and return on
original capital invested, and counterparties or evolving regional electricity markets may or may not provide
similar payments under new or extended PPAs. Our projects may not be able to secure a new agreement and
could be exposed to selling power at spot market prices. It is possible that subsequent PPAs or the spot markets
5
may not be available at prices that permit the operation of the project on a profitable basis, which may result in
our decision to mothball or retire the project. For the status of description of some of our PPAs and related
renegotiations, see Item 1A. “Risk Factors—Risks Related to Our Business—The expiration or termination of
our PPAs could have a material adverse impact on our business, results of operations and financial condition.”
ASSET MANAGEMENT
Our asset management strategy is to manage our physical assets and commercial relationships with the goal of
increasing shareholder value. We proactively seek scale opportunities and to establish best practices that result in
EBITDA and cash flow growth across all of our twenty-one operating plants. Our asset management group works to
ensure that our projects receive appropriate preventative and corrective maintenance and incur capital expenditures to
provide for their safety, efficiency, availability, flexibility, longevity, and growth in EBITDA contribution. We also
proactively look for opportunities to optimize power purchase, fuel supply, long-term service and other agreements to
deliver strong and predictable financial performance. The teams at each of the businesses have extensive experience in
managing, operating and maintaining the assets.
For operations and maintenance services at the five projects in our portfolio which we do not operate, we
partner with experienced operators in the independent power business. Examples of our third-party operators include
CMS, Heorot and Purenergy, which are experienced, well regarded energy infrastructure management services
companies. In addition, employees of Atlantic Power with significant experience managing similar assets are involved in
all significant decisions with the objective of proactively identifying value-creating opportunities such as contract
renewals or restructurings, asset-level refinancings, add-on acquisitions, divestitures and participation at partnership
meetings and calls.
INDUSTRY AND COMPETITION
The electric power industry is one of the largest industries in the United States, generating annualized retail
electricity sales of approximately $380 billion, based on information published by the Energy Information
Administration. A significant portion of the power produced in the United States and Canada is generated by non-utility
generators. According to the Energy Information Administration, independent power producers represented
approximately 40% of total net generation in 2019. Independent power producers sell the electricity that they generate to
electric utilities and other load-serving entities (such as municipalities and electric cooperatives) by way of bilateral
contracts or open power exchanges. The electric utilities and other load-serving entities, in turn, generally sell this
electricity to industrial, commercial and residential customers. In the independent power generation sector, electricity is
generated from a number of energy sources, including natural gas, coal, water, waste products such as biomass
(e.g., wood, wood waste, agricultural waste), landfill gas, geothermal, solar and wind. All of our plants are non-utility
electric generating facilities in the North American electrical power generation industry.
The power generation industry is characterized by intense competition, and we compete with utilities, industrial
companies, yieldcos and other independent power producers. Historically low crude oil and natural gas prices as well as
decreased rates of demand growth have contributed to reduced capacity and energy prices and increasing competition
among generators to obtain power sales agreements. We also compete for acquisition and joint-venture opportunities
with numerous private equity, infrastructure and pension funds, Canadian and U.S. independent power firms, utility
non-regulated subsidiaries and other strategic and financial players.
Our competitive strengths
We believe we have the following competitive strengths:
• Diversified projects. Our power generation projects in operation or under contract have an aggregate gross
electric generation capacity of approximately 1,723 MW, and our net ownership interest in these projects is
approximately 1,327 MW at December 31, 2019. These projects are diversified by fuel type, electricity and
steam customers, technologies, project operators and geography. The majority are located in the U.S.
6
Eastern, Mid-Atlantic and Midwest regions, and in Canada in the provinces of British Columbia and
Ontario.
• Experienced management team. Our management team has a depth of experience in commercial power
operations and maintenance, project development, asset management, mergers and acquisitions, capital
raising and management and financial controls.
• Stability of project cash flow. Many of our power generation projects currently in operation have been in
operation for more than ten years. Cash flows from each project are generally supported by PPAs with
investment-grade utilities and other creditworthy counterparties. We aim to stabilize operating margins
through a combination of a project’s PPAs, fuel supply agreements and/or commodity hedges, when
possible.
• Strong in-house operations and asset management teams. We manage the operations of sixteen of our
twenty-one operating power generation projects, which represent approximately 62% of our portfolio’s
total net generating capacity. The remaining five generation projects are operated by third parties, which
are recognized leaders in the independent power business.
OUR ORGANIZATION AND SEGMENTS
The following tables outline by segment our portfolio of power generating assets in operation as of
December 31, 2019, including our interest in each facility. We believe our portfolio is well diversified in terms of
electricity and steam customers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating
exposure to market, regulatory or environmental conditions specific to any single region.
We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our
reportable business segments in the fourth quarter of 2019 as the result of recent asset acquisitions, PPA expirations and
project decommissioning, and in order to align with changes to management’s structure, resource allocation and
performance assessment in making decisions regarding our operations. Segment information for prior periods has been
revised to conform to the new segment presentation. The segment classified as Corporate (formally Un-Allocated
Corporate) includes activities that support the executive and administrative offices, capital structure and costs of being a
public registrant. These costs are not allocated to the operating segments when determining segment profit or loss. We
have previously reported our segments on a geographic basis, and consequently the segment information presented
herein is significantly different than previous presentations of segment information.
The sections below provide descriptions of our projects as they are aligned in our segment reporting structure
for financial reporting purposes.
Solid Fuel Segment
Our Solid Fuel segment accounted for approximately 29%, 30% and 22% of consolidated revenue in 2019,
2018 and 2017, respectively, and total net generation capacity of 376 MW at December 31, 2019. Set forth below is a list
of our Solid Fuel projects in operation at December 31, 2019:
7
Project
Location
Fuel
MW Interest
MW
Primary Electric Purchasers
Gross Economic Net
Power
Contract
Expiry
Customer
Credit
Rating
(S&P)(1)
Allendale
Cadillac
Calstock
Chambers(2)
South Carolina
Michigan
Ontario
New Jersey
Biomass
Biomass
Biomass
Coal
20
40
35
262
100.00 %
100.00 %
100.00 %
40.00 %
Craven(2)
Dorchester
Grayling(2)
Piedmont
Williams Lake
North Carolina
South Carolina
Michigan
Georgia
British Columbia
Biomass
Biomass
Biomass
Biomass
Biomass
48
20
37
55
66
50.00 %
100.00 %
30.00 %
100.00 %
100.00 %
20
40
35
89
16
24
20
11
55
66
South Carolina Public Service Authority
Consumers Energy
Ontario Electricity Financial Corporation
Atlantic City Electric (3)
Chemours Co.
Duke Energy Carolinas, LLC
South Carolina Public Service Authority
Consumers Energy
Georgia Power
BC Hydro
November 2043
June 2028
June 2020
March 2024
March 2024
December 2027
October 2043
December 2027
September 2032
September 2029
A
A-
A+
A-
BB-
A-
A
A-
A-
AAA
(1) Customers that have assigned ratings at the top end of the range have, in the opinion of Standard and Poor’s
(“S&P”), the strongest capability for payment of debt or payment of claims, while customers at the bottom end of
the range have the weakest capacity. Agency ratings are subject to change, and there can be no assurance that a
ratings agency will continue to rate the customers, and/or maintain their current ratings. A security rating may be
subject to revision or withdrawal at any time by the rating agency, and each rating should be evaluated
independently of any other rating. We cannot predict the effect that a change in the ratings of the customers will
have on their liquidity or their ability to pay their debts or other obligations.
(2) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated
affiliates.
(3) The base PPA with Atlantic City Electric (“ACE”) makes up the majority of the revenue from the 89 Net MW. For
sales of energy and capacity not purchased by ACE under the base PPA and sold to the spot market, profits are
shared with ACE under a separate power sales agreement.
Natural Gas Segment
Our Natural Gas segment accounted for approximately 47%, 49% and 64% of consolidated revenue in 2019,
2018 and 2017, respectively, and total net generation capacity of 822 MW at December 31, 2019. Set forth below is a list
of our Natural Gas projects in operation at December 31, 2019:
Project
Frederickson(2)
Kenilworth
Manchief (3)
Morris (4)
Nipigon
Orlando(2)
Oxnard
Tunis
Location
Washington
Fuel
Natural Gas
Gross Economic Net
MW Interest
250
29
300
177
40
129
49
37
50.15 %
MW
50
45
30
100.00 %
29
100.00 % 300
100.00 % 100
77
40
65
49
37
100.00 %
50.00 %
100.00 %
100.00 %
Primary Electric Purchasers
Benton Co. PUD
Grays Harbor PUD
Franklin Co. PUD
Merck & Co., Inc.
Public Service Company of Colorado
Merchant
Equistar Chemicals, LP (5)
Independent Electricity System Operator
Progress Energy Florida
Southern California Edison
Independent Electricity System Operator
New Jersey
Colorado
Illinois
Natural Gas
Natural Gas
Natural Gas
Ontario
Florida
California
Ontario
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Power
Contract
Expiry
August 2022
August 2022
August 2022
September 2021
April 2022
N/A
December 2034
December 2022
December 2023
May 2020
October 2033
Customer
Credit
Rating
(S&P)(1)
AA-
A+
A+
AA
A-
NR
BBB+ (6)
AA-
A-
BBB
AA-
(1) Customers that have assigned ratings at the top end of the range have, in the opinion of S&P, the strongest capability
for payment of debt or payment of claims, while customers at the bottom end of the range have the weakest
capacity. Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to
rate the customers, and/or maintain their current ratings. A security rating may be subject to revision or withdrawal
at any time by the rating agency, and each rating should be evaluated independently of any other rating. We cannot
predict the effect that a change in the ratings of the customers will have on their liquidity or their ability to pay their
debts or other obligations.
8
(2) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated
affiliates.
(3)
In May 2019, we entered into an agreement to sell Manchief to PSCo following the expiration of the PPA in April
2022 for $45.2 million subject to working capital and other customary adjustments.
(4) Equistar has an option to purchase Morris that is exercisable in December 2020 and in December 2027.
(5) Equistar has the right under the PPA to take up to 77 MW, but on average has taken approximately 50 MW.
(6) Represents the credit rating of LyondellBasell, the parent company of Equistar Chemicals, as Equistar is not rated.
Non-operating Natural Gas Plants
In August 2018, we terminated discussions with the Navy regarding site control for our Naval Station, Naval
Training Center (“NTC”) and North Island projects located in San Diego, California. We are in the process of
decommissioning all three sites, which is a requirement of our land use agreements with the Navy.
Our Kapuskasing and North Bay projects are both 40 MW natural gas plants located in the Province of Ontario.
These projects formerly had PPAs with the OEFC that expired in December 2017. These plants are currently being
maintained, but do not operate because they do not have PPAs or a merchant market where operations would be
profitable.
Hydroelectric Segment
Our Hydroelectric Segment accounted for approximately 24%, 21% and 14% of consolidated revenue in 2019,
2018 and 2017, respectively, and total net generation capacity for operational projects of 129 MW at December 31,
2019. Set forth below is a list of our Hydroelectric projects in operation or under contract at December 31, 2019:
Project
Curtis Palmer
Koma Kulshan
Mamquam (3)
Moresby Lake
Location
New York
Washington
British Columbia
British Columbia
Net
Fuel MW Interest MW Primary Electric Purchasers
Gross Economic
Hydro
Hydro
Hydro
Hydro
60
13
50
6
100.00 %
100.00 %
100.00 %
100.00 %
60
13
50
6
Niagara Mohawk Power Corporation
Puget Sound Energy
BC Hydro
BC Hydro
Power
Contract
Expiry
December 2027 (2)
March 2037
September 2027
August 2022
Customer
Credit
Rating
(S&P)(1)
A-
BBB
AAA
AAA
(1) Customers that have assigned ratings at the top end of the range have, in the opinion of S&P, the strongest capability
for payment of debt or payment of claims, while customers at the bottom end of the range have the weakest
capacity. Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to
rate the customers, and/or maintain their current ratings. A security rating may be subject to revision or withdrawal
at any time by the rating agency, and each rating should be evaluated independently of any other rating. We cannot
predict the effect that a change in the ratings of the customers will have on their liquidity or their ability to pay their
debts or other obligations.
(2) The Curtis Palmer PPA expires at the earlier of December 2027 or the provision of 10,000 GWh of generation.
From January 6, 1995 through December 31, 2019, the facility has generated 8,060 GWh under its PPA. Based on
cumulative generation to date, we expect the PPA to expire prior to December 2027.
(3) BC Hydro has an option to purchase Mamquam that is exercisable in November 2021 and every five-year
anniversary thereafter.
9
REGULATORY MATTERS
Overview
Our facilities and operations are subject to laws and regulations that govern, among other things, transactions
by and with purchasers of power, including utility companies, the development and construction of generation facilities,
the ownership and operations of generation facilities, access to transmission, and the geographical location, zoning, land
use and operation aspects of our facilities and properties, including environmental matters.
In the United States, the power generation and sale aspects of our projects are primarily regulated by the
Federal Energy Regulatory Commission (“FERC”), although most of our projects benefit from the special provisions
accorded to Qualifying Facilities (“QFs”) or Exempt Wholesale Generators (“EWGs”).
In Canada, electricity generation is subject primarily to provincial regulation. Our projects in British Columbia
are therefore subject to different regulatory regimes from our projects in Ontario.
Generating projects
United States
Thirteen of our power generating projects are QFs under the Public Utility Regulatory Policies Act of 1978, as
amended (“PURPA”), and FERC regulations. A QF falls into one or both of two primary classes, both of which would
facilitate one of PURPA’s goals to more efficiently use fossil fuels to generate electricity than typical utility plants. The
first class of QFs includes energy producers that generate power using renewable energy sources such as wind, solar,
geothermal, hydro, biomass or waste fuels. The second class of QFs includes cogeneration facilities, which must meet
specific fossil fuel efficiency requirements by producing both electricity and steam versus electricity only.
The generating projects with QF status are currently party to a PPA with a utility or have been granted authority
to charge market-based rates or are exempt from FERC rate-making authority. The FERC has granted thirteen of the
projects the authority to charge market-based rates based primarily on a finding that the projects lack market power. The
projects with QF status are also exempt from state regulation respecting the rates of electric utilities and the financial or
organizational regulation of electric utilities. However, state regulators may review the prudency of utilities entering into
PPAs with QFs and the siting of the generation facilities. The majority of our generation is sold by QFs under PPAs that
required approval by state authorities.
PURPA, as initially implemented by the FERC, generally required that vertically integrated electric utilities
purchase power from QFs at their avoided costs. The Energy Policy Act of 2005 (the “EP Act of 2005”), however,
established new limits on PURPA’s requirement that electric utilities buy electricity from QFs to certain markets that
lack competitive characteristics. The projects with EWG status are also exempt from state regulation respecting the rates
of electric utilities.
Notwithstanding their status as QFs and EWGs, our projects remain subject to various aspects of FERC
regulation, including those relating to power marketer status and to oversight of mergers, acquisitions and investments
relating to utilities under the Federal Power Act, as amended by the EP Act of 2005. Nine of our projects are also subject
to reliability standards developed and enforced by the North American Electric Reliability Corporation (“NERC”).
NERC is a not-for-profit regulatory authority whose mission is to assure the reliability and security of the bulk power
system in North America.
Pursuant to its authority, NERC has issued, and the FERC has approved, a series of mandatory reliability
standards. Users, owners and operators of the bulk power system can be penalized significantly for failing to comply
with the FERC-approved reliability standards. We have designated our Manager of Operational and Regulatory
Compliance to oversee compliance with reliability standards and an outside law firm specializing in this area advises us
on FERC and NERC compliance, including annual compliance training for relevant employees.
10
British Columbia, Canada
The vast majority of British Columbia’s power is generated or procured by BC Hydro, which is one of the
largest electric utilities in Canada. BC Hydro is owned by the Province of British Columbia and is regulated by the
British Columbia Utilities Commission (the “BCUC”), which is governed by the Utilities Commission Act (British
Columbia) (the “UCA”). The BCUC is also responsible for the regulation of British Columbia’s public energy utilities
including publicly-owned and investor-owned utilities (i.e., independent power producers).
BC Hydro is generally required to acquire all new power (beyond what it already generates from existing BC
Hydro plants) from independent power producers.
All contracts for electricity supply, including those between independent power producers and BC Hydro, must
be filed with and approved by the BCUC. In making its determination, the BCUC will examine whether the contract is
in the public interest. The BCUC may hold a hearing in this regard. Furthermore, the BCUC may make rules governing
conditions to be contained in agreements entered into by public utilities for electricity.
Pursuant to the UCA, the BCUC has adopted the standards developed by the NERC and the Western Electricity
Coordinating Council (“WECC”) in respect to all generators of electricity in British Columbia, including independent
power producers. As a practical matter, the BCUC appointed WECC as Administrator to assist the BCUC in carrying out
the registration of parties and compliance monitoring.
The Clean Energy Act (the “Clean Energy Act”), which became law in 2010, sets out British Columbia’s
energy objectives. The Clean Energy Act states, among other things, that British Columbia aims to accelerate and
expand the development of clean and renewable energy sources in British Columbia to, among other things, promote
economic development and job creation and continue to work toward the reduction of greenhouse gas emissions. The
legislation also explicitly states that British Columbia will encourage the use of waste heat, biogas and biomass to reduce
waste. Clean Energy Production in B.C.: An inter-Agency Guidebook for Project Development, which was released by
the provincial government in 2016, is consistent with the Clean Energy Act, favors clean and renewable energy sources
such as waterpower, windpower and ocean energy generation.
Other provincial regulators in British Columbia having authority over independent power producers include the
British Columbia Safety Authority, the Ministry of Environment and Climate Change Strategy, and the Integrated Land
Management Bureau.
Ontario, Canada
In Ontario, the Ontario Energy Board (“OEB”) is an administrative tribunal with overall responsibility for the
regulation and supervision of the natural gas and electricity industries in Ontario and with the authority to grant or
renew, and set the terms for, licenses with respect to electricity generation facilities, including our projects.
No person is permitted to own or operate large or medium-scale electricity generation facilities in Ontario
without a license from the OEB.
The OEB’s general functions include:
• Determination of the rates charged for regulated services in the electricity sector;
• Licensing of market participants;
•
Inspections, particularly with respect to compelling production of records and information;
• Market monitoring and reporting, including on anti-competitive practice;
• Consumer advocacy; and
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• Enforcement and compliance.
The OEB has the authority effectively to modify licenses by adopting “codes” that are deemed to form part of
the licenses. Furthermore, any violations of the license or other irregularities in the relationship with the OEB can result
in administrative monetary penalties of up to Cdn$1 million per day of violation, license revocation and other
consequences. While the OEB provides reports to the Ontario Minister of Energy, it generally operates independently
from the government. However, the Minister may issue policy directives (with Cabinet approval) concerning general
policy and the objectives to be pursued by the OEB, and the OEB is required to implement such policy directives. The
law implemented by the OEB has been the subject of relatively frequent change, including in 2019, which has
contributed to regulatory uncertainty.
A number of other regulators and quasi-governmental entities play a role in electricity regulation in Ontario,
including the Independent Electricity System Operator (“IESO”), Hydro One, the Electrical Safety Authority (“ESA”)
and the Ontario Electricity Financial Corporation (“OEFC”).
In 1998, the Legislative Assembly of Ontario passed the Energy Competition Act of 1998, which authorized the
establishment of a market in electricity, and reorganized Ontario Hydro into five companies: Ontario Power Generation
(“OPG”), the Ontario Hydro Services Company (later renamed Hydro One), the Independent Electricity Market
Operator (later renamed the IESO), the ESA, and OEFC. The two commercial companies, Ontario Power Generation
and Hydro One, were intended to eventually operate as private businesses rather than as crown corporations. The
Province currently owns slightly less than half of the equity of Hydro One Inc., a publicly traded corporation. Hydro One
has been the subject of intervention by the Province, including pressuring the retirement of its former chief executive
officer and resignation of its entire board of directors.
The IESO is responsible for administering the wholesale electricity market and controlling Ontario’s
transmission grid. The IESO is a non-profit corporation whose directors are appointed by the government of Ontario.
The IESO’s “Market Rules” form the regulatory framework for the operation of Ontario’s transmission grid and
electricity market. The Market Rules require, among other things, that generators meet certain equipment and
performance standards and certain system reliability obligations. The IESO may enforce the Market Rules by imposing
financial penalties. The IESO may also terminate, suspend or restrict participatory rights, and has an enforcement arm.
In November 2006, the IESO entered into a memorandum of understanding with NERC, in which it recognized
NERC as the “electricity reliability organization” in Ontario. In addition, the IESO has also entered into a similar MOU
with both the Northeast Power Coordinating Council (the “NPCC”) and NERC. The IESO is accountable to NERC and
NPCC for compliance with NERC and NPCC reliability standards. Although the IESO may impose Ontario-specific
reliability standards, such standards must be consistent with, and at least as stringent as, NERC’s and NPCC’s standards.
Effective July 1, 2016, the IESO changed the definition of what generating facilities are considered part of the Bulk
Electric System (“BES”). Any new facility grouped into the BES, which includes all Ontario sites except Kapuskasing,
will have to comply with all NERC reliability standards in effect in Ontario. As of January 1, 2015, the IESO is
responsible for procuring new electricity generation. As a result, the IESO enters into electricity generation contracts
with electricity generators in Ontario from time to time. The IESO also administers the Ontario Reliability Compliance
Program, working with various market participants to ensure they understand and adhere to their obligations.
Although the Green Energy Act became law in Ontario in 2009 for renewable electricity generation
technologies, including via a feed-in tariff program, this statute was repealed as of January 1, 2019 with the introduction
and proclamation of the Green Energy Repeal Act, 2018. This Act amended provisions of the Electricity Act, 1998, as
well as the Environmental Protection Act, and the Planning Act, among others. In particular, amendments to the
Environmental Protection Act now provide that, absent a demonstrated demand for the electricity which would be
generated by a given renewable energy project, the provincial government is empowered to prohibit the issuance or
renewal of energy approvals for any such project. Amendments to the Planning Act now stipulate that there is no appeal
route in respect of any refusal or failure to adopt an amendment authorizing a renewable energy undertaking, except by
the Minister. Further amendments provide that there is now no appeal route in respect of all or any part of an application
for amendment to a by-law if the amendment proposes to permit a renewable energy undertaking, except by the
Minister. The provincial government has stated that the repeal of the Green Energy Act will empower individual
12
municipalities to make planning decisions related to the development of new energy projects. In July of 2018, the
provincial government cancelled hundreds of renewable energy contracts in the province. In the related Minister’s
Directive, the Minister noted that the IESO’s recent system planning work “indicates that Ontario’s current contracted
and rate regulated electricity resources are sufficient to satisfy or exceed forecasted provincial needs for the near term
and that there are other means of meeting future energy supply and capacity needs at materially lower costs than long-
term contracts that lock in the prices paid for these resources.”
Carbon emissions
United States – regional and state
In the United States, during the past several years government actions addressing carbon emissions have
occurred primarily at the regional and state levels. Beginning in 2009, the Regional Greenhouse Gas Initiative (“RGGI”)
was established by certain Northeast and Mid-Atlantic states as the first cap-and-trade program in the United States for
CO2 emissions. CO2 allowances are now a tradable commodity in the RGGI states. The nine states currently
participating in RGGI have varied implementation plans and schedules. RGGI implemented a new, reduced CO2 cap in
2014, with further reductions of 2.5% each year from 2015 to 2020. On January 1, 2020, New Jersey rejoined RGGI
after withdrawing from the compact in 2012. Our Chambers project operates in the state of New Jersey and is subject to
RGGI. However, its PPA is grandfathered to provide some cost mitigation under the law. California’s cap-and-trade
program governing greenhouse gas emissions became effective for the electricity sector on January 1, 2013. California,
along with British Columbia, Nova Scotia and Quebec, is part of the Western Climate Initiative, which supports the
implementation of state and provincial greenhouse gas emissions trading programs. Other states and regions in the
United States have considered similar regulations, and it is possible that federal climate legislation will be established in
the future.
In 2006, the State of California passed legislation initiating two programs to control/reduce the creation of
greenhouse gases. The two laws are more commonly known as AB 32 (the Global Warming Solutions Act) and
SB 1368. In 2016, California enacted SB 32, which expanded the requirements of AB 32. Under AB 32 and SB 32, the
California Air Resources Board (the “CARB”) is required to adopt a greenhouse gas emissions cap on all major sources
(not limited to the electric sector) to achieve goals of reaching (i) 1990 greenhouse gas emissions levels by the year
2020, (ii) 40% below 1990 levels by 2030, and (iii) 80% below 1990 emissions levels by 2050. Under the CARB
regulations that took effect on January 1, 2013, electricity generators and certain other facilities are now subject to an
allowance for greenhouse gas emissions, with allowances allocated by both formulas set by the CARB and auctions.
SB 1368 added the requirement that the California Energy Commission, in consultation with the California
Public Utilities Commission (the “CPUC”) and the CARB, establish greenhouse gas emission performance standards
and implement regulations for PPAs with a term of five or more years entered into prospectively by publicly owned
electric utilities. The legislation directs the California Energy Commission to establish the performance standard as one
not exceeding the rate of greenhouse gas emitted per megawatt hour (“MWh”) associated with combined-cycle, gas
turbine baseload generation.
United States – Federal
Over the past several years, the U.S. Environmental Protection Agency (the “EPA”) has taken a number of
actions respecting CO2 emissions. The EPA’s actions include its December 2009 finding of “endangerment” to public
health and welfare from greenhouse gases, its issuance in September 2009 of the Final Mandatory Reporting of
Greenhouse Gases Rule which required large sources, including power plants, to monitor and report greenhouse gas
emissions to the EPA annually beginning in 2011, and its issuance in May 2010 of its final Prevention of Significant
Deterioration and Title V Greenhouse Gas Tailoring Rule, which under a phased-in approach requires large industrial
facilities, including power plants, to obtain permits to emit, and to use best available control technology to curb
emissions of, greenhouse gases. In addition, in August 2015, the EPA issued its final rule regulating carbon emissions
from existing electric generating units, which is referred to as the Clean Power Plan (the “CPP”). As a result of judicial
challenge, however, the CPP was not implemented. In June 2019, the EPA issued the final Affordable Clean Energy
Rule (“ACE”), which repealed the CPP and established emissions guidelines for states to develop plans to address
13
greenhouse gas emissions from existing coal-fired power plants. In December 2018, the EPA issued a proposed rule to
considerably ease the greenhouse gas standards for new power plants. Any such rulemaking activities could take years to
complete, and are likely to draw legal challenges. At this time, we cannot predict the outcome of any legal challenges to
future administrative actions.
Canada - Federal
In Canada, the federal government has implemented greenhouse gas reporting regulations and is developing
additional programs to address greenhouse gas emissions. Under the 2004 federal Greenhouse Gas Emissions Reporting
Program (“GHGRP”), all facilities which emit 50,000 tonnes or more of carbon dioxide equivalent (“CO2eq”) per year
are required to submit reports on their emissions to Environment Canada.
On October 3, 2016, the Government of Canada announced its proposed pan-Canadian approach for the
pricing of carbon pollution. On January 15, 2018, the Government of Canada released the draft Greenhouse Gas
Pollution Pricing Act, setting out the mechanics to be used to backstop the federal government’s pan-Canadian approach
to carbon pricing in provinces that have not implemented, by January 1, 2019, a carbon pricing system that the federal
government has determined complies with its carbon pricing requirements. It also included a proposed design of rules to
enhance market liquidity. In May 2018, the federal Government published “Carbon pricing: compliance options under
the federal output-based pricing system,” a document that describes the proposed rules, and on June 21, 2018 the
Greenhouse Gas Pollution Pricing Act went into effect. Since that time the federal government has published, on
October 31, 2018, SOR/2018-212, 213 and 214 (the “GHGPPA SOR”), to amend Schedule 1 to the Greenhouse Gas
Pollution Pricing Act, to establish criteria respecting facilities and persons, and to issue the greenhouse gas emissions
information production order.
British Columbia and Québec have compliant carbon pricing systems in place and are not expected to be subject
to the federal backstop regime. Alberta is exempt from parts of the federal backstop regime. Although at the beginning of
2017, Ontario had implemented a compliant cap and trade system, there was a change in the provincial government as a
result of the election held in June 2018. The newly elected Ontario government cancelled the cap and trade regulation and
prohibited all trading of emission allowances, effective as of July 3, 2018, and on October 31, 2018 formally repealed the
cap-and- trade legislation. As a result, our Ontario operations are now subject to the federal backstop regime. Under the
federal GHGPPA SOR, large industrial emitters, such as our operations in Tunis and Nipigon, are subject to the federal
output-based pricing system (“OBPS”) provided for in Part 2 of the Greenhouse Gas Pollution Pricing Act. As of
January 1, 2020, the federal backstop regime imposes a minimum Cdn$30/tonne of CO2e (“tCO2e”) carbon price for
greenhouse gases that exceed a prescribed emissions limit set out in the Output-Based Pricing System Regulations,
increasing by Cdn$10 increments each following year to 2022.
The validity of the federal backstop regime is being challenged on constitutional grounds by Alberta, Ontario
and Saskatchewan. Canada’s highest court, the Supreme Court of Canada, is scheduled to hear the provincial challenges
in the spring of 2020.
As of July 4, 2019, Ontario has also established its own output-based performance standards for large emitters
through Ontario Regulation 241/19: Greenhouse Gas Emissions Performance Standards (“GHGEPS”). The GHGEPS,
while optional for facilities covered under the federal GHGRP emitting between 10,000 and 50,000 tonnes of CO2e,
appears to be similar to the federal OBPS. The implications of the federal OBPS the GHGEPS for our operations in
Ontario, such as Tunis and Nipigon, is discussed below (in the section on Canada – Ontario).
Canada – British Columbia
The Government of British Columbia has enacted a number of significant pieces of climate action legislation
that frame British Columbia’s approach to reducing greenhouse gas emissions with the goal of supporting its
participation in the emerging low-carbon economy.
One key piece of legislation is the Greenhouse Gas Reduction Targets Act, which was re-enacted in November
2018 as the Climate Change Accountability Act (British Columbia) (“CCAA”), which sets legislated targets for the
14
reduction of greenhouse gas emissions in British Columbia. Using 2007 as a base year, CCAA (along with related
Ministerial Orders) requires that emissions must be reduced by a minimum of 40% by 2030, 60% by 2040 and 80% by
2050. Under the CCAA, by December 31, 2020, the province will be required to additionally specify a reduction target
for a year that is earlier than 2030. Also required in connection with CCAA are (from 2020 onward) British Columbia
Greenhouse Gas Inventory Reports (reports are prepared in even-numbered years and tables are updated in odd-
numbered years), Community Energy and Emissions Inventory Reports (prepared every two years) and Carbon Neutral
Action Reports (prepared annually), all of which are designed to provide scientific, comparable and consistent reporting
of greenhouse gas sources.
Other related, key pieces of legislation include the Carbon Tax Act (“CTA”) and the Greenhouse Gas Industrial
Reporting and Control Act (“GGIRCA”). CTA operates to put a price on greenhouse gas emissions, providing an
incentive for sustainable choices and practices by producers of greenhouse gases. GGIRCA came into force on
January 1, 2016 and combined several pieces of British Columbia’s existing greenhouse gas legislation into a single
legislative framework. It includes the ability to set a greenhouse gas emissions intensity benchmark for regulated
industries and enables the benchmark to be met through flexible options, such as purchasing offsets or paying a set price
per tonne of greenhouse gas emissions that would be dedicated to a technology fund. Three regulations necessary to
implement GGIRCA also came into force on January 1, 2016: the Greenhouse Gas Emission Reporting Regulation
(“GGERR”), the Greenhouse Gas Emission Administrative Penalties and Appeals Regulation (“GGEAPAR”) and the
Greenhouse Gas Emission Control Regulation (“GGECR”). GGERR establishes compliance reporting requirements and
ensures that industrial operations that emit more than 10,000 carbon dioxide equivalent tonnes per year report their
greenhouse gas pollution each year. GGEAPAR establishes the process for when, how much, and under what conditions
administrative penalties may be levied for non-compliance with GGIRCA or the regulations made under GGIRCA.
GGECR establishes the BC Carbon Registry and sets criteria for developing emission offsets issued by the provincial
government. GGECR also establishes the price for funded units issued under GGIRCA that would go towards a
technology fund. Regulated operations will purchase offsets from the market or funded units from government to meet
emission limits. Funded unit revenue that goes to a technology fund will also support the development of clean
technologies with significant potential to reduce British Columbia’s emissions over the long term.
Canada - Ontario
In a news release issued on June 15, 2018, Ontario Premier-designate Doug Ford announced that the first
act of his newly formed government would be to cancel Ontario’s cap and trade program (under the Climate
Change Mitigation and Low-carbon Economy Act, 2016). Effective as of July 3, 2018, the Ontario government
cancelled the cap and trade regulation and prohibited all trading of emissions allowances, and on October 31, 2018
formally repealed the Ontario cap-and-trade legislation. Bill 4: Cap and Trade Cancellation Act, 2018 (the legislation
which repealed the former cap-and-trade regime) retired or cancelled outstanding emissions allowances and strictly
limited the ability of those holding emissions allowances to bring claims seeking to recover for any damages suffered
as a result.
Under the previous cap-and-trade regime, facilities in Ontario with annual greenhouse gas emissions of
25,000 tonnes or more were generally required by law to participate in the regime by obtaining emissions allowances.
However, facilities which primarily generate electricity using natural gas from a local distributor were excluded from the
requirement to obtain emission allowances and instead participated in the program through the payment of the carbon
price charged by the local natural gas distributor on the natural gas delivered after the end of 2016. As a result, our
operations in Ontario were not holding emissions allowances when the Ontario cap and trade program was cancelled and
were not adversely affected by the cancellation of that regime.
As a result of the cancellation of the Ontario cap-and-trade regime, on January 1, 2019 our operations in
Nipigon and Tunis became subject to the federal OBP. Under the federal “Notice Establishing Criteria Respecting
Facilities and Persons and Publishing Measures: SOR/2018-213,” any facility which emitted more than 50kt of
CO2e during any of the 2014, 2015, 2016 or 2017 calendar years, and which carries out, as its primary activity, the
generation of electricity using fossil fuels, is a covered facility and subject to the OBPS. Since the Nipigon and
Tunis projects are each generating electricity using natural gas and each reported emissions in excess of 50kt of
CO2e for one of the 2014, 2015, 2016 or 2017 calendar years (119,248 tonnes for 2014 in the case of Tunis and
15
115,725 tonnes for 2016 in the case of Nipigon), each is considered a covered facility and subject to the federal
OBPS.
Our operations in Ontario may also be subject to Ontario’s GHGPE, if required to register. Under
Ontario’s GHGPE, facilities must register with the Director of the Ministry of the Environment, Conservation and
Parks if the facility is required to submit a report under the federal GHGRP and reported emissions of more than
50,000 tonnes of CO2e. Facilities may also choose to register if the facility submitted a report under the federal
GHGRP and emits between 10,000 and 50,000 tonnes of CO2e. Accordingly, our operations in Tunis and Nipigon
are also subject to Ontario’s GHGPE.
Under the federal OBPS regulations, the Tunis and Nipigon projects are required to either pay an excess
emissions charge or remit compliance units as prescribed by the federal backstop regime for each tonne of CO2e
emissions in excess of 370 tonnes of CO2e / GWh of electricity generated by such operations and will receive free
emissions allowances if the emissions fall below that measure. Facilities in Ontario subject to the GHGPE will be
required to pay a similar excess emissions charge or remit compliance units per tonne of CO2e emissions. The
details of arrangements for the possible recovery of these potential additional costs from the IESO will depend on
the terms of the applicable PPA.
Renewable Energy
More than half of the U.S. states and most Canadian provinces have set mandates requiring the achievement of
certain levels of renewable energy production and/or energy efficiency during target timeframes. This includes
generation from wind, solar and biomass, and/or renewable fuel mandates. For example, in 2011, California enacted a
law requiring retail sellers of electricity to deliver 33% of their customers’ electricity requirements from renewable
resources, as defined in the statute, by 2020. In 2015, California enacted SB 350, which increases the amount of
electricity from renewable resources that California retail sellers must deliver after 2020 to 40% of retail sales by
December 2024, 45% of retail sales by December 2027, and 50% of retail sales by December 2030. In order to meet CO2
reduction goals, changes in the generation fuel mix are forecasted to include a reduction in existing coal resources,
higher reliance on natural gas and renewable energy resources and an increase in demand-side resources. Investments in
new or upgraded transmission lines will be required to move increasing renewable generation from more remote
locations to load centers.
In December 2015, 195 countries participating in the United Nations Framework Convention on Climate
Change (“UNFCC”), at its 21st Conference of the Parties meeting (“COP21”) held in Paris, adopted a new global
agreement on the reduction of climate change (the “Paris Agreement”). The Paris Agreement became effective in
November 2016, after it had been ratified by a sufficient number of countries. The Paris Agreement sets a goal of
holding the increase in global average temperature to well below 2 degrees Celsius and pursuing efforts to limit the
increase to 1.5 degrees Celsius, to be achieved by aiming to reach a global peaking of greenhouse gas emissions as soon
as possible. The Paris Agreement consists of two elements: a legally binding commitment by each participating country
to set an emissions reduction target, referred to as “nationally determined contributions” or “NDCs,” with a review of the
NDCs that could lead to updates and enhancements every five years (Article 4) and a transparency commitment
requiring participating countries to disclose in full their progress (Article 13). As decided at the 24th Conference of the
Parties meeting in December 2020, countries are expected to submit updated NDCs in 2020. Accordingly, the Paris
Agreement may result in additional regulations to reduce carbon emissions in coming years.
Canada ratified the Paris Agreement, and submitted an NDC that included a 2030 target of 30% below 2005
levels. The United States also submitted an NDC, which called for reducing its net greenhouse gas emissions by 26-28%
below 2005 levels by 2025. However, in November 2019, the Trump Administration formally notified the United
Nations of the U.S. withdrawal from the Paris Agreement, to be effective in November 2020. In light of the legislative,
judicial and executive factors influencing regulatory action, significant uncertainty exists as to how greenhouse gas
restrictions in the United States will impact our facilities in the future.
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EMPLOYEES
As of February 26, 2020, we had 266 employees, 205 in the United States and 61 in Canada. Of our Canadian
employees, 43 are covered by collective bargaining agreements, which will expire on December 19, 2020 and
December 31, 2020. During 2019, we did not experience any labor stoppages or labor disputes at any of our facilities.
AVAILABLE INFORMATION
Access to our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K
and amendments to these reports filed with or furnished to the SEC may be obtained free of charge through the Investors
section of our website at https://investors.atlanticpower.com/corporate-profile as soon as is reasonably practical after we
electronically file or furnish these reports. In addition, our filings with the SEC may be accessed through the SEC’s
website at www.sec.gov and our filings with the Canadian Securities Administrators (CSA) may be accessed through the
CSA’s System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com. Except for the documents
specifically incorporated by reference into this Annual Report, information contained on our website or the SEC or CSA
websites is not incorporated by reference in the Annual Report on Form 10-K and should not be considered to be a part
of the Annual Report. Information contained on our website or that can be accessed through our website is not
incorporated into and does not constitute a part of this Annual Report on Form 10-K. We have included our website
address and that of the SEC and CSA only as inactive textual references and do not intend them to be active links to such
websites. All statements made in any of our securities filings, including all forward-looking statements or information,
are made as of the date of the document in which the statement is included, and we do not assume or undertake any
obligation to update any of those statements or documents unless we are required to do so by applicable law. We are not
a foreign private issuer, as defined in Rule 3b-4 under the Exchange Act.
ITEM 1A. RISK FACTORS
This section highlights specific risks that could affect our Company. You should carefully consider each of the
following risks and all of the other information set forth in this Annual Report on Form 10-K. Based on the information
currently known to us, we believe the following information identifies the most significant risk factors affecting our
Company. However, the risks and uncertainties described below are not the only ones related to our business and are
not necessarily listed in the order of their importance. Additional risks and uncertainties not presently known to us or
that we currently believe to be immaterial may also adversely affect our business, results of operations or financial
condition.
If any of the following risks and uncertainties develops into actual events or if the circumstances described in
the risks and uncertainties occur or continue to occur, these events or circumstances could have a material adverse
effect on our business, results of operations or financial condition. These events could also have a negative effect on the
trading price of our securities.
Risks Related to the Operation of Our Business
The expiration or termination of our PPAs could have a material adverse impact on our business, results of
operations and financial condition
Power generated by our projects, in most cases, is sold under PPAs that expire at various times. Currently, our
PPAs are scheduled to expire between May 2020 and November 2043. See Item 1. Business—Our Organization and
Segments for details about our projects’ PPAs and related expiration dates. In addition, these PPAs may be subject to
termination prior to expiration in certain circumstances, including default by the project. When a PPA expires or is
terminated, it may be difficult for us to secure a new PPA on acceptable terms or timing, if at all; the price received by
the project for power under subsequent arrangements may be reduced significantly, or there may be a delay in securing a
new PPA until a significant time after the expiration of the original PPA at the project. It is possible that subsequent
PPAs may not be available at prices that permit the operation of the project on a profitable basis. For example, our
Kapuskasing and North Bay projects formerly had PPAs with the OEFC that expired in December 2017. These plants
are currently being maintained, but do not operate because they do not have PPAs or a merchant market where
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operations would be profitable. When the affected project temporarily or permanently ceases operations, or when we
have an expectation that we will be unable to renew or renegotiate the PPA, the value of the project may be impaired
such that we would be required to record an impairment loss under applicable accounting rules. See “—Impairment of
goodwill, long lived assets or equity method investments could have a material adverse effect on our business, results of
operations and financial condition.”
Two of our projects, representing 6% of our operating net MW and 3% of our 2019 Project Adjusted EBITDA,
have PPAs or other contractual arrangements that will expire in 2020. These projects are Oxnard and Calstock. Another
seven of our other projects, representing 51% of our operating net MW and 52% of our 2019 Project Adjusted EBITDA,
have PPAs or other contractual arrangements that will expire within the next five years. These projects are Kenilworth
(2021), Manchief (2022), Frederickson (2022), Moresby Lake (2022), Nipigon (2022), Orlando (2023) and Chambers
(2024). In May 2019, we entered into an agreement to sell Manchief to Public Service Company of Colorado (“PSCo”)
following the expiration of the PPA in 2022.
Our projects depend on their electricity and thermal energy customers and there is no assurance that these customers
will perform their obligations or make required payments
Each of our projects relies on one or more PPAs, steam sales agreements or other agreements with one or more
utilities or other customers for a substantial portion of its revenue. At times, we rely on a single customer or a limited
number of customers to purchase all or a significant portion of a project’s output. In 2019, the largest customers of our
power generation projects, including projects recorded under the equity method of accounting, were Niagara Mohawk
Power Corporation, IESO, Equistar Chemicals L. P. and Georgia Power Company, which account for approximately
19.3%, 12.7%, 11.4% and 10.9%, respectively, of the consolidated revenue of our projects. If a customer stops
purchasing output from our power generation projects or purchases less power than anticipated, such customer may be
difficult to replace, if at all. Further concentration of our customers would increase our dependence on any one customer.
Our cash flows and results of operations, including the amount of cash available to make payments on our indebtedness,
are highly dependent upon customers under such agreements fulfilling their contractual obligations. There is no
assurance that these customers will perform their contractual obligations or make required payments.
Further, our customers generally have investment-grade credit ratings, as measured by S&P. Customers that
have assigned ratings at the top end of the range have, in the opinion of the rating agency, the strongest capability for
payment of debt or payment of claims, while customers at the bottom end of the range have the weakest capacity.
Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to rate the
customers, and/or maintain their current ratings. A security rating may be subject to revision or withdrawal at any time
by the rating agency, and each rating should be evaluated independently of any other rating. We cannot predict the effect
that a change in the ratings of the customers will have on their liquidity or their ability to pay their debts or other
obligations.
Certain of our projects are exposed to fluctuations in the price of electricity, which may have a material adverse effect
on the operating margin of these projects and on our business, results of operations and financial condition
PPAs that are based on spot market pricing for some or all of their output will be exposed to fluctuations in the
wholesale price of electricity. In addition, as PPAs expire or terminate, the relevant project will be required to either
negotiate a new PPA or sell into the electricity wholesale market, in which case the prices for electricity will depend on
market conditions at the time, which may not be favorable. The open market wholesale prices for electricity are very
volatile. Long and short-term power prices may fluctuate substantially due to other factors outside of our control,
including:
•
•
changes in generation capacity in the electricity markets, including the addition of new supplies of power
from existing competitors or new market entrants as a result of the development of new generation
facilities, expansion or retirement of existing facilities or additional transmission capacity;
electric supply disruptions, including plant outages and transmission disruptions;
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•
fuel transportation capacity constraints;
• weather conditions;
•
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•
•
•
•
•
•
•
•
changes in the demand for power or in patterns of power usage;
development of new fuels and new technologies for the production or storage of power;
development of new technologies for the production of natural gas;
availability of competitively priced renewable fuel sources;
available supplies of natural gas, crude oil and refined products, and coal;
interest rate and foreign exchange rate fluctuation;
availability and price of emission credits;
geopolitical concerns affecting global supply of oil and natural gas;
general economic conditions which impact energy consumption in areas where we operate; and
power market, fuel market and environmental regulation and legislation.
The market price for electricity is affected by changes in demand for electricity. Factors such as economic
slowdown, worse than expected economic conditions, milder than normal weather, the growth of energy efficiency and
efforts aimed at energy conservation, among others, could reduce energy demand or significantly slow the growth in
demand for electricity, thereby reducing the market price for electricity. A reduction in demand could contribute to
conditions that no longer support the continued operation of certain power generation projects, which could adversely
affect our results of operations through increased depreciation rates, impairment charges and accelerated future
decommissioning costs, among others.
Both our Chambers and Morris projects are contracted but have some exposure to market prices for power. At
Chambers, plant capacity is sold forward pursuant to the PPA with our utility customer but the project is economically
dispatched, which impacts variable operating margins. For example, during periods of low demand and low spot
electricity prices, the project is dispatched less, which reduces the project’s operating margin. In addition, the utility
customer has the right to sell a portion of the output into the spot market if it is economical to do so, and the Chambers
project shares in the profit from these sales. This also adds some variability to the project’s financial results.
At Morris, a portion of the capacity is contracted with the industrial customer through 2034. The remaining
capacity has been sold forward into the Pennsylvania New Jersey Maryland (“PJM”) capacity market through annual
auctions covering the period through May 2022. The capacity revenues from these auctions generally represent the
majority of the operating margin of the uncontracted portion of the project. Energy associated with the capacity sold
forward into the PJM market is generally dispatched by PJM when economic to do so or when needed for other reasons.
The project can also offer ancillary services to the grid. The sale of energy and ancillary services from the uncontracted
portion of the project is not at a fixed price or margin and therefore can add variability to the project’s financial results.
Our projects depend on third-party suppliers under fuel supply agreements, and increases in fuel costs may adversely
affect the results of operations of the projects
The amount of energy generated at the projects is highly dependent on suppliers under certain fuel supply
agreements fulfilling their contractual obligations. The loss of significant fuel supply agreements or an inability or
failure by any supplier to meet its contractual commitments may adversely affect our results.
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Upon the expiration or termination of existing fuel supply agreements, we or our project operators will have to
renegotiate these agreements or may need to source fuel from other suppliers. We may not be able to renegotiate these
agreements or enter into new agreements on similar terms. There can be no assurance as to availability of the supply or
pricing of fuel under new arrangements, and it can be very difficult to accurately predict the future prices of fuel. If our
suppliers are unable to perform their contractual obligations or we are unable to renegotiate our fuel supply agreements,
we may seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility
and the risk that fuel and transportation may not be available during certain periods at any price. Changes in market
prices for natural gas, biomass, coal and oil may result from the following:
• weather conditions;
•
•
•
•
•
•
•
•
•
•
seasonality;
demand for energy commodities and general economic conditions;
availability and price of emission credits;
additional generating capacity;
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
availability and levels of storage and inventory for fuel stocks;
natural gas, crude oil, refined products and coal production levels;
changes in market liquidity;
governmental regulation and legislation; and
our creditworthiness and liquidity, and the willingness of fuel suppliers/transporters to do business with us.
Revenues earned by our projects may be affected by the availability, or lack of availability, of a stable supply of
fuel at reasonable or predictable prices. The price we can obtain for the sale of energy may not rise at the same rate, or
may not rise at all, to match a rise in fuel or delivery costs. To the extent possible, our projects attempt to match fuel cost
setting mechanisms in supply agreements to energy payment formulas in the PPA and to provide for indexing or
pass-through of fuel costs to customers. In cases where there is no pass-through of fuel costs, we often attempt to
mitigate the market price risk of changing commodity costs through the use of hedging strategies. To the extent that
costs are not matched well to PPA energy payments, pass-through of fuel costs is not allowed or hedging strategies are
unsuccessful, increases in fuel costs may adversely affect our results of operation. This may have a material adverse
effect on our business, results of operations and financial condition.
Our projects may not operate as planned
The ability of our projects to meet availability requirements and generate the required amount of power to be
sold to customers under the PPAs are primary determinants of the amount of cash that will be distributed from the
projects to us, and that will in turn be available for debt service obligations, investments in internal or external growth
opportunities or funding of our operations. There is a risk of equipment failure due to wear and tear, more frequent
and/or larger than forecasted downtimes for equipment maintenance and repair, unexpected construction delays, latent
defect, design error or operator error, or force majeure events, among other things, which could adversely affect
revenues and cash flow. Additionally, older equipment, even if maintained in accordance with good practices, is subject
to operational failure, including events that are beyond our control, and may require unplanned expenditures to operate
efficiently. Unplanned outages of generation facilities, including extensions of scheduled outages due to mechanical
failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically
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increase our operation and maintenance expenses and may reduce our revenues or require us to incur significant costs as
a result of obtaining replacement power from third parties in the open market to satisfy our obligations.
In general, our power generation projects transmit electric power to the transmission grid for purchase under the
PPAs through a single step up transformer. As a result, the transformer represents a single point of vulnerability and may
exhibit no abnormal behavior in advance of a catastrophic failure that could cause a temporary shutdown of the facility
until a replacement transformer can be found or manufactured. To the extent that we suffer disruptions of plant
availability and power generation due to transformer failures or for any other reason, there could be a material adverse
effect on our business, results of operations and financial condition and the amount of available cash flow may be
adversely affected.
We provide letters of credit under our $200 million Revolver for contractual credit support at some of our
projects. If the projects fail to perform under the related project-level agreements, the letters of credit could be drawn and
we would be required to reimburse our senior lenders for the amounts drawn.
Our projects are exposed to risks inherent in the use of derivative instruments
We and our projects may use derivative instruments, including futures, forwards, options and swaps, to manage
commodity and financial market risks. These activities, though intended to mitigate price volatility, expose us to other
risks. In the future, the project operators could recognize financial losses on these arrangements, including as a result of
volatility in the market values of the underlying commodities, if a counterparty fails to perform under a contract or upon
the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear the
transactions. If actively quoted market prices and pricing information from external sources are not available, the
valuation of these contracts would involve judgment or use of estimates. As a result, changes in the underlying
assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Most of these contracts are recorded at fair value with changes in fair value recorded currently in the statement
of operations, resulting in significant volatility in our (loss) income (as calculated in accordance with GAAP) that does
not significantly affect current period cash flows or the underlying risk management purpose of the derivative
instruments. As a result, we may be unable to accurately predict the impact that our risk management decisions may
have on our quarterly and annual (loss) income (as calculated in accordance with GAAP).
If the values of these financial contracts change in a manner that we do not anticipate, or if a counterparty fails
to perform under a contract, it could harm our business, results of operations, financial condition and cash flows. We
have executed natural gas swaps to reduce our risks to changes in the market price of natural gas, which is the fuel
consumed at many of our projects. Due to decreases in natural gas prices, we have incurred losses on these natural gas
swaps. We execute these swaps only for the purpose of managing risks and not for speculative trading.
We do not typically hedge the entire exposure of our operations against commodity price volatility. To the
extent we do not hedge against commodity price volatility, our business, results of operations and financial condition
may be improved or diminished based upon movement in commodity prices.
The effects of weather and climate change may adversely impact our business, results of operations and financial
condition
Our operations are affected by weather conditions, which directly influence the demand for electricity and
natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to
increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to
increase winter heating electricity and gas demand and revenues. Conversely, moderate temperatures in winter or
summer decrease heating or cooling electricity and gas demand and revenues. To the extent that weather is warmer in
the summer or colder in the winter than assumed, we may require greater resources to meet our contractual
commitments. These conditions, which cannot be accurately predicted, may have an adverse effect on our business,
results of operations and financial condition by causing us to seek additional capacity at a time when wholesale markets
are tight or to seek to sell excess capacity at a time when markets are weak.
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Over the past several years, changing weather patterns and climatic conditions have added to the
unpredictability of weather-related events in certain parts of the world, including the markets in which we operate and
intend to operate, and have created additional uncertainty as to future trends. To the extent climate change contributes to
the frequency or intensity of weather-related events, our operations and planning process could be impacted, which may
adversely impact our business, results of operations and financial condition.
Revenues from hydropower projects are highly dependent on precipitation and associated weather conditions and in
the absence of such suitable conditions, our hydropower projects may not meet anticipated production levels, which
could adversely affect our forecasted revenues
We own interests in four hydropower projects, which are subject to substantial resource risks. The energy and
revenues generated at a hydro energy project are highly dependent on precipitation patterns, which are variable and
difficult to predict for any given year. We base our investment decisions with respect to each hydro energy project on the
historical stream flow records for the area. However, actual climatic conditions in any given year may not meet the
historical averages, which would impair our ability to meet anticipated production levels, which could adversely affect
our forecasted revenues.
Our business faces significant operating hazards and insurance may not be sufficient to cover all losses
Our business involves significant operating hazards related to the generation of electricity, including hazards
related to acquiring, transporting and unloading fuel, operating large pieces of rotating equipment, structural collapse,
machinery failure, and delivering electricity to transmission and distribution systems. The occurrence of any one of these
events may result in our being subject to various litigation matters, including regulatory and administrative proceedings,
asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property
damage and fines and/or penalties. While we believe that the projects maintain an amount of insurance coverage that is
adequate and similar to what would be maintained by a prudent owner/operator of similar facilities, and are subject to
deductibles, limits and exclusions which are customary or reasonable given the cost of procuring insurance, current
operating conditions and insurance market conditions, there can be no assurance that such insurance will continue to be
offered on an economically feasible basis, nor that all events that could give rise to a loss or liability are insurable or
insured, nor that the amounts of insurance will at all times be sufficient to cover each and every loss or claim that may
occur involving our assets or operations of our projects. Any losses in excess of those covered by insurance, which may
include a significant judgment against any project or project operator, the loss of a significant permit or other approval or
the imposition of a significant fine or penalty, could have a material adverse effect on our business, results of operations
and financial condition.
Risks that are beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of
war, natural disasters, pandemics (including potentially in relation to the coronavirus) or other catastrophic events
could have a material adverse effect on our business, results of operations, ability to raise capital and financial
condition
Man-made events, such as acts of terror and governmental responses to acts of terror, could adversely affect
general economic conditions, which could have a material impact on our business, results of operations and financial
condition. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other
domestic targets. Our projects may be targets of terrorist activities, as well as events occurring in response to or in
connection with them, that could cause environmental repercussions and/or result in full or partial disruption of the
ability of the projects to generate and/or transmit electricity.
Our projects may be affected by pandemics (including potentially in relation to the coronavirus). Any such
environmental repercussions or other disruption could result in a decline in energy consumption and significant decrease
in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our
business, results of operations and financial condition.
Our projects could also be impacted by natural disasters, such as earthquakes, floods, lightning activity,
hurricanes, tropical storms, winter storms, tornadoes, wind, seismic activity, more frequent and more extreme weather
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events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise
and other related phenomena. Severe weather or other natural disasters could be destructive or otherwise disrupt our
operations or compromise the physical or cyber security of our facilities, which could result in increased costs and could
adversely affect our ability to manage our business effectively. We maintain standard insurance against catastrophic
losses, which are subject to deductibles, limits and exclusions; however, our insurance coverage may not be sufficient to
cover all of our losses. Additionally, future significant weather-related events, natural disasters and other similar events
that have an adverse effect on the economy could have a material adverse effect on our business, results of operations,
ability to raise capital and financial condition. These and other hazards can cause significant personal injury or loss of
life, severe damage to and destruction of property, plant and equipment, disruption of communication systems and
technology, contamination of, or damage to, the environment and suspension of operations.
We may face significant competition for acquisitions and may not be able to finance or otherwise pursue, execute or
successfully integrate acquisitions or new business initiatives
The North American power industry is continuing to undergo consolidation and may present attractive
investment opportunities, but we are likely to confront significant competition for those opportunities and, to the extent
that any opportunities are identified, we may be unable to effect acquisitions or investments. A payout of a significant
portion of our cash flow to service our debt obligations may result in us not retaining a sufficient amount of cash to
finance any acquisition or other growth opportunities, to the extent any such acquisition or other opportunities are
available to us. As a result, we may have to forego such opportunities, even if they would otherwise be necessary or
desirable, if we do not find alternative sources of financing for such opportunities to make cash available to us. In
addition, even if we are able to find alternative sources of financing for such opportunities, we may be precluded from
pursuing an otherwise attractive acquisition or investment if the projected short-term cash flow from the acquisition or
investment is not adequate to service the capital raised to fund such acquisition or investment. This could limit our
flexibility in planning for, or reacting to, changes in our business and industry, placing us at a competitive disadvantage
compared to our competitors.
Any acquisition, investment or new business initiative may involve potential risks, including an increase in
indebtedness, the inability to successfully integrate operations, the potential disruption of our ongoing business, the
diversion of management’s attention from other business concerns, inadequate return on capital and the possibility that
we pay more than the acquired company or interest is worth. There may also be liabilities that we fail to discover, or are
unable to discover, in our due diligence prior to the consummation of an acquisition or prior to launching an initiative or
entering a market. We may not be indemnified for some or all of these liabilities in an acquisition transaction.
We have limited control over management decisions at certain projects
Five of our projects are not wholly-owned by us or we have contracted for their operations and maintenance,
and in some cases we have limited control over the operation of the projects. Although we generally prefer to acquire
projects where we have control, we may make acquisitions in non-control situations to the extent that we consider it
advantageous to do so and consistent with regulatory requirements and restrictions, including the Investment Company
Act of 1940, as amended. Third-party operators operate five of our projects. As such, we must rely on the technical and
management expertise of these third-party operators, although typically we negotiate to obtain positions on a
management or operating committee if we do not own 100% of a project. To the extent that such third-party operators do
not fulfill their obligations to manage the operations of the projects or are not effective in doing so, our cash flow may be
adversely affected. The approval of third-party operators also may be required for us to receive distributions of funds
from projects or to transfer our interest in projects. Our inability to control fully certain projects could have an adverse
effect on our business, results of operations and financial condition.
Our equity interests in certain projects may be subject to transfer restrictions
The partnership or other agreements governing some of the projects may limit a partner’s ability to sell its
interest. Specifically, these agreements may prohibit any sale, pledge, transfer, assignment or other conveyance of the
interest in a project without the consent of the other partners. In some cases, other partners may have rights of first offer
or rights of first refusal in the event of a proposed sale or transfer of our interest. These restrictions may limit or prevent
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us from managing our interests in these projects in the manner we see fit, and may have an adverse effect on our ability
to sell our interests in these projects at the prices we desire.
Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidential information,
damage our reputation and otherwise have an adverse effect on our business, results of operations and financial
condition
From time to time, we, like others in our industry, are subject to cyber intrusions in which customer data and
proprietary business information is targeted. A cyber intrusion is considered to be any adverse event that threatens the
confidentiality, integrity or availability of our information resources. More specifically, a cyber intrusion is an
intentional attack or an unintentional event that can include gaining unauthorized access to systems to disrupt operations,
corrupt data, steal confidential information, and impact our ability to make collections or otherwise impact our
operations. We are dependent on various information technologies throughout our company and our projects to carry out
multiple business activities. Further, the computer systems that run our facilities are not completely isolated from
external networks. Parties that wish to disrupt the U.S. and/or Canadian bulk power system or our operations could view
our computer systems, software or networks as attractive targets for cyber attack. In addition, our business requires that
we collect and maintain confidential employee and shareholder information, which is subject to the risk of electronic
theft or loss.
A successful cyber attack, such as unauthorized access, malicious software or other violations on the systems
that control generation and transmission at our projects could severely disrupt business operations, diminish competitive
advantages through reputation damages and increase operational costs. The breach of certain business systems could
affect our ability to correctly record, process and report financial information. A major cyber incident could result in
significant expenses to investigate and repair security breaches or system damage and could lead to litigation, adverse
regulatory action, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. For these
reasons, a significant cyber incident could materially and adversely affect our business, results of operations and
financial condition.
Certain employees are subject to collective bargaining
A number of our plant employees, at one plant in British Columbia and at two plants in Ontario, are subject to
collective bargaining agreements which will expire on December 19, 2020 and December 31, 2020, respectively. We
may not be able to renew them without a labor disruption or without agreeing to significant increases in labor costs.
Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could
have a material adverse effect on our business, results of operations and financial condition.
Our Pension Plan may require additional future contributions
Certain of our employees in Canada are participants in a defined benefit pension plan that we sponsor. The
additional amount of future contributions to our defined benefit plan will depend upon asset returns and a number of
other factors and, as a result, the amounts we will be required to contribute in the future may vary. Cash contributions to
the plan will reduce the cash available for our business.
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Our success depends in part on our ability to retain, motivate and recruit executives and other key employees, and
failure to do so could negatively affect us
Our success depends in part on our ability to retain, recruit and motivate key employees who have experience in
our industry. Experienced employees in the power industry are in high demand and competition for their talents can be
intense. Further, an aging work force in the power industry necessitates recruiting, retaining and developing the next
generation of leadership. A failure to attract and retain executives and other key employees with specialized knowledge
in power generation could have an adverse impact on our business, results of operations and financial condition because
of the difficulty of promptly finding qualified replacements.
Risks Related to Governmental Regulation and Laws
Our operations are subject to the provisions of various energy laws and regulations
Our business is subject to extensive Canadian and U.S. federal, state, provincial and local laws and regulations.
Compliance with the requirements under these various regimes may cause us to incur significant additional costs, and
failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of
liens, fines and/or civil or criminal liability.
Generally, in the United States, our projects are subject to regulation by the FERC regarding the terms and
conditions of wholesale service and rates, as well as by state regulators regarding the prudency of utilities entering into
PPAs entered into by QF projects and the siting of the generation facilities. The majority of our generation is sold by QF
projects under PPAs that required approval by state authorities.
The EP Act of 2005 also limited the requirement that electric utilities buy electricity from QFs in certain
markets that have certain competitive characteristics, potentially making it more difficult for our current and future
projects to negotiate favorable PPAs with these utilities.
If any project were to lose its status as a QF, it would lose its ability to make sales to utilities on favorable
terms. Such project may no longer be entitled to exemption from provisions of the Public Utility Holding Company Act
of 2005 or from certain provisions of the Federal Power Act and state law and regulations. Loss of QF status could also
trigger defaults under covenants to maintain that status in the PPAs and project-level debt agreements, and if not cured
within allowed cure periods, could result in termination of agreements, penalties or acceleration of indebtedness under
such agreements. In such event, our business, results of operations and financial condition could be negatively impacted.
Notwithstanding their status as QFs and EWGs, our facilities remain subject to numerous FERC regulations,
including those relating to power marketer status, approval of mergers, acquisitions and investments relating to utilities,
and mandatory reliability rules and regulations delegated to NERC. Any violation of these rules and regulations could
subject us to significant fines and penalties and negatively impact our business, results of operations and financial
condition.
The EP Act of 2005 and other federal and state programs also may provide incentives for various forms of
electric generation technologies, which may subsidize our competitors. The U.S. regulatory environment has undergone
significant changes in the last several years due to state and federal policies affecting wholesale competition and the
creation of incentives for the addition of large amounts of new renewable energy generation and, in some cases,
transmission. These changes are ongoing and we cannot predict the future design of the wholesale power markets or the
ultimate effect that the changing regulatory environment will have on our business. In addition, in some of these
markets, interested parties have proposed material market design changes, including the elimination of a single clearing
price mechanism as well as proposals to re-regulate the markets. Other proposals to re-regulate may be made and
legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation
process. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, or new law or
other future regulatory developments are introduced, our business, results of operations and financial condition could be
negatively impacted.
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Generally, in Canada, our projects are subject to energy regulation primarily by the relevant provincial
authorities. In addition, our projects are subject to Canada’s corporate, commercial and other laws of general application
to businesses. Our projects require licenses, permits and approvals which can be in addition to any required
environmental permits. No assurance can be provided that we will be able to obtain, comply with and renew, as required,
all necessary licenses, permits and approvals for these facilities. If we cannot comply with and renew as required all
applicable licenses, permits and approvals, our business, results of operations and financial condition could be adversely
affected.
The introductions of new laws, or other future regulatory developments, may have a material adverse impact on
our business, operations or financial condition.
Risks with respect to the two Canadian provinces where we currently have projects are addressed further below.
British Columbia
The Government of British Columbia has a number of specific statutes and regulations that govern the
generation, transmission and distribution of electricity within British Columbia. Our projects in that province are subject
to these laws. These statutes can be changed by act of the provincial legislature and the regulations may be changed by
the provincial cabinet. Such changes could have a material effect on our projects.
The Utilities Commission Act governs the BCUC, which is responsible for the regulation of British Columbia’s
public energy utilities, which include publicly-owned and investor-owned utilities (i.e., independent power producers).
All contracts for electricity supply, including those between independent power producers and BC Hydro, must be filed
with and approved by the BCUC as being “in the public interest.” The BCUC may hold a hearing in this regard.
Furthermore, the BCUC may make rules governing conditions to be contained in agreements entered into by public
utilities for electricity. Consequently, power procurement is controlled by the BCUC and, as a result, our potential
contracts with BC Hydro may be subject to terms that adversely affect us.
The Clean Energy Act sets out British Columbia’s energy objectives, one of which is the generation of at least
93% of the electricity in British Columbia from clean or renewable resources. BC Hydro is required to submit for review
and approval every five years to the Government of British Columbia resource plans outlining how it will meet these
objectives. BC Hydro is generally required to acquire all new power (beyond what it already generates from existing BC
Hydro plants) from independent power producers. Two of our three British Columbia projects currently sell all of their
electricity to BC Hydro, and the third project sells substantially all of its electricity to BC Hydro. Therefore, changes to
BC Hydro’s energy procurement policies and financial difficulties of or regulatory intervention in respect of BC Hydro
and/or the province’s energy objectives could impact the market for electricity generated by our British Columbia
projects, although BC Hydro is currently limited by regulation to undertaking efficiency improvements at its existing
facilities and undertaking development of new generation facilities/projects only with BCUC approval. There is a risk
that the regulatory regime could adversely affect the amount of power that BC Hydro purchases from our projects and
the competitive environment or the price at which BC Hydro is willing to purchase power from our British Columbia
projects.
Ontario
The government of Ontario has a number of specific statutes and regulations that govern our projects in that
province. The statutes can be changed by act of the provincial legislature and the regulations may be changed by the
provincial cabinet. Such changes could have a material effect on our projects.
In Ontario, the OEB is an administrative tribunal with authority to grant or renew, and set the terms for, licenses
with respect to electricity generation facilities, including our projects. No person is permitted to own or operate a large or
medium-scale electricity generation facility in Ontario without a license from the OEB. Although all of our Ontario
projects are currently licensed, the OEB has the authority to effectively modify the licenses by adopting “codes” that are
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deemed to form part of the licenses. Furthermore, any violations of the license or other irregularities in the relationship
with the OEB can result in fines.
Although the OEB provides reports to the Ontario Minister of Energy, it generally operates independently from
the government. However, the Minister may issue policy directives (with Cabinet approval) concerning general policy
and the objectives to be pursued by the OEB, and the OEB is required to implement such policy directives. Thus, the
OEB’s regulation of our projects is subject to potential political interference, to a degree.
A number of other regulators and quasi-governmental entities play a role, including the IESO, Hydro One, the
ESA and OEFC. All these agencies may affect our projects.
As discussed above in Item 1. “Business-Regulatory Matters,” in 2018, the Ontario provincial government
cancelled hundreds of renewable energy projects which had previously received approval, and has introduced or
amended legislation which will have an impact on the development of new renewable energy projects.
Noncompliance with federal reliability standards may subject us and our projects to penalties
Many of our operations are subject to the regulations of NERC, a self-regulatory non-governmental
organization which has statutory responsibility to regulate bulk power system users and generation and transmission
owners and operators. NERC groups the users, owners, and operators of the bulk power system into 17 categories,
known as functional entities—e.g., Generator Owner, Generator Operator, Purchasing-Selling Entity, etc.—according to
the tasks they perform. The NERC Compliance Registry lists the entities responsible for complying with federal
mandatory reliability standards and the FERC, NERC, or a regional reliability organization may assess penalties against
any responsible entity found to be in noncompliance. Violations may be discovered or identified through
self-certification, compliance audits, spot checking, self-reporting, compliance investigations by NERC (or a regional
reliability organization) and the FERC, periodic data submissions, exception reporting, and complaints. The penalty that
could be imposed for violating the requirements of the standards is a function of the Violation Risk Factor. Penalties for
the most severe violations can reach as high as $1 million per violation, per day, and our projects could be exposed to
these penalties if violations occur, which could have a material adverse effect on our business, results of operations and
financial condition.
Our projects are subject to significant environmental and other regulations
Our projects are subject to numerous and significant federal, state, provincial and local laws, including statutes,
regulations, by-laws, guidelines, policies, directives, permits, approvals, licenses, registrations and other requirements
governing or relating to, among other things: air emissions; discharges into water; ash disposal; the storage, handling,
use, transportation and distribution of dangerous goods and hazardous, residual and other regulated materials, such as
chemicals; the prevention of releases of hazardous materials into the environment; the prevention, presence and
remediation of hazardous materials in soil and groundwater, both on and off site; land use and zoning matters; and
workers’ health and safety matters. Our facilities could experience incidents, malfunctions or other unplanned events that
could result in spills or emissions in excess of permitted levels and result in personal injury, penalties and property
damage. As such, the operation of our projects carries an inherent risk of environmental, health and safety liabilities
(including potential civil actions, at common law and pursuant to statutory rights of compensation, compliance or
remediation orders, fines and other penalties), and may result in the projects being involved from time to time in
administrative and judicial proceedings relating to such matters. We have implemented environmental, health and safety
management programs designed to regularly improve environmental, health and safety performance, but there is no
guarantee that such programs will fully and effectively eliminate the inherent risk of environmental, health and safety
liabilities related to the operation of our projects.
Significant costs may be incurred for either capital expenditures or the purchase of allowances under any or all
of these programs to keep the projects compliant with environmental laws and regulations. Some of our projects’ PPAs
do not allow for the pass-through of emissions allowance or emission reduction capital expenditure costs. If it is not
economical to make those expenditures, it may be necessary to retire or mothball facilities, or restrict or modify our
operations to comply with more stringent standards.
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Our projects have obtained environmental permits and other approvals that are required for their operations.
Compliance with applicable environmental laws, regulations, permits and approvals and material future changes to them
could materially impact our businesses. Although we believe the operations of the projects are currently in material
compliance with applicable environmental laws, licenses, permits and other authorizations required for the operation of
the projects, and although there are environmental monitoring and reporting systems in place with respect to all the
projects, there is no guarantee that more stringent laws will not be imposed, that there will not be more stringent
enforcement of applicable laws or that such systems may not fail, which may result in material expenditures. Failure by
the projects to comply with any environmental, health or safety requirements, or increases in the cost of such
compliance, including as a result of unanticipated liabilities or expenditures for investigation, assessment, remediation or
prevention, or mandated regulatory reserves, could result in additional expense, capital expenditures, restrictions and
delays in the projects’ activities, the extent of which cannot be predicted and which could have a material adverse effect
on our business, results of operations and financial condition.
If additional regulatory requirements are imposed on energy companies mandating limitations on greenhouse gas
emissions or requiring efficiency improvements, such requirements may result in compliance costs that alone or in
combination could make some of our projects uneconomical to maintain or operate
The EPA, other regulatory agencies, environmental advocacy groups and other organizations are focusing
considerable attention on greenhouse gas emissions from power generation facilities and their potential role in climate
change. See “Item 1. Business—Industry Regulation—Carbon Emissions.”
There are also potential impacts on our natural gas businesses as legislation or regulations may require
greenhouse gas emission reductions from the natural gas sector, which could affect demand for natural gas. Additionally,
greenhouse gas requirements could result in increased demand for energy conservation and renewable products, as well
as increase competition surrounding such innovation. Additionally, our reputation could be damaged due to public
perception surrounding greenhouse gas emissions at our power generation projects. Any such negative public perception
could ultimately result in a decreased demand for electric power generation or distribution. Several regions of the United
States and Canada have moved forward with greenhouse gas emission regulation.
Concerning our projects in British Columbia, regulatory restrictions stemming from GGIRCA, CCAA, and
financial commitments arising in connection with the requirements under the CTA, could affect our ability to operate our
projects in British Columbia and affect the results of our operations. Concerning our projects in Ontario, the federal
OBPS, from the beginning of 2019, increased the cost of generating electricity using natural gas and the price of the
electricity produced by our natural gas-powered projects in the Province. In addition, on December 15, 2016, the IESO
entered into an electricity trade agreement with Hydro-Québec under which the IESO will purchase a total of 14 terawatt
hours (TWh) of electricity from Hydro-Québec over a seven-year period from 2017 to 2023. The News Release issued
by the Government of Ontario regarding this agreement stated that “Ontario will reduce the cost to its consumers by
$70 million compared to its previous plan by importing 2 TWh of hydroelectric power each year from Québec to replace
the use of natural gas.” We anticipate that the increasing carbon price and other initiatives to reduce greenhouse gas
emissions associated with the generation of electricity in the Province could affect our ability to operate our projects in
Ontario and affect the results of our operations.
All of our subject generating facilities have complied on a timely basis with the new EPA and applicable
Canadian greenhouse gas reporting requirements. Compliance with greenhouse gas emission reduction requirements
may require increasing the energy efficiency of equipment at our natural gas projects, purchase of allowances and/or
offsets, fuel switching, and/or retirement of high-emitting projects and potential replacement with lower-emitting
projects. The cost of compliance with greenhouse gas emission legislation and/or regulation is subject to significant
uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the
implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and
commercialization of carbon capture and storage technology, the selected compliance alternatives and in the United
States the actions taken by the Trump Administration to revoke Obama era climate regulations. We cannot estimate the
aggregate effect of such requirements on our business, results of operations, financial condition or our customers.
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However, such expenditures, if material, could make our generation facilities uneconomical to operate, result in the
impairment of assets, or otherwise adversely affect our business, results of operations and financial condition.
We are subject to Canadian tax
As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes, and
dividends paid by us are generally subject to Canadian withholding tax if paid to a shareholder that is not a resident of
Canada. We hold promissory notes from our U.S. holding companies (the “Intercompany Notes”) and are required to
include, in computing our taxable income, interest on the Intercompany Notes. In addition, we are required to include in
computing our taxable income any income earned by the Partnership. Atlantic Power Preferred Equity Ltd., a subsidiary
of the Partnership, is also a Canadian corporation and is generally subject to Canadian federal, provincial and other
taxes.
Canadian federal income tax laws and policies could be changed in a manner which adversely affects holders of our
common shares
There can be no assurance that Canadian federal income tax laws and Canada Revenue Agency administrative
policies respecting the Canadian federal income tax consequences generally applicable to us, to our subsidiaries, or to a
U.S. or Canadian holder of common shares will not be changed in a manner which adversely affects holders of our
common shares.
Our common shares may not continue to be qualified investments under Canadian tax laws
There can be no assurance that our common shares will continue to be qualified investments under relevant
Canadian tax laws for trusts governed by registered retirement savings plans, registered retirement income funds,
deferred profit sharing plans, registered education savings plans, registered disability savings plans and tax-free savings
accounts. Canadian tax laws impose penalties for the acquisition or holding of non-qualified or ineligible investments.
Our current structure may be subject to additional U.S. federal income tax liability
Under our current structure, our subsidiaries that are incorporated in the United States are subject to U.S.
federal income tax on their income at regular corporate rates (currently as high as 21%, plus state and local taxes), and
two of our U.S. holding companies will claim interest deductions with respect to the Intercompany Notes in computing
their income for U.S. federal income tax purposes. To the extent any interest expense under the Intercompany Notes is
disallowed or is otherwise not deductible, the U.S. federal income tax liability of our U.S. holding companies will
increase, which could affect the after-tax cash available to distribute to us.
We received advice from our U.S. tax counsel at the time of the issuance, based on certain representations by us
and our U.S. holding companies and determinations made by our independent advisors, as applicable, that the
Intercompany Notes should be treated as debt for U.S. federal income tax purposes. However, it is possible that the
Internal Revenue Service (the “IRS”) could successfully challenge these positions and assert that any of these
arrangements should be treated as equity rather than debt for U.S. federal income tax purposes or that the interest on
such arrangements is otherwise not deductible. In this case, the otherwise deductible interest would be treated as
non-deductible distributions and, in the case of the Intercompany Notes, may be subject to U.S. withholding tax to the
extent our respective U.S. holding company had current or accumulated earnings and profits. The determination of debt
or equity treatment for U.S. federal income tax purposes is based on an analysis of the facts and circumstances. There is
no clear statutory definition of debt for U.S. federal income tax purposes, and its characterization is governed by
principles developed in case law, which analyze numerous factors that are intended to identify the nature of the
purported creditor’s interest in the borrower.
Not all courts have applied this analysis in the same manner, and some courts have placed more emphasis on
certain factors than other courts have. To the extent it were ultimately determined that our interest expense on the
Intercompany Notes were disallowed, our U.S. federal income tax liability for the applicable open tax years would
materially increase, which could materially affect the after-tax cash available to us to distribute. Alternatively, the IRS
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could argue that the interest on the Intercompany Notes exceeded or exceeds an arm’s length rate, in which case only the
portion of the interest expense that does not exceed an arm’s length rate may be deductible and the remainder may be
subject to U.S. withholding tax to the extent our U.S. holding companies had current or accumulated earnings and
profits. We have received advice from independent advisors that the interest rate on these debt instruments was and is, as
applicable, commercially reasonable under the circumstances, but the advice is not binding on the IRS.
Furthermore, our U.S. holding companies’ deductions attributable to the interest expense on the Intercompany
Notes may be limited by the amount by which each U.S. holding company’s net interest expense (the interest paid by
each U.S. holding company on all debt, including the Intercompany Notes, less its interest income) exceeds 30% of its
adjusted taxable income (generally, U.S. federal taxable income before net interest expense, net operating loss
carryovers, and, for tax years beginning before January 1, 2022, depreciation and amortization). Any disallowed interest
expense may currently be carried forward to future years. In addition, if our U.S. holding companies do not make regular
interest payments as required under these debt agreements, other limitations on the deductibility of interest under U.S.
federal income tax laws could apply to defer and/or eliminate all or a portion of the interest deduction that our U.S.
holding companies would otherwise be entitled to.
In addition, recently enacted U.S. tax legislation made significant changes to the U.S. federal income tax rules
applicable to our activities in the United States. Although the tax legislation enacted on December 22, 2017 reduced the
federal corporate income tax rate from 35% to 21%, it also added additional limitations on deductions attributable to
interest expense (discussed in the preceding paragraph) and introduced “base erosion” rules that may effectively limit the
tax deductibility of certain payments made by U.S. entities to non-U.S. affiliates. We evaluated the full effect of this
legislation on our business and operations and currently believe that the interest expense limitation and base erosion and
anti-abuse tax will not have a material impact on cash taxes in future tax years.
Our U.S. holding companies have existing net operating loss carryforwards that we can utilize to offset future
taxable income. Some of these loss carryforwards are subject to an annual limitation on their use. Although we expect
these losses will be available to us as a future benefit, in the event that they are successfully challenged by the IRS or
subject to additional future limitations, including, but not limited to, as a result of implementation of any of the potential
options we are considering, our ability to realize these benefits may be limited. Although not expected, a reduction in our
net operating losses, or additional limitations on our ability to use such losses, may result in a material increase in our
future income tax liability.
Failure to comply with the U.S. Foreign Corrupt Practices Act and/or the Canadian Corruption of Foreign Public
Officials Act could subject us to, among other things, penalties and legal expenses that could harm our reputation
and have a material adverse effect on our business, results of operations and financial condition
We are subject to anti-corruption laws and regulations including the U.S. Foreign Corrupt Practices Act
(“FCPA”) and the Canadian Corruption of Foreign Public Officials Act (the “CFPOA”), which generally prohibit
companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or
keeping business and/or other benefits. In addition, the FCPA imposes accounting standards and requirements on U.S.
publicly traded corporations and their foreign affiliates, which are intended to prevent the diversion of corporate funds to
the payment of bribes and other improper payments, and to prevent the establishment of “off books” slush funds from
which improper payments can be made (similar provisions have been proposed to be added to the CFPOA). The
Securities and Exchange Commission has increased its enforcement of the FCPA during the past several years. In recent
years, enforcement of the CFPOA in Canada has also increased and can be attributed, in part, to the establishment of the
Royal Canadian Mounted Police’s International Anti-Corruption Unit in 2008. Although we have implemented policies
and procedures designed to ensure that we, our employees and other intermediaries comply with the FCPA and/or the
CFPOA, there is no assurance that such policies or procedures will work effectively all of the time or protect us against
liability under the FCPA and/or the CFPOA for actions taken by our employees, agents and other intermediaries with
respect to our business or any businesses that we may acquire. If we are not in compliance with the FCPA and/or the
CFPOA, we may be subject to criminal penalties pursuant to the CFPOA and/or criminal and civil penalties and other
remedial measures pursuant to the FCPA, including changes or enhancements to our procedures, policies and control, as
well as potential personnel change and disciplinary actions, which could have an adverse impact on our business, results
of operations and financial condition.
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Failure to fully comply with Section 404 of the Sarbanes-Oxley Act of 2002 could negatively affect our business,
market confidence in our reported financial information, and the price of our common shares.
We continue to document, test, and monitor our internal controls over financial reporting in order to satisfy all
of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002; however, we cannot be assured that our
disclosure controls and procedures and our internal control over financial reporting will prove to be completely adequate
in the future. Failure to fully comply with Section 404 of the Sarbanes-Oxley Act of 2002 could negatively affect our
business, market confidence in our reported financial information, and the price of our common shares.
Risks Related to our Financial Position and Economic and Financial Market Conditions
We may not generate sufficient cash flow to service our debt obligations or implement our business plan, including
financing internal or external growth opportunities
We continue to focus on executing our business plan, including the objectives of enhancing the value of our
existing assets through discretionary capital investments and commercial activities, delevering our balance sheet to
improve our cost of capital and ability to compete for new investments, improving our cost structure and reducing
overhead. However, we may not generate sufficient cash flow to service our debt obligations or implement our business
plan, including financing internal or external growth opportunities.
Our ability to make required payments under our outstanding indebtedness, as well as meeting the greater of the
requirements of the 50% cash sweep or the targeted debt balance under the terms of our Credit Agreement (defined
below), or to prepay or redeem any such indebtedness, will depend on our financial and operating performance,
including our ability to generate cash flow from operations in the future. As a result, we may be required to refinance
such indebtedness and/or obtain third-party financing in order to repay, redeem or refinance such indebtedness when it
comes due, or secure amendments or waivers. There can be no assurance that our business will generate sufficient cash
flow from operations or that future borrowings or refinancing opportunities will be available to us at an acceptable cost,
in amounts sufficient, or at all, to enable us to service our debt obligations or to repay or redeem any such indebtedness
at maturity, particularly because of our high levels of debt and the debt incurrence restrictions imposed by the various
agreements governing our indebtedness, or that we will succeed in obtaining amendments or waivers. Steps taken to
refinance our indebtedness or obtain other third-party financing, if any, may not be successful and may not permit us to
meet our scheduled debt service obligations, which could have a material adverse effect on our liquidity and financial
condition.
In addition, a payout of a significant portion of our cash flow to service our debt, including pursuant to the
mandatory amortization feature of the Credit Facilities, or to pay dividends on our preferred shares, may result in us not
retaining a sufficient amount of cash to finance growth and reinvestment opportunities through the acquisition of
additional projects, to the extent any such acquisitions are otherwise available to us. As a result, we may have to forego
growth and reinvestment opportunities that would otherwise be desirable, if we do not find alternative sources of
financing for such opportunities. In addition, even if we are able to find alternative sources of financing for such
opportunities, we may be precluded from pursuing an otherwise attractive acquisition or investment if the projected
short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund such
acquisition or investment. This could also limit our flexibility in planning for, reacting to, or in responding to economic
downturns or changes in our business and industry, placing us at a competitive disadvantage compared to our
competitors. We cannot provide any assurance that we will be able to identify, finance or close any transactions
associated with any such growth or reinvestment opportunities on acceptable terms or timing, or at all.
Further, if we are unable to generate sufficient cash flow from operations, our ability to support our liquidity
needs, including, but not limited to, servicing our debt obligations, including pursuant to the mandatory amortization
feature of the Credit Facilities, or financing internal or external growth opportunities, will depend on our ability to access
the credit and capital markets, neither of which may be available to us on acceptable terms, or at all. Further, access to
the credit and capital markets and the cost and availability of credit may be adversely affected by factors beyond our
control, including turmoil in the financial services industry, volatility in securities trading markets and general economic
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conditions. We cannot provide any assurance that we will be able to access the credit or capital markets on acceptable
terms or timing, or at all.
Our Credit Facilities contain certain terms, covenants and restrictions that could impact our available cash flow and
restrict our ability to make acquisitions or investments or issue additional indebtedness
Our Credit Facilities contain certain terms, covenants and restrictions, including a mandatory amortization
feature and customary prepayment provisions. Such terms, covenants and restrictions may impact our available cash
flow and limit our ability to retain sufficient amounts of cash to service our debt obligations or finance internal or
external growth opportunities. Our Credit Facilities are a primary source of our liquidity. See “Management’s Discussion
and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
The covenants under the Credit Facilities include a requirement that APLP Holdings Limited Partnership
(“APLP Holdings”) and its subsidiaries maintain certain leverage and interest coverage ratios (each, as defined in the
credit agreement governing the Credit Facilities (the “Credit Agreement”)). The Credit Facilities also contain customary
restrictions and limitations on Atlantic Power Limited Partnership’s (the “Partnership’s”) and its subsidiaries’ ability to
(i) incur additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into
mergers, consolidations, reorganizations, or certain other corporate transactions, (iv) dispose of assets, (v) modify
material contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and (viii) make
dividend payments or other distributions, in each case, subject to customary carve-outs and exceptions and various
thresholds. Any such limitations could restrict our ability to, among other things, make acquisitions or investments or
issue additional indebtedness.
Discontinuation, reform or replacement of the London Interbank Offered Rate (“LIBOR”), or uncertainty related to
the potential for any of the foregoing, may adversely affect us
The U.K. Financial Conduct Authority announced in 2017 that LIBOR would be effectively discontinued after
2021. In addition, other regulators have suggested reforming or replacing other benchmark rates. The discontinuation,
reform or replacement of LIBOR or any other benchmark rates may have an unpredictable impact on contractual
mechanics in the credit markets or cause disruption to the broader financial markets. Uncertainty as to the nature of such
potential discontinuation, reform or replacement may negatively impact the volatility of LIBOR rates, liquidity, our
access to funding required to operate our business, or the trading market for our existing Credit Facilities.
To address the transition away from LIBOR, we have amended our Credit Facilities to provide for an agreed
upon methodology to calculate the new floating benchmark rate plus spread adjustments. If LIBOR becomes unavailable
or if LIBOR ceases to accurately reflect the costs to the lenders, we may be required to pay interest under an alternative
base rate which could cause the amount of interest payable on the Term Loan (as defined herein) to be materially
different than expected.
Our indebtedness and financing arrangements, and any failure to comply with the covenants contained therein, could
negatively impact our business and our projects and could render us unable to make preferred dividend payments,
acquisitions or investments or issue additional indebtedness we otherwise would seek to do
The degree to which we are leveraged on a consolidated basis could have important consequences for our
shareholders and other stakeholders, including:
•
•
•
our ability in the future to obtain additional financing for, among other things, the repayment or redemption
of indebtedness and other debt service obligations and investment in internal and external growth
opportunities, including the acquisition of additional projects, to the extent any such acquisitions are
otherwise available to us, or other purposes;
our ability to refinance indebtedness on terms acceptable to us or at all;
our ability to satisfy debt service and other obligations;
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•
•
•
•
our vulnerability to general adverse industry conditions and economic conditions, including but not limited
to adverse changes in foreign exchange rates and commodity prices;
the availability of cash flow to fund other corporate purposes and grow our business;
our flexibility in planning for, or reacting to, changes in our business and the industry; and
our competitive position relative to our competitors that are not as highly leveraged.
As of December 31, 2019, our consolidated debt represented approximately 82% of our total capitalization,
comprised of debt and balance sheet equity.
The agreements governing our indebtedness limit, but do not prohibit, the incurrence of additional
indebtedness. Our current or future borrowings could increase the level of financial risk to us and, to the extent that the
interest rates are not fixed and rise, or that borrowings are refinanced at higher rates, our available cash flow and results
of operations could be adversely affected. Changes in interest rates do not have a significant impact on cash payments
that are required on our debt instruments as approximately 98% of our debt, including our share of the project-level debt
associated with equity investments in affiliates, either bears interest at fixed rates or is financially hedged through the use
of interest rate swaps.
As of December 31, 2019, we had (i) no amount outstanding and $78.3 million issued in letters of credit under
our Revolver (as defined herein), (ii) $88.5 million of outstanding convertible debentures, and (iii) $560.4 million of
outstanding Term Loan, Medium Term Notes and non-recourse project-level debt.
In addition, some of our projects currently have non-recourse term loans or other financing arrangements in
place with various lenders. These financing arrangements are typically secured by all of the project assets and contracts
as well as our equity interests in the project. The terms of these financing arrangements generally impose many
covenants and obligations on the part of the borrower. For example, some of these agreements contain requirements to
maintain specified historical, and in some cases, prospective debt service coverage ratios before cash may be distributed
from the relevant project to us, which would adversely affect our available cash flow. We have, in the past, failed to
meet the cash flow coverage ratio tests at certain of our projects, which restricted those projects from making cash
distributions. Although all of our projects with non-recourse loans are currently meeting their debt service requirements,
we cannot provide any assurances that our projects will generate enough future cash flow to meet any applicable ratio
tests in order to be able to make distributions to us.
In many cases, an uncured default by any party under key project agreements (such as a PPA or a fuel supply
agreement) will also constitute a default under the project’s term loan or other financing arrangement. Failure to comply
with the terms of these term loans or other financing arrangements, or events of default thereunder, may prevent cash
distributions by the particular project(s) to us and may entitle the lenders to demand repayment and/or enforce their
security interests, which could have a material adverse effect on our business, results of operations and financial
condition. In addition, failure to comply with the terms, restrictions or obligations of any of our convertible debentures
or Credit Facilities, or the preferred shares of the Partnership, or any other financing arrangements, borrowings or
indebtedness, or events of default thereunder, may entitle the lenders to demand repayment, accelerate related debt as
well as any other debt to which a cross-default or cross-acceleration provision applies and/or enforce their security
interests, which could have a material adverse effect on our business, results of operations and financial condition. In
addition, if and for as long as we have failed to declare, or are in arrears on the payment of, dividends on the Series 1
Shares, the Series 2 Shares or the Series 3 Shares, the Partnership will not make any distributions on its limited
partnership units. Additionally, if our lenders under our indebtedness demand payment, we may not, at that time, have
sufficient cash and cash flows from operating activities to repay such indebtedness.
Our failure to refinance or repay any indebtedness when due could constitute a default under such indebtedness
and restrict our ability to take certain actions, including paying dividends on the Series 1 Shares, the Series 2 Shares or
the Series 3 Shares (as herein defined). In addition, any covenant breach or event of default could harm our credit rating
33
and our ability to obtain additional financing on acceptable terms or at all. The occurrence of any of these events could
have a material adverse effect on our business, results of operations, financial condition and liquidity.
Paying dividends on the Series 1 Shares, the Series 2 Shares or the Series 3 Shares could also be restricted if we
fail to meet the targeted debt balances of the Credit Facilities, even though failing to do so would not result in an event
of default.
Exchange rate volatility may affect our available cash flow and results of operations
Our dividend payments on our preferred shares and our interest payments on some of our corporate-level
long-term debt and convertible debentures are denominated in Canadian dollars. Conversely, some of our projects’
revenues and expenses are denominated in U.S. dollars. Our Canadian dollar-denominated debt instruments are revalued
at each balance sheet date based on the U.S. dollar to Canadian dollar foreign exchange rate at the balance sheet date,
with changes in the value of the debt recorded in the consolidated statements of operations. The U.S. dollar to Canadian
dollar foreign exchange rate has been volatile in recent years, which in turn creates volatility in our results due to the
revaluation of our Canadian dollar-denominated debt. Although we currently generate sufficient revenues in Canadian
dollars to fund our Canadian dollar obligations, future exchange rate volatility or changes to our Canadian dollar
revenues could expose us to currency exchange rate risks, against which we do not typically hedge. Any arrangements to
mitigate this exchange rate risk may not be sufficient to fully protect against this risk. If hedging transactions do not fully
protect against this risk, changes in the currency exchange rate between U.S. and Canadian dollars could adversely affect
our available cash flow and results of operations.
A downgrade in our credit rating or in the credit rating of our outstanding debt securities, or any deterioration in
credit quality could negatively affect our ability to access capital and our ability to hedge
A downgrade in our credit rating, a downgrade in the credit rating of our outstanding debt securities, or any
deterioration in credit quality could adversely affect our ability to renew existing, or obtain access to new, credit
facilities and could increase the cost of such facilities, and restrict access to our Revolver. Any downgrade of our
corporate credit rating could also cause counterparties to require us to post letters of credit or other additional collateral,
make cash prepayments, or obtain a guarantee agreement, all of which would expose us to additional costs and/or could
adversely affect our ability to comply with covenants or other obligations under any of our Revolver, convertible
debentures or unsecured notes or any other financing arrangements, borrowings or indebtedness (or could constitute an
event of default under any such financing arrangements, borrowings or indebtedness that we may be unable to cure), any
of which could have a material adverse effect on our business, results of operations and financial condition.
Changes in our creditworthiness may affect the value of our common shares
Changes to our perceived creditworthiness and ability to meet our required covenants on an ongoing basis may
affect the market price or value and the liquidity of our common shares.
The future issuance of additional common shares could dilute existing shareholders
From time to time, we may decide to issue additional common shares, redeem outstanding debt for common
shares, repay outstanding principal amounts under existing debt by issuing common shares, or issue equity-related
securities such as convertible debt. We may also, from time to time, decide to issue common shares to meet strategic
objectives or in connection with acquiring assets or pursuing broader strategic options. The issuance of additional
common shares may have a dilutive effect on shareholders and may adversely impact the price of our common shares.
Volatile capital and credit markets may adversely affect our ability to raise capital on favorable terms and may
adversely affect our business, results of operations, financial condition and cash flows
Disruptions in the capital and credit markets in the United States, Canada or abroad can adversely affect our
ability to access the capital markets. Our access to funds under our Credit Facility is dependent on the ability of the
banks that are parties to the facility to meet their funding commitments. Those banks may not be able to meet their
34
funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of
borrowing requests within a short period of time. Longer-term disruptions in the capital and credit markets as a result of
turmoil in the financial services industry, volatility in securities trading markets and general economic conditions could
result in an inability to support our liquidity needs, including, but not limited to, the service of our debt obligations or
financing of internal or external growth opportunities. See “—We may not generate sufficient cash flow to service our
debt obligations or implement our business plan, including financing internal or external growth opportunities.”
Our ability to arrange for financing on a recourse or non-recourse basis and the costs of such capital are
dependent on numerous factors, some of which are beyond our control, including:
•
•
•
•
•
general industry, economic and capital market conditions;
the availability of bank credit;
investor confidence;
our financial condition, performance and prospects as well as companies in our industry or similar
financial circumstances; and
changes in tax and securities laws which are conducive to raising capital.
Should future access to capital not be available to us, either as a result of market conditions or our financial
condition, we may not be able to service our debt obligations or finance internal or external growth opportunities, any of
which would adversely affect our business, results of operations and financial condition.
We have guaranteed the performance of some of our subsidiaries, which may result in substantial costs in the event
of non-performance
We have issued certain guarantees of the performance of some of our subsidiaries in certain situations, which
obligates us to perform in the event that the subsidiaries do not perform. In the event of non-performance by the
subsidiaries, we could incur substantial cost to fulfill our obligations under these guarantees. Such performance
guarantees could have a material impact on our business, results of operations, financial condition and cash flows. See
Notes 12, 20 and 23 to the consolidated financial statements for information on our guarantee obligations.
We have anti-takeover protections that may discourage, delay or prevent a change in control that could benefit our
shareholders.
The Business Corporations Act (British Columbia) (the “BCBCA”) and our Articles of Continuance contain
provisions that could make it more difficult for a third party to acquire us without the consent of our Board of Directors
(“Board”). These provisions include:
• As a notice of meeting is required to include certain particulars in the case where a shareholder meeting is
being requisitioned by shareholders, our Board must be given advance notice regarding special business
that is to be brought by such requisitioning shareholders before the shareholder meeting. For special
business, advance notice describing the special business to be discussed at the meeting must be provided
and that notice must include any documents to be approved or ratified as an addendum or state that such
document will be available for inspection at our records office or other reasonably accessible location;
• Under the BCBCA, shareholders may make proposals for matters to be considered at the annual general
meeting of shareholders, provided that such shareholders represent at least 1% of the voting shares of a
company or such shares have a fair market value of at least Cdn$2,000. Such proposals must be sent to us
in advance of any proposed meeting by delivering a timely written notice in proper form to our registered
office. The notice must include information on the business the shareholder intends to bring before the
35
meeting. These provisions could have the effect of delaying until the next shareholder meeting shareholder
actions that are favored by the holders of a majority of our outstanding voting securities; and
• Casual vacancies on our Board, which occur when a member of the Board vacates his or her position
before the end of his or her term, can be approved prior to the next annual meeting of shareholders by the
directors of our Board of Directors.
If we experience a change of control, unless we elect to make a voluntary prepayment of the Term Loan, the
Partnership will be required to offer each electing lender a prepayment of such lender’s term loan under the Credit
Facilities at a price equal to 101% of par. Additionally, a change in control will permit holders of our convertible
debentures to require that we purchase the debentures upon the conditions set forth in the respective indenture governing
the debentures, which may discourage, delay or prevent a change of control or the acquisition of a substantial block of
our common shares. In addition, some of our PPAs or other commercial agreements may contain change of control
provisions.
We have a shareholder rights plan in place that may delay or prevent a change of control or the acquisition of a
substantial block of our common shares and may make any future unsolicited acquisition attempt more difficult. Under
the rights plan:
• The rights will generally become exercisable if a person or group acquires 20% or more of Atlantic
Power’s outstanding common shares (unless such transaction is a “permitted bid” or a transaction to which
the application of the shareholders rights plan has been waived pursuant to the terms of the plan) and thus
becomes an “acquiring person.” A “permitted bid” is an offer pursuant to which, among other things, such
person or group agrees to hold the offer open to all shareholders for a period longer than the statutorily
required period;
• Each right, when exercisable, will entitle the holder, other than the “acquiring person,” to acquire shares of
Atlantic Power’s common shares at a significant discount to the then-prevailing market price; and
• As a result, the rights plan may cause substantial dilution to a person or group that becomes an “acquiring
person” and may discourage or delay a merger or acquisition that shareholders may consider favorable,
including transactions in which shareholders might otherwise receive a premium for their shares.
U.S., Canadian and/or global economic conditions and uncertainty could adversely affect our business, results of
operations and financial condition
Our business may be affected by changes in U.S., Canadian and/or global economic conditions, including
inflation, deflation, interest rates, availability of capital, consumer spending rates and the effects of governmental
initiatives to manage economic conditions. Uncertainty about global economic conditions may cause consumers to alter
behaviors that may directly or indirectly reduce energy spending, which could have a material adverse effect on demand
for our products. Volatility in the financial markets and the deterioration of national and global economic conditions may
have a material adverse effect on our business, results of operations and financial condition.
36
Financial markets can also be, and have been in the past, affected by concerns over U.S. fiscal policy, federal
deficit and related budget and tax issues. These concerns have from time to time raised concerns relating to the stability
of the long-term sovereign credit rating of the United States. Any actions taken by the U.S. federal government regarding
the federal deficit or any action taken or threatened by ratings agencies, could significantly impact the global and U.S.
economies and financial markets. Any such economic downturn could have a material adverse effect on our business,
results of operations and financial condition.
Impairment of goodwill, long-lived assets or equity method investments could have a material adverse effect on our
results of operations and financial condition
As of December 31, 2019, we had $21.3 million of goodwill, which represented approximately 2% of our total
assets on our consolidated balance sheets. Goodwill is not amortized, but is evaluated for impairment at least annually or
more frequently if an event or change in circumstance occurs that would more likely than not reduce the fair value of a
reporting unit below its carrying value. We could be required to, and have in the past, evaluated the potential impairment
of goodwill outside of the required annual evaluation process if we experience situations, including but not limited to,
sustained declines in market capitalization, deterioration in general economic conditions or our operating or regulatory
environment, increased competitive environment, an increase in fuel costs (particularly when we are unable to pass-
through the impact to customers), significant changes in forecasted market prices for power, negative or declining cash
flows, loss of a key contract or customer (particularly when we are unable to replace it on equally favorable terms), or
our inability to renew certain of our PPAs following their expiration or termination. These types of events and the
resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations
for those periods. Additionally, goodwill may be impaired if any acquisitions we make do not perform as expected.
Long-lived assets are initially recorded at acquisition cost and are amortized or depreciated over their estimated
useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present, whereas
goodwill is evaluated for impairment on an annual basis or more frequently if potential impairment indicators are
present. Otherwise, the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of
goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and
assumptions to determine fair value, as described above.
We have recorded $55.0 million, nil and $187.2 million of goodwill, long-lived asset and equity method
investment impairments for the years ended December 31, 2019, 2018 and 2017, respectively. See Note 9 to the
consolidated financial statements included in this Annual Report on Form 10-K.
Increasing competition could adversely affect our performance and the performance of our projects
The power generation industry is characterized by intense competition and our projects encounter competition
from utilities, industrial companies and other independent power producers, in particular with respect to uncontracted
output. In recent years, there has been increasing competition among generators for PPAs, and this has contributed to a
reduction in electricity prices in certain markets where supply has surpassed demand plus appropriate reserve margins.
Further, changes and developments in technology, including fuel cells, microturbines, solar cells and other
emerging technologies related to energy generation, distribution and consumption, may facilitate the entrance of new
competitors, increase the supply of electricity, and reduce the cost of methods of producing power that we do not
currently use or lower the price of or demand for energy. If these technologies became cost-competitive, we could face
increasing competition and the value of our generating facilities could be reduced.
In addition, we continue to confront significant competition for acquisition and investment opportunities and, to
the extent that any opportunities are identified, we may be unable to effect acquisitions or investments on attractive
terms, if at all. Increasing competition among participants in the power generation industry may adversely affect our
performance and the performance of our projects. Further, a payout of a significant portion of our cash flow to service
our debt may result in us not retaining a sufficient amount of cash to finance acquisition or investment opportunities and
make other capital and operating expenditures. See “—Risks Related to Our Financial Position and Economic and
Financial Market Conditions—We may not generate sufficient cash flow to service our debt obligations or implement
37
our business plan, including financing internal or external growth opportunities.”
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We have included descriptions of the locations and general character of our principal physical operating
properties, including an identification of the segments that use such properties, in “Item 1. Business,” which is
incorporated herein by reference. A significant portion of our equity interests in the entities owning these properties is
pledged as collateral under our Credit Facilities or under non-recourse operating level debt arrangements.
Our principal executive office is located at 3 Allied Drive, Suite 155, Dedham, Massachusetts under a lease that
expires in 2024. Our registered office is located at 1066 West Hastings Street, Suite 2600, Vancouver, British Columbia
V6E 3X1 Canada.
ITEM 3. LEGAL PROCEEDINGS
From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that
arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies
when a loss is likely and can be reasonably estimated. There are no matters pending which are expected to have a
material adverse impact on our financial position or results of operations or have been reserved for as of December 31,
2019.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
38
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Purchases of Equity Securities by Atlantic Power Corporation and Affiliated Purchasers
Share Repurchase Program
On December 31, 2019, we commenced a new Normal Course Issuer Bid (“NCIB”) for our Series E
Debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd.
(“APPEL”), our wholly-owned subsidiary. The NCIBs expire on December 30, 2020 or such earlier date as the
Company and/or APPEL complete their respective purchases pursuant to the new NCIBs. Under the NCIB, we may
purchase up to a total of 10,578,799 common shares based on 10% of our public float as of December 17, 2019 and we
are limited to daily purchases of 9,243 common shares per day with certain exceptions including block purchases and
purchases on other approved exchanges. All purchases made under the NCIBs will be made through the facilities of the
TSX or other Canadian designated exchanges and published marketplaces and in accordance with the rules of the TSX at
market prices prevailing at the time of purchase. Common share purchases under the NCIBs may also be made on the
New York Stock Exchange (“NYSE”) in compliance with Rule 10b-18 under the Exchange Act, as amended, or other
designated exchanges and published marketplaces in the United States in accordance with applicable regulatory
requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval.
As of December 31, 2019, we have not made any repurchases under the new NCIBs.
This new NCIB replaced the prior NCIB that expired on December 30, 2019. Under the prior NCIB, we
repurchased and cancelled 1,064,081 million common shares at a cost of $2.5 million. The following table provides
purchases of common equity securities by Atlantic Power Corporation and affiliated purchasers for the period of
October 1, 2019 through December 31, 2019:
Purchase Period
10/1/2019 - 10/31/2019
11/1/2019 - 11/30/2019
12/1/2019 - 12/31/2019
Total
Common Shares
Total Number of
Shares Purchased
Average Price Paid as Part of a Publicly Announced of Shares to be Purchased Under
Per Share
Purchase Plan
the Plan
Total Number of Shares
Dollar Value of Maximum Number
50,829
35,044
618,444
704,317
$ 2.27
$ 2.35
$ 2.35
50,829
35,044
618,444
704,317
$0 (1)
(1) This plan expired on December 30, 2019, and has been replaced by the NCIB as noted above.
The Board authorization permits the Company to repurchase common and preferred shares and convertible
debentures. Therefore, in addition to the current NCIBs, from time to time we may repurchase our securities, including
our common shares, our convertible debentures and our APPEL preferred shares through open market purchases,
including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the Exchange Act, NCIBs,
issuer self tender or substantial issuer bids, or in privately negotiated transactions. There can be no assurances as to the
amount, timing or prices of repurchases, which may vary based on market conditions, other market opportunities and
other factors. Any share repurchases outside of previously authorized NCIBs would be effected after taking into account
our then current cash position and then anticipated cash obligations or business opportunities.
Subsequent to December 31, 2019 and through February 26, 2020, we have repurchased and cancelled
1,742,919 common shares at a cost of $4.1 million under the new NCIB.
Market Information and Holders
Our common shares trade on the NYSE under the symbol “AT” and on the TSX under the symbol “ATP”. The
number of common shares outstanding was 106,932,375 on February 26, 2020.
39
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of December 31, 2019 regarding our Long-Term Incentive Plan.
For the description of our Long-Term Incentive Plan, see Note 17, Equity Compensation Plans to the consolidated
financial statements.
Number of securities to be Weighted-average
exercise price of
outstanding options,
warrants and rights
issued upon exercise of
outstanding options,
warrants and rights(1)(2)
(a)
(b)
Number of securities remaining
available for future issuance
under equity compensation plans
(excluding securities reflected
in column (a))(1)(2)
(c)
Equity compensation plans approved by
security holders
Equity compensation plans not approved
by security holders
Total
1,276,664 $
179,968
1,456,632 $
—
—
—
—
89,984
89,984
(1) Number of securities to be issued upon exercise of outstanding awards and number of securities remaining available
for future issuance reflects expected redemption of award one-third in cash and two-thirds in common shares for
officers and one hundred percent in cash for non-officers. Specifically, the number of securities to be issued upon
exercise of the outstanding awards reflects two-thirds of the number of outstanding notional shares held by officers;
it does not include notional shares expected to be settled in cash See Item 15. “Exhibits and Financial Statements
Schedule”—Note 2(u), Equity compensation plans.
(2) The maximum aggregate number of common shares that may be issued under our Long-Term Incentive Plan upon
redemption of notional shares is 6,000,000 and the maximum aggregate number of common shares that may be
issued under our Transition Equity Grant Participation Agreement upon redemption of notional shares is 539,903.
See Item 15. “Exhibits and Financial Statements Schedule”—Note 2(u), Equity compensation plans.
Performance Graph
The performance graph below compares the cumulative total shareholder return on our common shares for the
period December 31, 2014 through December 31, 2019, with the cumulative total return of the Standard & Poor’s 500
Composite Stock Price Index, or S&P 500, and the Standard & Poor’s TSX Composite, or S&P/TSX.
The performance graph shown below is being furnished and compares each period assuming that a $100
investment was made on December 31, 2014 in each of our common shares, the stocks included in the S&P 500 and the
stocks included in the S&P/TSX, and that all dividends were reinvested.
40
Comparison of Cumulative Total Return
Total Return Performance
2015
2016
2017
2018
2019
Atlantic Power Corporation
S&P 500
S&P/TSX
180
160
140
120
100
80
60
40
20
l
e
u
a
V
x
e
d
n
I
0
2014
AT
S&P
S&P / TSX
Dec-2014
Dec-2015
Dec-2016
Dec-2017
Dec-2018
Dec-2019
$
100.00 $
100.00
100.00
75.55 $
95.87 $
90.12 $
83.22 $
101.38
88.91
113.34
104.48
135.17
110.78
130.79
97.88
89.35
159.67
116.61
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected historical consolidated financial information for each of the periods
indicated. The annual historical information for each of the years in the three-year period ended December 31, 2019 has
been derived from our audited consolidated financial statements included elsewhere in this Annual Report on
Form 10-K.
You should read the following selected consolidated financial data along with “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements
and the accompanying notes, which describe the impact of material acquisitions and dispositions that occurred in the
three-year period ended December 31, 2019.
41
(in millions of U.S. dollars, except as otherwise stated)
Project revenue
Project income (loss)
(Loss) income from continuing operations
Income from discontinued operations, net of tax
Net (loss) income attributable to Atlantic Power
Corporation
Basic (loss) earnings per share
(Loss) earnings per share from continuing
operations attributable to Atlantic Power Corporation
Earnings per share from discontinued operations, net of
tax
Net (loss) income attributable to Atlantic Power
Corporation
Diluted (loss) earnings per share attributable to Atlantic
Power Corporation (c)
Dividend declared per common share
Total assets
Total long-term liabilities
2019(a)
$ 281.6 $
46.8
(43.8)
—
Year Ended December 31,
2017(a)
431.0 $
(47.4)
(93.0)
—
2018(a)
282.3 $
88.2
37.2
—
2016(a)
399.2 $
10.1
(113.9)
—
420.2
(41.4)
(84.1)
19.5
2015(a)(b)
(42.6)
36.8
(98.6)
(122.4)
(62.4)
$ (0.39) $
0.33 $
(0.86) $
(1.02) $
(0.76)
—
—
—
—
0.25
$ (0.39) $
0.33 $
(0.86) $
(1.02) $
(0.51)
(0.51)
$ (0.39) $
$
0.09
— $
$ 935.6 $ 1,031.5 $ 1,158.8 $ 1,456.8 $ 1,671.2
829.1 $ 1,020.0 $ 1,020.0
$ 675.0 $
(0.86) $
— $
(1.02) $
— $
0.29 $
— $
723.2 $
(a)
Includes $55.0 million, $0, $187.2 million, $85.9 million and $127.8 million of goodwill, long-lived asset and
equity method investment impairments for the years ended December 31, 2019, 2018, 2017, 2016 and 2015,
respectively.
(b) Excludes the Wind Projects, which are classified as discontinued operations for the year ended December 31, 2015.
(c) Diluted (loss) earnings per share is computed including dilutive potential shares, which include those issuable upon
conversion of convertible debentures and under our long-term incentive plan (“LTIP”). Please see the notes to our
historical consolidated financial statements included elsewhere in this Annual Report on Form 10-K for information
relating to the number of shares used in calculating basic and diluted (loss) earnings per share for the periods
presented.
42
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following management’s discussion and analysis of financial condition and results of operations should be
read in conjunction with our audited consolidated financial statements included in this Annual Report on Form 10-K. All
dollar amounts discussed below are in millions of U.S. dollars, unless otherwise stated. The financial statements have
been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
(in millions of U.S. dollars, except per-share amounts)
The discussion and analysis below has been organized as follows:
1) 2019 Significant Activities and Recent Events
2) Performance Highlights and Overview of 2019 Results
3) Results of Operations by Segment
4) Project Operating Performance
5) Supplementary Non-GAAP Financial Information
6) Liquidity and Capital Resources
7) Critical Accounting Policies
2019 Significant Activities
Below, we discuss our progress in executing our business strategy, which is presented in detail in Item 1.
Business to this Annual Report on Form 10-K.
Debt reduction
During 2019, we made payments of $72.3 million to reduce our corporate and consolidated project-level debt
and repurchased $18.5 million of convertible debentures prior to their December 2019 maturity. Our consolidated
leverage ratio at year end 2019 was 3.8 times, an improvement from 4.5 times at year end 2018. In December 2019, S&P
raised our issuer credit rating to BB- (stable) from B+ (positive) based on our improving leverage profile reflecting the
predictability of contracted cash flows and our plan to continue to allocate excess cash to pay down debt.
In January 2020, we were able to reprice the Term Loan, lowering the rate from LIBOR plus 2.75% to LIBOR
plus 2.50%. This is the fifth repricing since the inception of the Term Loan under which we originally paid interest at
LIBOR plus 5.00%. An additional 0.25% step down in the interest rate margin will become effective should we achieve
a Leverage Ratio (as defined in the Credit Agreement) of 2.75:1.00. Additionally, we amended the Term Loan to extend
the maturity date by two years to April of 2025 and added customary new provisions relating to the replacement of
LIBOR as the benchmark for the Eurodollar Rate (as defined in the Credit Agreement). Targeted debt balances, which
prescribe required quarterly principal payments, were also adjusted and will end in December 2022. We expect to fully
repay the Term Loan by its maturity date.
Capital allocation
During 2019, we allocated capital to both external acquisitions and equity repurchases. We used $28.5 million
of our discretionary cash to close the acquisition of the Allendale and Dorchester biomass plants in South Carolina and
equity investments in the Craven (North Carolina) and Grayling (Michigan) biomass plants. Including the $2.6 million
deposit on the South Carolina plants made in 2018 and transaction costs, the total investment in these four plants was
$31.3 million. We believe these acquisitions represent a meaningful addition to the level and length of our existing
contracted cash flows. Together with the 2018 acquisition of the remaining ownership interests in our Koma Kulshan
hydro project for $13.6 million, as discussed in Note 3, Acquisitions and divestments to the consolidated financial
statements, these were the first external investments that we have made during current management’s tenure since 2015.
43
We also used $10.5 million of our discretionary capital to repurchase and cancel common ($2.5 million) and
preferred (US$8.0 million equivalent) shares at prices that we believe were attractive relative to our estimates of value
during 2019. From 2015 through 2019, we repurchased a total of approximately 17.0 million common shares,
representing an investment of $38.8 million, and a total of nearly 1.6 million preferred shares, representing a total
investment of Cdn$24.7 million (US$19.1 million equivalent). Common shares outstanding have been reduced
approximately 11% during this period. The return on preferred share repurchases has averaged approximately 10% to
11%, including avoided tax-related obligations.
PPA renewals
In January 2019, Merck & Co., Inc. (“Merck”), the customer at our Kenilworth project, exercised its second
extension option under the PPA, extending the expiration date from September 30, 2019 to September 30, 2020. In July
2019, Merck exercised the third and final one-year option under the PPA, extending its expiration date from
September 30, 2020 to September 30, 2021.
In September 2019, we executed a new ten-year Energy Purchase Agreement with BC Hydro for our Williams
Lake biomass plant in British Columbia, Canada that became effective October 1, 2019. Under the new contract,
Williams Lake receives a fixed price per megawatt-hour for energy produced, up to the maximum level of generation
permitted under the agreement. This price escalates annually with the British Columbia Consumer Price Index. The
contract does not provide for a capacity payment and the energy payment structure does not include a fuel cost pass-
through. Given the state of the timber market in British Columbia, the availability and cost of fuel will be the most
significant variables determining the operational and financial performance of Williams Lake under the new contract.
Cost management
We cut our corporate overhead expense from approximately $54 million in 2013 to $24 million for 2019, which
represents a cumulative reduction from 2013 of approximately 57%. We have maintained our corporate overhead in the
$24 million range for the past four years.
Recent Events
Cadillac Repair Update
On September 22, 2019, the Cadillac project experienced a malfunction in its steam turbine that began a
cascade of events, sparking a fire that resulted in significant damage to the turbine, generator and other components in
that area of the plant. The fire was contained by the local fire department and did not result in any injuries or known
environmental violations. Although the plant incurred significant damage and is expected to be out of service for a
lengthy period, we expect that the financial impact will be limited by our comprehensive insurance coverage.
During the third quarter, we recorded a $25 million write-down of Cadillac’s property, plant and equipment and
a $0.3 million write-down of capital spares inventory. We also recorded a corresponding insurance receivable
($24.2 million) as a component of other assets less the $1.0 million property damage deductible, which was recorded as
an insurance loss charged to other project income because we believe that it is probable we will receive insurance
recoveries up to the replacement cost of the plant, less the deductible.
During the fourth quarter, we received $11.3 million of insurance proceeds with respect to the fire at Cadillac,
which were applied against the insurance receivable. During the three months ended December 31, 2019, we recorded a
$0.6 million write-down of fuel inventory, with a corresponding increase to the insurance receivable. As of December
31, 2019, the insurance receivable balance totaled $13.5 million. Additionally, we estimate anticipated insurance
recoveries related to business interruption losses of $2.0 million for the three months ended December 31, 2019.
Anticipated reimbursements for lost profits, or business interruption losses, are accounted for as a gain contingency
because lost profits are not considered an incurred loss. Anticipated reimbursements for business interruption losses
were not recorded as of December 31, 2019 as all contingencies related to these claims had not been resolved as of
44
period end. We expect all contingencies related to business interruption losses to be resolved once final payment is
received from the insurers, which is when we will recognize the reimbursements in earnings (loss). Capital spending
through December 31, 2019 for repairs at Cadillac was $5.1 million.
Chambers Impairment
We own a 40% limited partner interest in Chambers Cogeneration Limited Partnership. Chambers operates
under a PPA that expires in March 2024. During the fourth quarter of 2019, we performed an analysis of the post-PPA
value of Chambers operating as a merchant facility. As a result, we identified a significant decrease in the long-term
outlook for power prices and spark spreads in PJM, the region where Chambers operates. These forward power prices,
which were obtained from a third party, including analysis of the forward prices for natural gas and coal, had a
significant negative impact on the projected discounted cash flows of Chambers post-PPA. The estimated post-PPA
value is a significant component of the project’s overall value when compared to its pre-impairment carrying value of
$58.2 million.
When determining if this decrease in estimated fair value was other than temporary, we considered the
likelihood that future conditions would change such that the gas and coal prices currently observed in the forward
pricing models would become more favorable over time in order for the project to be profitable in a merchant market.
While declining power prices have been observed over the past several years, it was our assessment that future merchant
pricing and spark spreads were likely to remain low and that Chambers would be unable to recover its start fuel and start
operations and maintenance costs after expiration of its PPA in 2024. Based on these factors, we determined that the
decline in the fair value of our investment in Chambers was other than temporary. We recorded a $49.2 million
impairment in earnings (loss) from unconsolidated affiliates in the consolidated statements of operations for the year
ended December 31, 2019. Subsequent to recording the impairment, our remaining equity investment in Chambers is
$9.0 million.
Performance Highlights and Overview of 2019 Results
(in millions of U.S. dollars, except as otherwise stated)
Year Ended December 31,
2018
2019
2017
Project revenue
Project income (loss)
Net (loss) income attributable to Atlantic Power Corporation
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
(Loss) earnings per share attributable to Atlantic Power Corporation—basic
(Loss) earnings per share attributable to Atlantic Power Corporation—diluted
Project Adjusted EBITDA(1)
$
$
$
$
$
46.8 $
(42.6) $
144.7
(21.7)
(110.8)
281.6 $ 282.3 $ 431.0
88.2 $ (47.4)
36.8 $ (98.6)
169.2
137.5
(4.3)
(17.0)
(178.9)
(135.0)
0.33 $ (0.86)
(0.39) $
(0.39)
(0.86)
0.29
196.1 $ 185.1 $ 288.8
(1) See reconciliation and definition below under Supplementary Non-GAAP Financial Information.
Revenue decreased from $282.3 million in the year ended December 31, 2018 to $281.6 million in the year
ended December 31, 2019, a decrease of $0.7 million. The primary drivers of the decrease are as follows:
• Williams Lake – the extension of the energy purchase agreement at Williams Lake that became effective in
April 2018 and expired in September 2019 provided lower pass-through of costs than the previous contract.
The project entered into a new energy services agreement that became effective in October 2019, but the
plant did not operate until late December, resulting in lower dispatch than in 2018. These factors resulted in
a $9.5 million decrease in project revenue;
•
San Diego projects – the Naval Station, North Island and NTC projects ceased operations in February
2018. This resulted in a $7.4 million decrease in project revenue;
45
• Cadillac – the project ceased operation after the fire in September 2019, resulting in $5.6 million decrease
in energy and capacity revenue; and
• Morris – there was a $3.3 million decrease in project revenue at our Morris project due to lower fuel index
prices than in 2018.
These decreases in project revenue were partially offset by:
• Curtis Palmer – higher water flows resulted in a $12.0 million increase in revenue from 2018;
• Allendale and Dorchester – the Allendale and Dorchester projects were purchased on July 31, 2019 and
contributed $10.8 million of revenue in 2019; and
• Tunis – the project commenced its restart in October 2018 and contributed $1.0 million of revenue in 2018
as compared to $4.4 million of revenue in 2019, for an increase in project revenue of $3.4 million.
Consolidated project income was $46.8 million for the year ended December 31, 2019, a decrease of
$41.4 million from the prior year project income of $88.2 million. The primary drivers of the decrease are as follows:
•
Impairment of equity investment and long-lived assets – we recorded a $49.2 million equity investment
impairment at Chambers and a $5.8 million long-lived asset impairment at Calstock in 2019;
• Derivative instruments – the change in fair value of our derivative instruments decreased $11.1 million
from 2018; and
• Remeasurement gain – we recorded a $6.7 million gain in 2018 related to the remeasurement of our
previous 50% equity ownership of Koma to fair value resulting from the acquisition of the remaining 50%
in July of 2018.
These decreases in project income were partially offset by increases in project income resulting from:
• Depreciation and amortization expense – depreciation and amortization expense decreased by
$19.2 million from 2018 primarily due to a decrease of $17.9 million at our Nipigon project resulting from
the PPA intangible asset being fully amortized in 2018 and a $2.6 million decrease at the San Diego
projects, which ceased operations in February 2018; and
• Operations and maintenance expenses – operation and maintenance expenses decreased by $8.0 million
from 2018 primarily due to a decrease of $7.1 million in maintenance expense at our Manchief project
where a turbine overhaul was performed in 2018, a $5.2 million decrease in operations and maintenance
expenses at the San Diego projects, which ceased operations in February 2018, and a $3.7 million decrease
in maintenance expense at our Tunis project where costs were incurred in 2018 in preparation for the
commencement of its commercial operation. These decreases were partially offset by $4.8 million of
increased operation and maintenance expenses at the Allendale and Dorchester projects, which were
purchased on July 31, 2019.
A detailed discussion of project income (loss) by segment is provided in Results of Operations by Segment
below. The discussion of Project Adjusted EBITDA by segment begins on page 59.
Factors and trends that may influence our results
The primary components of our financial results are (i) the financial performance of our projects, (ii) unrealized
gains and losses associated with derivative instruments, (iii) interest expense and foreign exchange impacts on
corporate-level debt, and (iv) impairment of goodwill, long-lived assets and equity method investments. We have
46
recorded net losses in four of the past five years, primarily as a result of non-cash losses associated with items (ii), (iii)
and (iv) above, which are described in more detail in the following paragraphs.
Financial performance of our projects
The operating performance of our projects supports cash distributions that are made to us after all operating,
maintenance, capital expenditures and debt service requirements are satisfied at the project-level. Our projects are able to
generate cash flows because they generally receive revenues from long-term contracts that provide relatively stable cash
flows. Risks to the stability of these distributions include the following:
• Power generated by our projects, in most cases, is sold under PPAs that expire at various times. Currently,
our PPAs are scheduled to expire between May 2020 and November 2043. When a PPA expires or is
terminated, it may be difficult for us to secure a new PPA on acceptable terms or timing, if at all, or the
price received by the project for power under subsequent arrangements may be reduced significantly, or
there may be a delay in securing a new PPA until a significant time after the expiration of the original PPA
at the project. See “Risk Factors—Risks Related to the Operation of Our Business—The expiration or
termination of our PPAs could have a material adverse impact on our business, results of operations and
financial condition.”
• Our PPAs are generally structured to minimize our risk to fluctuations in commodity prices by passing the
cost of fuel through to the utility and its customers, but some of our projects do have exposure to market
power and fuel prices. See Item 1A. “Risk Factors— Risks Related to the Operation of Our Business—Our
projects depend on third-party suppliers under fuel supply agreements, and increases in fuel costs may
adversely affect the results of the operations of the projects” and Item 7A. “Quantitative and Qualitative
Disclosures About Market Risk” for additional details about our hedging arrangements.
• Our most significant exposure to market power prices exists at the Chambers and Morris projects. At
Chambers, plant capacity is sold forward pursuant to the PPA with our utility customer but the project is
economically dispatched, which impacts variable operating margins. For example, during periods of low
demand and low spot electricity prices, the project is dispatched less, which reduces the project’s operating
margin. In addition, the utility customer has the right to sell a portion of the output into the spot market if it
is economical to do so, and the Chambers project shares in the profit from these sales. This also adds some
variability to the project’s financial results. At Morris, a portion of the capacity is contracted with the
industrial customer through 2034. The remaining capacity has been sold forward into the PJM capacity
market through annual auctions covering the period through May 2022. The capacity revenues from these
auctions generally represent the majority of the operating margin of the uncontracted portion of the project.
Energy associated with the capacity sold forward into the PJM market is generally dispatched by PJM
when economic to do so or when needed for other reasons. The project can also offer ancillary services to
the grid. The sale of energy and ancillary services from the uncontracted portion of the project is not at a
fixed price or margin and therefore can add variability to the project’s financial results. See Item 1A. “Risk
Factors— Risks Related to the Operation of Our Business—Certain of our projects are exposed to
fluctuations in the price of electricity, which may have a material adverse effect on the operating margin of
these projects and on our business, results of operations and financial condition.”
• The performance of our projects is impacted by a variety of operational and other factors, including water,
planned and unplanned outages and maintenance requirements, delays in start-up, sourcing of fuel from
suppliers, among others. For additional details regarding the various operational and other risks that we
face, see Item 1A “Risk Factors— Risks Related to the Operation of Our Business.”
• When revenue or fuel contracts at our projects expire, we may not be able to sell power or procure fuel
under new arrangements that provide the same level or stability of project cash flows. If re-contracted, the
degree of the expected decline in cash flows from operations is subject to market conditions when we
execute new PPAs for these projects and is difficult to estimate at this time. See Item 1A. “Risk Factors—
47
Risks Related to the Operation of Our Business—The expiration or termination of PPAs could have a
material adverse impact on our business, results of operations and financial condition.
• Our Cadillac (consolidated) and Chambers (equity method) projects have non-recourse project-level debt
that can restrict the ability of the projects to make cash distributions. The project-level debt agreements
contain a cash flow coverage ratio test that restricts the projects’ cash distributions if project cash flows do
not exceed project-level debt service requirements by a specified amount. Although these projects are
currently meeting their debt service requirements, we cannot provide any assurances that they will generate
enough future cash flow to meet any applicable ratio tests and be able to make distributions to us. See
“Liquidity and Capital Resources—Uses of Liquidity—Debt Services Obligations—Project Level”“ and
Item 1A. “Risk Factors—Risks Related to Our Financial Position and Economic and Financial Market
Conditions—Our indebtedness and financing arrangements, and any failure to comply with the covenants
contained therein, could negatively impact our business and our projects and could render us unable to
make acquisitions or investments or issue additional indebtedness we otherwise would seek to do.”
Non-cash gains and losses on derivatives instruments
In the ordinary course of our business, we execute natural gas purchase agreements and natural gas swap
contracts to manage our exposure to fluctuations in commodity prices, foreign currency forward contracts to manage our
exposure to fluctuations in foreign exchange rates and interest rate swaps to manage our exposure to changes in interest
rates on variable rate project-level debt. Most of these contracts are recorded at fair value with changes in fair value
recorded currently in earnings, resulting in significant volatility in our income that does not significantly affect current
period cash flows or the underlying risk management purpose of the derivative instruments. See Item 7A. “Quantitative
and Qualitative Disclosures About Market Risk” for additional details about our derivative instruments.
Interest expense and other costs associated with debt
Interest expense relates to both non-recourse project-level debt and corporate-level debt. A portion of our
convertible debentures and long-term corporate level debt are denominated in Canadian dollars. These debt instruments
are revalued at each balance sheet date based on the U.S. dollar to Canadian dollar foreign exchange rate at the balance
sheet date, with changes in the value of the debt recorded in the consolidated statements of operations. The U.S. dollar to
Canadian dollar foreign exchange rate has been volatile in recent years, which in turn creates volatility in our results due
to the revaluation of our Canadian dollar-denominated debt.
Impairment
We test our goodwill for impairment at least annually, or more often if deemed appropriate based on the
determination of management of the occurrence of certain trigger events under our impairment policy. Equity method
investments and long-lived assets, such as property, plant and equipment, and other intangible assets and liabilities
subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount of an equity method investment or asset group may not be recoverable. We recorded
$55.0 million, nil and $187.1 million of impairments for the years ended December 31, 2019, 2018 and 2017,
respectively. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA on acceptable terms or
timing, if at all. It is possible that subsequent PPAs may not be available at prices that permit the operation of the project
on a profitable basis. When the affected project temporarily or permanently ceases operations, or when we have an
expectation that we will be unable to renew or renegotiate the PPA, the value of the project may be impaired such that
we would record an impairment loss. See “Critical Accounting Policies – Goodwill” for a discussion of the trends and
factors that have resulted in the recorded goodwill, long-lived asset and equity method investment impairments.
Results of Operations by Segment
We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our
reportable business segments in the fourth quarter of 2019 as the result of recent asset acquisitions, PPA expirations and
project decommissioning and in order to align with changes to management’s structure, resource allocation and
48
performance assessment in making decisions regarding our operations. Our financial results for the year ended
December 31, 2018 and 2017 have been revised to reflect these changes. All results of operations for the Solid Fuel,
Natural Gas and Hydroelectric segments are recorded as a component of project income (loss). The segment classified as
Corporate (formerly Un-Allocated Corporate) includes management fee revenue, operating expenses directly related to
supporting our projects and mark-to-market adjustments of fuel and interest rate swaps. These items are recorded as a
component of project income (loss). The Corporate segment also includes activities that support the executive and
administrative offices, capital structure, costs of being a public registrant, costs to develop future projects and
intercompany eliminations. These costs are not allocated to the other operating segments when determining project
income (loss). Project income (loss) is the primary GAAP measure of our operating results and is discussed below by
reportable segment followed by a discussion of Corporate items not included in project income (loss).
2019 compared to 2018
The following tables summarize our consolidated results of operations and project (loss) income by reportable
Years Ended December 31,
2019
2018
$ change % change
$ 138.0 $ 130.9 $
7.1
27.5
(35.3)
(0.7)
(0.8)
(8.0)
(19.2)
(28.0)
(11.1)
(46.2)
0.7
(5.8)
(1.0)
(5.3)
(68.7)
(41.4)
—
(8.7)
34.7
4.0
30.0
(71.4)
9.6
(81.0)
5.4 %
28.1 %
(66.0)%
(0.2)%
(1.1)%
(9.4)%
(22.9)%
(11.6)%
NM
NM
(38.9)%
NM
NM
NM
NM
(46.9)%
— %
(16.5)%
NM
NM
59.1 %
NM
NM
NM
97.9
53.5
282.3
73.1
85.0
83.7
241.8
2.2
43.2
(1.8)
—
—
4.1
47.7
88.2
23.9
52.7
(22.8)
(3.0)
50.8
37.4
0.2
37.2
125.4
18.2
281.6
72.3
77.0
64.5
213.8
(8.9)
(3.0)
(1.1)
(5.8)
(1.0)
(1.2)
(21.0)
46.8
23.9
44.0
11.9
1.0
80.8
(34.0)
9.8
(43.8)
(1.2)
$ (42.6) $
0.4
(1.6)
36.8 $ (79.4)
NM
NM
segment:
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (expense):
Change in fair value of derivative instruments
Equity in (loss) earnings of unconsolidated affiliates
Interest expense, net
Impairment
Insurance loss
Other (expense) income, net
Project income
Administrative and other expenses:
Administration
Interest expense, net
Foreign exchange loss (gain)
Other expense (income), net
(Loss) income from operations before income taxes
Income tax expense
Net (loss) income
Net (loss) income attributable to preferred shares of a
subsidiary company
Net (loss) income attributable to Atlantic Power Corporation
49
Project (Loss) Income by Segment
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (expense):
Change in fair value of derivative instruments
Equity in (loss) earnings of unconsolidated affiliates
Interest expense, net
Impairment
Insurance loss
Other expense, net
Project (loss) income
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (expense):
Change in fair value of derivative instruments
Equity in earnings of unconsolidated affiliates
Interest expense, net
Other (expense) income, net
Year Ended December 31, 2019
Consolidated
Solid Fuel Natural Gas Hydroelectric Corporate
Total
$ 41.1 $
38.7
0.2
80.0
31.0 $
86.7
14.1
131.8
65.9 $
—
2.9
68.8
— $
—
1.0
1.0
138.0
125.4
18.2
281.6
28.6
33.5
14.7
76.8
43.7
28.9
30.2
102.8
—
13.3
19.5
32.8
—
1.3
0.1
1.4
—
(45.0)
(1.2)
(5.8)
(1.0)
—
(53.0)
$ (49.8) $
(1.4)
42.0
0.1
—
—
(1.2)
39.5
68.5 $
—
—
—
—
—
—
36.0 $
(7.5)
—
—
—
—
—
(7.5)
(7.9) $
72.3
77.0
64.5
213.8
(8.9)
(3.0)
(1.1)
(5.8)
(1.0)
(1.2)
(21.0)
46.8
Year Ended December 31, 2018
Consolidated
Solid Fuel Natural Gas Hydroelectric Corporate
Total
$ 37.4 $
41.6
4.8
83.8
38.3 $
56.3
44.6
139.2
55.2 $
—
3.1
58.3
— $
—
1.0
1.0
24.1
28.9
15.0
68.0
—
5.6
(1.7)
—
3.9
49.0
44.0
49.9
142.9
—
11.6
18.7
30.3
—
0.5
0.1
0.6
3.2
37.0
(0.1)
(3.1)
37.0
33.3 $
—
0.6
—
7.2
7.8
35.8 $
(1.0)
—
—
—
(1.0)
(0.6) $
130.9
97.9
53.5
282.3
73.1
85.0
83.7
241.8
2.2
43.2
(1.8)
4.1
47.7
88.2
Project income (loss)
$ 19.7 $
Discussion of project income (loss) by reportable segment:
Solid Fuel
Project income for 2019 decreased $69.5 million from 2018 primarily due to:
•
decreased project income of $51.6 million at Chambers primarily due to a $49.2 million impairment
recorded in 2019;
50
•
•
•
decreased project income of $8.9 million at Williams Lake primarily due to the extension of the energy
purchase agreement that became effective in April 2018 and expired in September 2019, which provided
lower pass-through of costs than the previous contract. The project entered into a new energy purchase
agreement that became effective in October 2019, but the plant did not operate until late December,
resulting in lower dispatch than 2018;
decreased project income of $6.0 million at Calstock primarily due to a $5.8 million long-lived asset
impairment recorded in 2019; and
decreased project income of $4.3 million at Cadillac primarily due to the fire in September 2019, resulting
in $1.4 million of operating losses related to the 45-day business interruption insurance deductible and a
$1.0 million insurance loss for the property and casualty loss deductible.
Natural Gas
Project income for 2019 increased $35.2 million from 2018 primarily due to:
•
•
•
•
•
increased project income of $16.9 million at Nipigon primarily due to a $17.8 million decrease in
amortization expense from accelerated amortization of the intangible PPA asset in 2018;
increased project income of $7.4 million at Manchief primarily due to a $7.1 million decrease in
maintenance expense from a turbine overhaul in 2018;
increased project income of $6.4 million at Tunis, primarily due to a $3.7 million decrease in maintenance
expense incurred in preparation for commencing operations in October 2018 and a $3.4 million increase in
project revenue;
increased project income of $6.3 million at our San Diego projects, which ceased operations in February
2018 and recorded higher asset retirement obligations in 2018; and
increased project income of $2.1 million at Frederickson primarily due to higher dispatch than 2018.
These increases were partially offset by:
•
•
decreased project income of $2.4 million at Orlando primarily due to a $4.1 million decrease in the fair
value of natural gas swaps, partially offset by a capacity rate escalation under the PPA; and
decreased project income of $1.9 million at Oxnard due to an increase in fuel pricing in 2019.
Hydroelectric
Project income for 2019 increased $0.2 million from 2018 primarily due to:
•
increased project income of $11.5 million at Curtis Palmer primarily due to higher water flows than 2018.
This increase was partially offset by:
•
decreased project income of $7.9 million at Koma primarily due to a $6.7 million gain in 2018 related to
the remeasurement of our previous 50% equity ownership of Koma to fair value resulting from the
acquisition of the remaining 50% in July of 2018; and
•
decreased project income of $2.2 million at Mamquam primarily due to lower water flows than 2018.
51
Corporate
Total project loss increased $7.3 million from 2018 primarily due to a $6.5 million decrease in fair value of
interest rate swap agreements and settlements of forward gas contracts.
Discussion of Corporate segment items not included in project income (loss):
Administrative and other expenses (income)
Administrative and other expenses (income) includes the income and expenses not attributable to our projects
and which are allocated to the Corporate segment. These costs include the activities that support the executive and
administrative offices, capital structure, costs of being a public registrant, costs to develop future projects, interest costs
on our corporate obligations, the impact of foreign exchange fluctuations and corporate tax. Significant non-cash items
that impact Administrative and other expenses (income), which are subject to potentially significant fluctuations, include
the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our
Canadian dollar-denominated obligations and the related deferred income tax expense (benefit) associated with these
non-cash items.
Administration
Administration expense did not change materially from 2018.
Interest, net
Interest expense decreased $8.7 million from $52.7 million in 2018 to $44.0 million in 2019 primarily due to
lower outstanding debt balances than 2018, as well as a lower interest rate on our Term Loan.
Foreign exchange loss (gain)
Foreign exchange gain decreased by $34.7 million from a $22.8 million gain in 2018 to an $11.9 million loss in
2019 due to the revaluation of instruments denominated in Canadian dollars (primarily our Medium Term Notes
(“MTNs”) and convertible debentures). The Canadian dollar appreciated 4.8% against the U.S. dollar from
December 31, 2018 to December 31, 2019, as compared to an 8.7% decrease in 2018.
Other expense (income), net
Other income, net decreased $4.0 million in 2018 to other expense, net of $1.0 million in 2019 primarily due to
a $5.0 million change in the fair value of the conversion option of the Series E Debentures.
Income tax expense
Income tax expense for the year ended December 31, 2019 was $9.8 million. Expected income tax benefit for
the same period, based on the Canadian enacted statutory rate of 27%, was $9.2 million. The primary items impacting
the tax rate for the year ended December 31, 2019 were $7.7 million related to impairments and a net increase to the
Company’s valuation allowances of $5.7 million, consisting of $7.9 million increases in Canada and $2.2 million
decreases in the United States. In addition, the rate was further impacted by $2.2 million related to changes in tax rates,
$1.7 million relating to foreign exchange, $1.3 million relating to withholding and state taxes and $0.4 million of other
permanent differences.
52
2018 compared to 2017
The following tables summarize our consolidated results of operations and project (loss) income by reportable
Year ended December 31,
2018
2017
$ change % change
$ 130.9 $ 148.9 $ (18.0)
(7.9)
105.8
(122.8)
176.3
(148.7)
431.0
97.9
53.5
282.3
73.1
85.0
83.7
241.8
106.3
87.8
113.1
307.2
(33.2)
(2.8)
(29.4)
(65.4)
(12.1)%
(7.5)%
(69.7)%
(34.5)%
(31.2)%
(3.2)%
(26.0)%
(21.3)%
2.2
43.2
(1.8)
—
4.1
47.7
88.2
2.1
(54.8)
(17.5)
(101.1)
0.1
(171.2)
(47.4)
0.1
98.0
15.7
101.1
4.0
218.9
135.6
4.8 %
NM
(89.7)%
(100.0)%
NM
NM
NM
23.9
52.7
(22.8)
(3.0)
50.8
37.4
0.2
37.2
0.4
0.3
(11.5)
(39.1)
(2.6)
(52.9)
188.5
58.3
130.2
(5.2)
$ 36.8 $ (98.6) $ 135.4
23.6
64.2
16.3
(0.4)
103.7
(151.1)
(58.1)
(93.0)
5.6
1.3 %
(17.9)%
NM
NM
(51.0)%
NM
NM
NM
(92.9)%
NM
segment:
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (expense):
Change in fair value of derivative instruments
Equity in earnings (loss) of unconsolidated affiliates
Interest expense, net
Impairment
Other income, net
Project income (loss)
Administrative and other expenses (income):
Administration
Interest expense, net
Foreign exchange (gain) loss
Other income, net
Income (loss) from operations before income taxes
Income tax expense (benefit)
Net income (loss)
Net income attributable to preferred shares of a subsidiary company
Net income (loss) attributable to Atlantic Power Corporation
53
Project Income (Loss) by Segment
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (expense):
Change in fair value of derivative instruments
Equity in earnings of unconsolidated affiliates
Interest expense, net
Other (expense) income, net
Year Ended December 31, 2018
Consolidated
Solid Fuel Natural Gas Hydroelectric Corporate
Total
$ 37.4 $
41.6
4.8
83.8
38.3 $
56.3
44.6
139.2
55.2 $ — $
—
3.1
58.3
—
1.0
1.0
24.1
28.9
15.0
68.0
—
5.6
(1.7)
—
3.9
49.0
44.0
49.9
142.9
—
11.6
18.7
30.3
—
0.5
0.1
0.6
3.2
37.0
(0.1)
(3.1)
37.0
33.3 $
—
0.6
—
7.2
7.8
35.8 $
(1.0)
—
—
—
(1.0)
(0.6) $
130.9
97.9
53.5
282.3
73.1
85.0
83.7
241.8
2.2
43.2
(1.8)
4.1
47.7
88.2
Project income (loss)
$ 19.7 $
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (expense):
Change in fair value of derivative instruments
Equity in (loss) earnings of unconsolidated affiliates
Interest expense, net
Impairment
Other income, net
Project (loss) income
Year Ended December 31, 2017
Consolidated
Solid Fuel Natural Gas Hydroelectric Corporate
Total
$ 36.2 $
41.6
15.9
93.7
56.7 $
64.2
155.9
276.8
56.0 $ — $
—
3.5
59.5
—
1.0
1.0
24.6
29.2
21.6
75.4
81.7
45.6
73.7
201.0
—
13.3
17.4
30.7
—
(0.3)
0.4
0.1
148.9
105.8
176.3
431.0
106.3
87.8
113.1
307.2
8.1
(42.6)
(17.4)
(29.1)
0.1
(80.9)
$ (62.6) $
(7.9)
(12.9)
(0.1)
(57.3)
—
(78.2)
(2.4) $
—
0.7
—
(14.7)
—
(14.0)
14.8 $
1.9
—
—
—
—
1.9
2.8 $
2.1
(54.8)
(17.5)
(101.1)
0.1
(171.2)
(47.4)
Discussion of project income (loss) by reportable segment:
Solid Fuel
Project income for 2018 increased $82.3 million from 2017 primarily due to:
•
increased project income of $48.2 million at Chambers which recorded a $47.1 million impairment in the
year ended December 31, 2017;
54
•
•
increased project income of $27.4 million at Williams Lake primarily due to a $29.1 million long-lived
asset impairment recorded in 2017 and a $6.7 million decrease in depreciation expense resulting from the
long-lived asset impairment in 2017, partially offset by a $10.7 million decrease in project revenue due to
the terms of the energy purchase agreement extension that became effective in April 2018; and
increased project income of $7.9 million at Piedmont primarily due to $7.1 million of lower interest
expense and interest rate swap mark-to-market fair value adjustments resulting from the repayment of the
project-level debt, in full, in 2017.
Natural Gas
Project income for 2018 increased $35.7 million from 2017 primarily due to:
•
•
•
•
•
decreased project loss of $34.8 million at Frederickson which recorded a $28.3 million impairment in 2017;
decreased project loss of $16.5 million, $13.9 million and $7.5 million at Naval Station, North Island and
NTC primarily due to $22.5 million, $21.2 million and $13.5 million of long-lived asset impairments
recorded in 2017, respectively. These projects ceased operations in February 2018;
increased project income of $10.6 million at Selkirk primarily due to a $10.6 million impairment recorded
for the year ended December 31, 2017;
increased project income of $5.3 million at Orlando primarily due to higher generation and a higher
capacity rate than 2017; and
increased project income of $5.7 million at Morris primarily due to higher energy and capacity revenues
than 2017.
These increases were partially offset by:
•
•
•
•
decreased project income of $21.0 million at North Bay primarily due to $37.2 million of revenue recorded
related to the OEFC settlement and the expiration of the enhanced dispatch contract in 2017, partially offset
by a $13.5 million decrease in depreciation expense;
decreased project income of $20.4 million at Kapuskasing primarily due to $39.0 million of revenue
recorded related to the OEFC settlement and the expiration of the enhanced dispatch contract in 2017,
partially offset by a $16.3 million decrease in depreciation expense;
decreased project income of $9.4 million at Tunis primarily due to $6.8 million of revenue recorded related
to the OEFC settlement in 2017 and a $3.3 million increase in maintenance expense in preparation of
commencing operations in October 2018; and
decreased project income of $5.5 million at Manchief primarily due to a $7.4 million increase in
maintenance expense from a turbine overhaul completed in 2018.
Hydroelectric
Project income for 2018 increased $21.0 million from 2017 primarily due to:
•
increased project income of $11.5 million at Curtis Palmer due primarily to a $14.7 million goodwill
impairment recorded in 2017, partially offset by a $3.2 million decrease in revenue from lower water flows
than 2017; and
55
•
increased project income of $6.6 million at Koma Kulshan primarily due to a $6.7 million gain in 2018
related to the remeasurement of our previous 50% equity ownership of Koma to fair value resulting from
the acquisition of the remaining 50% in July of 2018.
Corporate
Total project loss increased $3.4 million from 2017 primarily due to a $2.9 million decrease in fair value of
interest rate swap agreements and settlements of forward gas contracts.
Discussion of Corporate segment items not included in project income (loss):
Administrative and other expenses (income)
Administrative and other expenses (income) includes the income and expenses not attributable to our projects
and which are allocated to the Corporate segment. These costs include the activities that support the executive and
administrative offices, capital structure, costs of being a public registrant, costs to develop future projects, interest costs
on our corporate obligations, the impact of foreign exchange fluctuations and corporate tax. Significant non-cash items
that impact Administrative and other expenses (income), which are subject to potentially significant fluctuations, include
the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our
Canadian dollar-denominated obligations and the related deferred income tax expense (benefit) associated with these
non-cash items.
Administration
Administration expense did not change materially from 2017.
Interest, net
Interest expense decreased $11.5 million from $64.2 million in 2017 to $52.7 million in 2018 primarily due to
lower outstanding debt balances than 2017, as well as a lower interest rate on our Term Loan.
Foreign exchange (gain) loss
Foreign exchange gain increased by $39.1 million from a $16.3 million loss in 2017 to a $22.8 million gain in
2018 due to the revaluation of instruments denominated in Canadian dollars (primarily our MTNs and convertible
debentures). The Canadian dollar depreciated 8.7% against the U.S. dollar from December 31, 2017 to December 31,
2018, as compared to a 6.6% increase in 2017. Additionally, our Canadian dollar obligations increased from 2017 as a
result of the convertible debenture issuance in the first quarter of 2018.
Other income, net
Other income, net increased $2.6 million from 2017 primarily due to a $3.2 million unrealized gain recorded for
the fair value of the conversion option of the Series E Debentures.
Income tax expense
Income tax expense for the year ended December 31, 2018 was $0.2 million. Expected income tax expense for
the same period, based on the Canadian enacted statutory rate of 27%, was $10.1 million. The primary items impacting
the tax rate for the twelve months ended December 31, 2018 were $0.5 million relating to withholding and state taxes
and $0.7 million of other permanent differences. These items were offset by a net decrease to our valuation allowance of
$6.7 million, consisting of $0.1 million of decreases in Canada due to utilization of net operating losses and $6.6 million
decreases in the United States. Based on initiatives recently completed, we determined that sufficient deferred tax
liabilities were likely to reverse in a timely manner against certain deferred tax assets, resulting in a reduction of the
valuation allowance in the United States. In addition, the rate was further impacted by $3.3 million relating to changes in
56
tax rates and $1.1 million related to capital loss on intercompany notes.
Project Operating Performance
Two of the primary metrics we utilize to measure the operating performance of our projects are generation and
availability. Generation measures the net output of our proportionate project ownership percentage in GWhs.
Availability is calculated by dividing the total scheduled hours of a project less forced outage hours by the total hours in
the period measured. The terms of our PPAs require our projects to maintain certain levels of availability. The majority
of our projects were able to achieve substantially all of their respective capacity payments. The terms of our PPAs
provide for certain levels of planned and unplanned outages. All references below are denominated in thousands of Net
GWh.
Generation
(in Net GWh)
Segment
Solid Fuel
Natural Gas
Hydroelectric
Total
Year ended December 31,
2019
2018
2017
% change
2019 vs. 2018 2018 vs. 2017
% change
1,439.2 1,517.6 1,527.1
2,475.3 2,206.3 2,843.9
643.7
637.7
4,587.7 4,361.6 5,014.7
673.2
(5.2)%
12.2 %
5.6 %
5.2 %
(0.6)%
(22.4)%
(0.9)%
(13.0)%
Year ended December 31, 2019 compared with Year ended December 31, 2018
Aggregate power generation for 2019 increased 5.2% from 2018 primarily due to:
•
•
increased generation in the Natural Gas segment primarily due to a 317.9 net GWh increase in generation
at Frederickson due to higher dispatch than 2018 and a 32.5 GWh increase in generation at Manchief due to
higher dispatch than 2018, partially offset by a combined 95.5 net GWh decrease in generation at Naval
Station, Naval Training Center and North Island, which ceased operations in February 2018; and
increased generation in the Hydroelectric segment primarily due to an 88.4 net GWh increase in generation
at Curtis Palmer due to higher water flows than 2018, partially offset by a 47.2 net GWh decrease in
generation at Mamquam due to lower water flows than 2018.
These increases were partially offset by:
•
decreased generation in the Solid Fuel segment primarily due to a 204.5 net GWh decrease in generation at
Williams Lake due to lower wood fuel inventory and a 69.6 net GWh decrease at Cadillac due to the fire in
September 2019, partially offset by a combined 223.1 net GWh increase in generation at Allendale,
Dorchester, Craven and Grayling, which were acquired in 2019.
Year ended December 31, 2018 compared with Year ended December 31, 2017
Aggregate power generation for 2018 decreased 13% from 2017 primarily due to:
•
decreased generation in the Natural Gas segment primarily due to a combined 741.7 net GWh decrease in
generation at Naval Station, North Island and NTC, which ceased operations in February 2018, and a 111.3
net GWh decrease in generation at Frederickson due to milder weather than 2017, partially offset by a
188.4 net GWh increase in generation at Manchief due to higher dispatch than 2017.
57
Availability
Segment
Solid Fuel
Natural Gas
Hydroelectric
Weighted average
2019
2018
Year ended December 31,
% change
2019 vs. 2018 2018 vs. 2017
% change
2017
92.5 % 94.6 % 87.3 %
95.8 % 96.4 % 90.2 %
92.6 % 97.3 % 93.7 %
94.0 % 96.5 % 90.3 %
(2.2)%
(0.6)%
(4.8)%
(2.6)%
8.4 %
6.9 %
3.8 %
6.9 %
Year ended December 31, 2019 compared with Year ended December 31, 2018
Weighted average availability for 2019 decreased to 94.0% from 96.5% in 2018 primarily due to:
•
•
decreased availability in the Hydroelectric segment primarily due to a forced outage at Moresby Lake in
2019; and
decreased availability in the Solid Fuel segment primarily due to the fire at Cadillac in September 2019.
Year ended December 31, 2018 compared with Year ended December 31, 2017
Weighted average availability for 2018 increased to 96.5% from 90.3% in 2017 primarily due to:
•
•
•
increased availability in the Solid Fuel segment primarily due to a shorter maintenance outage at Piedmont
in 2018 than in 2017;
increased availability in the Natural Gas segment primarily due to maintenance outages at Frederickson,
Kenilworth and Orlando in 2017, partially offset by decreased availability at Manchief due to a
maintenance outage in the 2018 period; and
increased availability in the Hydroelectric segment primarily due to a maintenance outage at Mamquam in
2017.
58
Supplementary Non-GAAP Financial Information
Project Adjusted EBITDA
The key measurement we use to evaluate the results of our business is Project Adjusted EBITDA. Project
Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including
non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a
measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore
unlikely to be comparable to similar measures presented by other companies. We believe that Project Adjusted EBITDA
is a useful measure of financial results at our projects because it excludes non-cash impairment charges, gains or losses
on the sale of assets and non-cash mark-to-market adjustments, all of which can affect year-to-year comparisons. Project
Adjusted EBITDA is before corporate overhead expense. The most directly comparable GAAP measure to Project
Adjusted EBITDA is Project income (loss). A reconciliation of Net (loss) income to Project income (loss) and to Project
Adjusted EBITDA is provided under “Project Adjusted EBITDA” below. Project Adjusted EBITDA for our equity
investments in unconsolidated affiliates is presented on a proportionately consolidated basis in the table below.
Net (loss) income
Income tax expense (benefit)
(Loss) income from operations before income taxes
Administration
Interest expense, net
Foreign exchange loss (gain)
Other expense (income), net
Project income (loss)
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization
Interest expense, net
Change in the fair value of derivative instruments
Impairment
Insurance loss
Other expense (income), net
Project Adjusted EBITDA
Project Adjusted EBITDA by segment
Solid Fuel
Natural Gas
Hydroelectric
Corporate
Total
Solid Fuel
$ change
Year ended December 31,
2018
2019
2019
2018
2017
$ (43.8) $ 37.2 $ (93.0) $ (81.0) $ 130.2
58.3
188.5
0.3
(11.5)
(39.1)
(2.6)
$ 46.8 $ 88.2 $ (47.4) $ (41.4) $ 135.6
(58.1)
(151.1)
23.6
64.2
16.3
(0.4)
9.6
(71.4)
—
(8.7)
34.7
4.0
9.8
(34.0)
23.9
44.0
11.9
1.0
0.2
37.4
23.9
52.7
(22.8)
(3.0)
80.7
2.5
8.9
55.0
1.0
1.2
(33.5)
(15.8)
(0.1)
(187.1)
—
(2.8)
$ 196.1 $ 185.1 $ 288.8 $ 10.0 $ (103.7)
133.2
19.2
(2.1)
187.1
—
(1.2)
(19.0)
(0.9)
11.1
55.0
1.0
5.2
99.7
3.4
(2.2)
—
—
(4.0)
32.7
108.2
55.5
(0.3)
(8.2)
(94.9)
0.3
(0.9)
$ 196.1 $ 185.1 $ 288.8 $ 11.0 $ (103.7)
54.9
185.3
47.2
1.4
(14.0)
17.8
8.0
(0.8)
46.7
90.4
47.5
0.5
The following table summarizes Project Adjusted EBITDA for our Solid Fuel segment for the periods
indicated:
2019
2018
Year ended December 31,
% change
2019 vs. 2018 2018 vs. 2017
% change
2017
Solid Fuel
Project Adjusted EBITDA
$ 32.7 $ 46.7 $ 54.9
(30)%
(15)%
59
Year ended December 31, 2019 compared with Year ended December 31, 2018
Project Adjusted EBITDA for 2019 decreased $14.0 million or 30% from 2018 primarily due to decreases in
Project Adjusted EBITDA of:
•
•
•
$9.0 million at Williams Lake primarily due to the extension of the energy purchase agreement that became
effective in April 2018 and expired in September 2019, which provided lower pass-through of costs than
the previous contract. The project also had lower generation than in 2018;
$4.0 million at Cadillac which has been non-operational since the fire in September 2019; and
$2.4 million at Chambers due to lower energy and steam demand, as well as lower prices on excess energy
than in 2018.
These decreases were partially offset by increases in Project Adjusted EBITDA of:
•
•
$0.9 million at Grayling, which was acquired in August 2019; and
$0.9 million at Allendale, which was acquired in July 2019.
Year ended December 31, 2018 compared with Year ended December 31, 2017
Project Adjusted EBITDA for 2018 decreased $8.2 million or 15% from 2017 primarily due to decreases in
Project Adjusted EBITDA of:
•
$8.4 million at Williams Lake due to lower gross margin under the extension of the energy purchase
agreement that became effective in April 2018, partially offset by cost reductions.
Natural Gas
The following table summarizes Project Adjusted EBITDA for our Natural Gas segment for the periods
indicated:
Year ended December 31,
% change
2019 vs 2018
2017
2018
% change
2018 vs 2017
2019
Natural Gas
Project Adjusted EBITDA
$ 108.2 $ 90.4 $ 185.3
20 %
(51)%
Year ended December 31, 2019 compared with Year ended December 31, 2018
Project Adjusted EBITDA for 2019 increased by $17.8 million or 20% from 2018 primarily due to increases in
Project Adjusted EBITDA of:
•
•
•
•
$7.4 million at Manchief primarily due to a $7.1 million decrease in maintenance expense from a turbine
overhaul in 2018;
$7.1 million at Tunis, primarily due to a $3.7 million decrease in maintenance expense incurred in
preparation for commencing operations in October 2018 and a $3.4 million increase in project revenue;
$2.1 million at Frederickson primarily due to higher dispatch than 2018;
$1.9 million at San Diego projects (which ceased operations in February 2018) due to losses incurred in the
comparable 2018 period; and
60
•
$1.7 million at Orlando primarily due to a capacity rate escalation under the PPA.
These increases were partially offset by decreases in Project Adjusted EBITDA of:
•
•
$2.1 million at Oxnard due to an increase in fuel pricing and higher operating costs in 2019; and
$1.1 million at Morris mostly due to higher maintenance expenses in 2019.
Year ended December 31, 2018 compared with Year ended December 31, 2017
Project Adjusted EBITDA for 2018 decreased by $94.9 million or 51% from 2017 primarily due to decreases in
Project Adjusted EBITDA of:
•
•
•
•
$36.7 million and $34.5 million at Kapuskasing and North Bay, respectively, due to the expiration of the
enhanced dispatch agreements in December 2017 and the OEFC settlement received in 2017;
$9.3 million, $9.0 million and $5.7 million at Naval Station, North Island and NTC, respectively, which
ceased operations in February 2018;
$9.0 million at Tunis due to $6.8 million of revenue recorded related to the OEFC settlement in 2017 and
$3.0 million of higher maintenance expense incurred during 2018; and
$5.5 million at Manchief due to a $7.4 million increase in maintenance expense from a turbine overhaul,
offset by a $1.8 million increase in project revenue due to higher dispatch.
These decreases were partially offset by increases in Project Adjusted EBITDA of:
•
•
•
•
$7.4 million at Morris due to a higher capacity price, higher steam sales and ancillary revenue than 2017;
$3.0 million at Frederickson due to lower planned maintenance expense than 2017;
$2.8 million at Orlando due to higher availability and contractual capacity rates than 2017; and
$2.3 million at Nipigon due to a contractual rate increase and lower payroll expense than 2017.
Hydroelectric
The following table summarizes Project Adjusted EBITDA for our Hydroelectric segment for the periods
indicated:
Year Ended December 31,
% change
2019 vs. 2018 2018 vs. 2017
% change
2017
2018
2019
Hydroelectric
Project Adjusted EBITDA
$ 55.5 $ 47.5 $ 47.2
17 %
1 %
Year ended December 31, 2019 compared with Year ended December 31, 2018
Project Adjusted EBITDA for 2019 increased by $8.0 million or 17% from 2018 primarily due to an increase in
Project Adjusted EBITDA of:
•
$11.5 million at Curtis Palmer primarily due to higher water flows than 2018.
61
This increase was partially offset by decreases in Project Adjusted EBITDA of:
•
•
$2.2 million at Mamquam primarily due to lower water flows than in 2018; and
$1.3 million at Moresby Lake primarily due to lower generation resulting from a transformer failure in
2019.
Year ended December 31, 2018 compared with Year ended December 31, 2017
Project Adjusted EBITDA for 2018 increased by $0.3 million or 1% from 2017 primarily due to an increase in
Project Adjusted EBITDA of:
•
$3.3 million at Mamquam due to higher water flows and lower maintenance expense relative to 2017.
This increase was partially offset by a decrease in Project Adjusted EBITDA of:
•
$2.8 million at Curtis Palmer primarily due to $3.2 million of decreased project revenues from lower water
flows than in 2017.
Corporate
The following table summarizes Project Adjusted EBITDA for our Corporate segment for the periods indicated:
Corporate
Project Adjusted EBITDA
Year Ended December 31,
2019
2018
2017
% change % change
2019 vs. 2018 2018 vs. 2017
$ (0.3) $ 0.5 $ 1.4
NM
NM
Year ended December 31, 2019 compared with Year ended December 31, 2018
Project Adjusted EBITDA did not change materially from 2018.
Year ended December 31, 2018 compared with Year ended December 31, 2017
• Project Adjusted EBITDA did not change materially from 2017.
Liquidity and Capital Resources
Cash and cash equivalents
Restricted cash
Total
Revolving credit facility availability
Total liquidity
December 31,
2019
December 31,
2018
$
$
74.9 $
7.7
82.6
121.7
204.3 $
68.3
2.1
70.4
123.1
193.5
For the year ended December 31, 2019, our total liquidity increased $10.8 million. Changes in cash and cash
equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Restricted cash increased
$5.6 million from 2018 primarily due to insurance proceeds received at Cadillac that are restricted for use in the
reconstruction of the plant. We believe that our liquidity position and cash flows from operations will be adequate to
62
maintain our operations and meet obligations as they become due for at least the next 12 months from February 26,
2020.
Sources of Liquidity
Our primary source of liquidity is distributions from our projects and availability under our Revolver (as
defined herein). Our liquidity depends in part on our ability to successfully enter into new PPAs at projects when PPAs
expire or terminate. PPAs in our portfolio have expiration dates ranging from May 2020 to November 2043. We
currently have two projects with PPAs with expiration dates in 2020, Calstock and Oxnard. When a PPA expires or is
terminated, it may be difficult for us to secure a new PPA, if at all, or the price received by the project for power under
subsequent arrangements may be reduced significantly. As a result, this may reduce the cash received from project
distributions and the cash available for further debt reduction, identification of and investment in accretive growth
opportunities (both internal and external), to the extent available, and other allocation of available cash. See “Risk
Factors—Risks Related to Economic and Financial Market Conditions—We may not generate sufficient cash flow to
service our debt obligations or implement our business plan, including financing external growth opportunities or fund
our operations.”
Uses of Liquidity
Capital and Maintenance Expenditures
Our commercial operations require a significant amount of capital and maintenance expenditures. Capital
expenditures and maintenance expenses for the projects are generally paid at the project level using project cash flows
and project reserves. Therefore, the distributions that we receive from the projects are made net of capital expenditures
needed at the projects. The operating projects which we own consist of large capital assets that have established
commercial operations. On-going capital expenditures for assets of this nature are generally not significant because most
major expenditures relate to planned repairs and maintenance and are expensed when incurred. We invested
approximately $26.1 million of project capital expenditures and maintenance expenses (excluding $5.1 million of
Cadillac reconstruction costs) for the year ended December 31, 2019. In all cases, scheduled maintenance outages during
the year ended December 31, 2019 occurred at such times that did not adversely impact the facilities’ availability
requirements under their respective PPAs.
We expect to reinvest approximately $36.8 million in 2020 in our portfolio (excluding reconstruction cost at
Cadillac) in the form of maintenance expenses and project capital expenditures. As explained above, these investments
are generally paid at the project level. We believe one of the benefits of our diverse fleet is that plant overhauls and other
major expenditures do not occur in the same year for each facility. Recognized industry guidelines and original
equipment manufacturer recommendations provide a source of data to assess maintenance needs. In addition, we utilize
predictive and risk-based analysis to refine our expectations, prioritize our spending and balance the funding
requirements necessary for these expenditures over time. Future capital expenditures and maintenance expenses may
exceed the projected 2020 level as a result of the timing of more infrequent events such as steam turbine overhauls
and/or gas turbine and hydroelectric turbine upgrades. All remaining costs for the repair and reconstruction of our
Cadillac plant are expected to be paid with insurance proceeds. Repair costs exceeded the $1 million deductible in 2019.
There may be timing differences between the period of when costs are accumulated and insurance proceeds are received.
Acquisitions
In August 2019, we acquired equity ownership interests in Craven and Grayling for $18.7 million and in July
2019, we completed our acquisition of Dorchester and Allendale, paying the remaining $10.0 million of the total
$12.6 million purchase price. The initial $2.6 million deposit was made in 2018.
Debt Service and Redemptions
During the year ended December 31, 2019, we made $70 million of principal payments on the Term Loan and
$2.3 million on Cadillac’s term loan. Additionally, in April 2019, we redeemed, in full, the aggregate principal amount
63
of Cdn$24.7 million ($18.5 million) of the outstanding Series D Debentures.
Debt Service Obligations - Corporate
The following table summarizes the maturities of our corporate debt at December 31, 2019:
Senior secured term loan facility(1)
MTNs
Convertible Debenture
Total Corporate Debt
Maturity
Date
April 2025
June 2036
January 2025
Remaining
Interest
Rates
Principal
Repayments 2020
2021
2022
2023
2024
4.55% - 4.79% $
5.95%
6.00%
$
380.0 $ 72.5 $ 93.0 $ 106.0 $ 60.0 $ 36.0 $
161.7
88.5
630.2 $ 72.5 $ 93.0 $ 106.0 $ 60.0 $ 36.0 $
—
—
—
—
—
—
—
—
—
—
Thereafter
12.5
161.7
88.5
262.7
(1)
The Credit Facility contains a mandatory amortization feature determined by using the greater of (i) 50% of the
cash flow of APLP and its subsidiaries that remains after the application of funds, in accordance with a
customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt service
on the Credit Facilities and the 5.95% Medium Term Notes due June 23, 2036 (“MTNs”), letters of credit costs
to meet the requirements of the debt service reserve account, debt service on other permitted debt of APLP
Holdings and its subsidiaries, capital expenditures permitted under the Credit Agreement, and payment on the
preferred equity issued by Atlantic Power Preferred Equity Ltd., a subsidiary of APLP Holdings or (ii) such
other amount up to 100% of the cash flow described in clause (i) above that is required to reduce the aggregate
principal amount of Term Loan outstanding to achieve a target principal amount that declines quarterly based
on a pre-determined specified schedule. Note that failing to meet the mandatory amortization requirements is
not an event of default, but could result in APLP Holdings being unable to make distributions to Atlantic Power
Corporation and Atlantic Power Preferred Equity Limited being unable to pay dividends to its shareholders. In
January 2020, APLP Holdings completed the repricing of the Term Loan. As a result of the repricing, the
interest rate margin on the Term Loan and the Revolver was reduced by 0.25% to LIBOR plus 2.50% with no
change to the 1.00% LIBOR floor. Additionally, APLP Holdings amended its existing Term Loan to extend the
maturity date by two years to April of 2025 and added customary new provisions relating to the replacement of
LIBOR as the benchmark for the Eurodollar Rate (as defined in the Credit Agreement) replacement. Targeted
debt balances were adjusted to reflect the previously announced anticipated closing of the sale of the
Company’s Manchief power plant in 2022, resulting in lower targeted debt repayment in 2020 and higher
targeted debt repayment in 2022 as compared to the previous schedule. The amortization profile in the table
above is based on principal payments according to the targeted principal amount described in (ii) above through
2022 based on the schedule as amended in January 2020. After 2022, the amortization profile is based on
(i) above and is an estimate, subject to change. See Note 12, Long-term debt to the consolidated financial
statements for more information on our Credit Facilities.
Debt Service Obligations - Project-Level
Project-level debt of our consolidated projects is secured by the respective project and its contracts with no
other recourse to us. Project-level debt generally amortizes during the term of the respective revenue-generating
contracts of the projects. The following table summarizes the maturities of project-level debt. The amounts represent our
share of the non-recourse project-level debt balances at December 31, 2019. Certain of the projects have more than one
tranche of debt outstanding with different maturities, different interest rates and/or debt containing variable interest rates.
Project-level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt
service coverage ratios are not attained. All project-level debt is non-recourse to us and substantially the entire principal
is amortized over the life of the projects’ PPAs. See Note 12, Long-term debt to the consolidated financial statements.
Although all of our projects with non-recourse loans are currently meeting their debt service requirements, we cannot
provide any assurances that our projects will generate enough future cash flow to meet any applicable ratio tests in order
to be able to make distributions to us.
64
The range of interest rates presented represents the rates in effect at December 31, 2019. The amounts listed
below are in millions of U.S. dollars, except as otherwise stated.
Maturity
Date
Range of
Interest Rates
Total
Remaining
Principal
Repayments 2020
2021
2022 2023
2024
Thereafter
Consolidated Projects:
Cadillac
Total Consolidated Projects
Equity Method Projects:
Chambers(1)
Total Equity Method Projects
Total Project-Level Debt
August 2025 6.26 % - 6.38 % $
December 2023 5.00 %
$
18.7 $ 3.9 $ 2.7 $ 3.3 $ 3.3 $ 3.7 $
3.7
18.7
3.3
2.7
3.9
3.3
—
38.5
38.5
—
57.2 $ 11.7 $ 11.5 $ 13.4 $ 15.1 $ 3.7 $
8.8 10.1 11.8
8.8 10.1 11.8
7.8
7.8
1.8
1.8
—
—
1.8
(1) The above table does not include our $1.1 million proportionate share of unamortized issuance premiums.
Repurchases of Securities
On December 31, 2018, we commenced a Normal Course Issuer Bid (“NCIB”) for each of our Series D and
Series E Debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity
Ltd. (“APPEL”), our wholly-owned subsidiary. During the year ended December 31, 2019, we repurchased and canceled
1,064,081 common shares at a total cost of approximately $2.5 million. Additionally, we repurchased and cancelled
427,500 shares of Series 1 Shares, 100,377 shares of Series 2 Shares and 148,311 shares of Series 3 Shares of APPEL at
a total cost of $8.0 million.
On December 31, 2019, we commenced a new NCIB for our Series E Debentures, our common shares and for
each series of the preferred shares of APPEL, our wholly-owned subsidiary. Under the NCIBs, our broker may purchase
up to 10% of the public float of our convertible debentures and common shares and up to 10% of the public float of
APPEL’s preferred shares, determined as of December 17, 2019, up to the following limits:
Convertible Debenture
Common Shares
Series 1 Preferred Shares
Series 2 Preferred Shares
Series 3 Preferred Shares
Maturity
Date
January 2025
Interest
Rates
Limit on Purchase
(Principal Amount)
Total Limit
6.00 % Cdn$ 11,500,000
Limit on Purchase
(Number of Shares)
Total Limit (1)
10,578,799
384,750
223,072
133,031
(1) Represented 10% of the public float of the common shares and 10% of the public float of the Preferred Shares.
The Board authorization permits the Company to repurchase common and preferred shares and convertible
debentures. Therefore, in addition to the current NCIBs, from time to time we may repurchase our securities, including
our common shares, our convertible debentures and our APPEL preferred shares through open market purchases,
including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the Exchange Act, NCIBs,
issuer self tender or substantial issuer bids, or in privately negotiated transactions. There can be no assurances as to the
amount, timing or prices of repurchases, which may vary based on market conditions, other market opportunities and
other factors. Any share repurchases outside of previously authorized NCIBs would be effected after taking into account
our then current cash position and then anticipated cash obligations or business opportunities. The NCIBs will expire on
December 30, 2020 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to
65
the NCIBs. In certain circumstances, we may be required to suspend the NCIBs under applicable law.
Subsequent to December 31, 2019 and through February 26, 2020, we have repurchased and cancelled
1,742,919 common shares at a cost of $4.1 million under the new NCIB. We also repurchased and cancelled 247,894
Series 1 Shares at a cost of $3.1 million.
Dividends from preferred shares issued by a subsidiary company
In 2007, a subsidiary acquired in our acquisition of the Partnership issued 5.0 million 4.85% Cumulative
Redeemable Preferred Shares, Series 1 (the “Series 1 Shares”) priced at Cdn$25.00 per share. Cumulative dividends are
payable on a quarterly basis. The Series 1 Shares are redeemable by the subsidiary company at Cdn$25.00 per share,
plus an amount equal to all accrued and unpaid dividends thereon. At December 31, 2019, there were 3,847,500 Series 1
Shares outstanding.
In 2009, a subsidiary company acquired in our acquisition of the Partnership issued 4.0 million 7.0%
Cumulative Rate Reset Preferred Shares, Series 2 (the “Series 2 Shares”) priced at Cdn$25.00 per share. The Series 2
Shares pays a fixed dividend when declared. The dividend on the Series 2 Shares is cumulative. Beginning on December
31, 2014 and each fifth-year anniversary thereafter, (i) the rate on the Series 2 shares is reset at a rate equal to the sum of
the then five-year Government of Canada bond yield and 4.18%, and (ii) holders of Series 2 Shares have the right,
subject to certain limitations, to convert their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the
“Series 3 Shares”) of the subsidiary. On December 31, 2019, the rate on the Series 2 Shares was reset to 5.67% and
holders of the Series 2 Shares converted 23,618 Series 2 Shares into Series 3 Shares.
The holders of Series 3 Shares are entitled to receive quarterly floating rate dividends, as and when declared by
the board of directors of the subsidiary, at a rate equal to the sum of the then 90-day Government of Canada Treasury bill
rate and 4.18%. The dividend on the Series 3 Shares is cumulative. The dividend rate for the Series 3 Shares was reset on
December 31, 2019 to 5.83%. Beginning on December 31, 2019, and on each fifth-year anniversary thereafter, holders
of Series 3 Shares have the right, subject to certain limitations, to convert their shares into Series 2 Shares. On
December 31, 2019, the rate on the Series 3 Shares was reset to 5.83% and holders of the Series 3 Shares converted
295,032 Series 3 Shares into Series 2 Shares.
The Series 2 Shares and Series 3 Shares are redeemable by the subsidiary company at Cdn$25.00 per share,
plus an amount equal to all accrued and unpaid dividends thereon. At December 31, 2019, there were 2,504,131 Series 2
Shares and 1,077,391 Series 3 Shares outstanding.
The Series 1 Shares, the Series 2 Shares and the Series 3 Shares are fully and unconditionally guaranteed by us
and by the Partnership on a subordinated basis as to: (i) the payment of dividends, as and when declared; (ii) the
payment of amounts due on a redemption for cash; and (iii) the payment of amounts due on the liquidation, dissolution
or winding up of the subsidiary company. If, and for so long as, the declaration or payment of dividends on the Series 1
Shares, the Series 2 Shares or the Series 3 Shares is in arrears, the Partnership will not make any distributions on its
limited partnership units and we will not pay any dividends on our common shares.
The subsidiary company paid aggregate dividends of $7.4 million and $8.3 million on Series 1 Shares, Series 2
Shares and Series 3 Shares for the years ended December 31, 2019 and 2018, respectively.
Contributions to our pension plan
We expect to contribute $0.4 million to our pension plan in 2020.
66
Cash Flow Discussion
2019 compared to 2018
The following table reflects the changes in cash flows for the periods indicated:
Year ended
December 31,
2019
2018
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Operating Activities
$ 144.7 $ 137.5 $
(21.7)
(110.8)
(17.0)
(135.0)
Change
7.2
(4.7)
24.2
Cash flow from our projects may vary from year to year based on working capital requirements and the
operating performance of the projects, as well as changes in prices under PPAs, fuel supply and transportation
agreements, steam sales agreements and other project contracts, and the transition to merchant or re-contracted pricing
following the expiration of PPAs. Project cash flows may have some seasonality and the pattern and frequency of
distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have
a material impact on our business.
For the year ended December 31, 2019, the net increase in cash flows provided by operating activities of
$7.2 million was primarily the result of the following:
• Hydrological conditions – higher water flows at our Curtis Palmer project, partially offset by lower
water flows at our Mamquam and Moresby Lake projects, had an $8.0 million positive impact on cash
flows provided by operating activities;
• Major maintenance – we performed a planned major maintenance outage at our Manchief project in
2018 and had no such outage in the year ended December 31, 2019, resulting in a $7.4 million positive
impact on cash flows from operations;
• Tunis operations – the Tunis project commenced commercial operations in October 2018 and recorded
$3.4 million of higher revenue in the year ended December 31, 2019. Additionally, Tunis incurred
$3.9 million of lower maintenance expense in 2019. In 2018, Tunis incurred $5.0 million of non-
recurring maintenance expense to prepare the project for commercial operations; and
•
Interest – we made $3.7 million of lower interest payments than 2018 due to lower outstanding debt
balances and a lower interest rate on the Credit Facilities.
These increases were partially offset by decreases in net cash provided by operating activities that were
primarily the result of the following:
• Contract extension – the extension of the energy purchase agreement at Williams Lake that became
effective in April 2018 and expired in September 2019 provided lower pass-through of costs than the
previous contract. The project entered into a new energy purchase agreement that became effective in
October 2019, but the plant did not operate until late December, resulting in lower dispatch than 2018.
These factors resulted in a $9.0 million negative impact on cash flows provided by operating activities;
• Working capital – changes in working capital resulted in a $4.8 million decrease in cash flows from
operating activities; and
67
• Distributions from unconsolidated affiliates – we received $2.1 million of lower distributions from our
unconsolidated affiliates.
Investing Activities
For the year ended December 31, 2019, the net increase in cash flows used in investing activities of
$4.7 million was primarily the result of the following:
• Acquisitions – we paid $27.3 million net of cash received during 2019 for the completion of the
acquisitions of Dorchester, Allendale and for the acquisition of equity interests in Craven and
Grayling, as compared to $15.4 million in 2018 for the step acquisition of Koma and the deposit paid
for Dorchester and Allendale; and
• Purchases of PP&E – investments in capitalized plant additions were $5.5 million higher than 2018,
primarily due to $5.1 million of capitalized additions at Cadillac, which is undergoing repairs related
to the fire.
These increases were partially offset by the following:
•
Insurance recoveries– we received $11.3 million of property and casualty insurance recoveries related
to the fire at Cadillac in the fourth quarter of 2019; and
• Proceeds from asset sales – we received $1.6 million of cash proceeds from the sale of equipment at
our San Diego projects in 2019.
Financing Activities
For the year ended December 31, 2019, the net decrease in cash flows used in financing activities of
$24.2 million was primarily the result of the following:
• Convertible debenture redemptions – we paid $18.5 million to redeem and cancel the Series D
Debentures in full during the year ended December 31, 2019. In 2018, we paid $88.1 million to
redeem and cancel the Series C Debentures, in full, and the Series D Debentures, in part, with proceeds
from the issuance of the Series E Debentures;
• Corporate and project-level debt repayments – we made $28.0 million less principal payments than
2018;
• Common share repurchases – we paid $2.5 million in 2019 to repurchase and cancel common shares
as compared to $16.6 million in 2018; and
• Deferred financing costs – we incurred $5.1 million of deferred financing costs related to the issuance
of the Series E Debentures in 2018.
These decreases were partially offset by the following:
• Convertible debenture issuance – we received $92.2 million from the issuance of the Series E
Debentures in 2018.
68
2018 compared to 2017
The following table reflects the changes in cash flows for the periods indicated:
Year ended
December 31,
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Operating Activities
2018
2017
Change
$ 137.5 $ 169.2 $ (31.7)
(12.7)
43.9
(4.3)
(178.9)
(17.0)
(135.0)
Cash flow from our projects may vary from year to year based on working capital requirements and the
operating performance of the projects, as well as changes in prices under PPAs, fuel supply and transportation
agreements, steam sales agreements and other project contracts, and the transition to merchant or re-contracted pricing
following the expiration of PPAs. Project cash flows may have some seasonality and the pattern and frequency of
distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have
a material impact on our business.
For the year ended December 31, 2018, the net decrease in cash flows provided by operating activities of
$31.7 million was primarily the result of the following:
• Contract expirations – the expiration of the enhanced dispatch contracts at our North Bay and
Kapuskasing projects on December 31, 2017, as well as operations ceasing at our San Diego projects
in February 2018, had an approximate $72 million impact on cash flows from operations;
• OEFC Settlement – we received approximately $26.6 million related to our settlement with the OEFC
for the year December 31, 2017 and did not receive any payments in 2018; and
• Major maintenance – a planned major maintenance outage at our Manchief project had a $5.5 million
impact on cash flows from operations. Additionally, costs incurred to prepare our Tunis project for
commercial operations had a $3.3 million impact on cash flows from operations.
These decreases were partially offset by increases in net cash provided by operating activities that were
primarily the result of the following:
• Working capital – changes in working capital resulted in a $39.3 million increase in cash flows from
operating activities primarily due to a $20.6 million decrease in working capital at our Kapuskasing,
North Bay and San Diego projects, which were not in operation at December 31, 2018 but were under
contract in 2017;
•
Interest expense – our interest payments were $30.7 million lower than the comparable 2017 period
due to lower interest rates and outstanding principal on our Term Loan, the repayment of the Epsilon
Power Partners term facility, in full, in the second quarter of 2018 and the repayment of Piedmont’s
project-level debt, in full, in the fourth quarter of 2017; and
• Distributions from unconsolidated affiliates – we received $14.3 million in higher distributions from
our unconsolidated affiliates, primarily at our Orlando ($6.6 million increase), Chambers ($5.5 million
increase) and Frederickson ($2.0 million increase) projects.
69
Investing Activities
For the year ended December 31, 2018, the net increase in cash flows used in investing activities of
$12.7 million was primarily the result of the following:
• Acquisition of Koma Kulshan – we paid $12.8 million, net of cash received, to acquire an additional
0.25% ownership of Koma Kulshan in the second quarter of 2018 and the remaining 50% of Koma
Kulshan in the third quarter of 2018; and
• Deposit for acquisition – we made a $2.6 million down payment for the acquisition of two biomass
plants in South Carolina, which closed on July 31, 2019; and
• Proceeds from sale of equity investment – in 2017, we received $1.0 million from the sale of our
17.7% equity interest in Selkirk Cogen L.P.
These increases were partially offset by the following:
• Purchases of PP&E – investments in capitalized plant additions were $3.5 million lower than in 2017.
Financing Activities
For the year ended December 31, 2018, the net decrease in cash flows used in financing activities of
$43.9 million was primarily the result of the following:
• Convertible debenture redemptions – we paid $88.1 million to redeem and cancel the Series C
Debentures, in full, and the Series D Debentures, in part, with proceeds from the issuance of the Series
E Debentures;
• Common share repurchases – we paid $16.6 million in 2018 to repurchase and cancel common shares
as compared to $0.2 million in 2017;
• Preferred share repurchases – we paid $8.0 million in 2018 to repurchase and cancel preferred shares
as compared to $3.1 million in 2017; and
• Deferred financing costs – we incurred $5.1 million of deferred financing costs related to the issuance
of the Series E Debentures in 2018.
These decreases were partially offset by the following:
• Convertible debenture issuance – we received $92.2 million from the issuance of the Series E
Debentures; and
• Corporate and project-level debt repayments – we made $65.6 million of lower principal payments
than 2017 primarily due to the $54.6 million payment to retire Piedmont’s non-recourse project-level
debt in 2017.
70
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual obligations as of December 31, 2019:
Long-term debt including estimated interest(1)
Operating leases
Finance leases
Operations and maintenance commitments
Fuel purchase and transportation obligations
Other liabilities
Total contractual obligations
Payment Due by Period
Less than
1 year
1-3 Years 3-5 Years Thereafter Total
$ 106.5 $ 253.5 $ 138.2 $
1.2
0.1
0.4
5.0
3.1
1.5
0.2
0.6
10.2
—
0.6
—
—
—
—
$ 116.3 $ 266.0 $ 138.8 $
386.0 $ 884.2
3.3
0.3
1.0
15.2
5.8
388.7 $ 909.8
—
—
—
—
2.7
(1) Debt represents our proportionate share of project long-term debt and corporate-level debt. Project debt is
non-recourse to us and is generally amortized during the term of the respective revenue-generating contracts of the
projects. The range of interest rates on long-term consolidated project debt at December 31, 2019 was 4.55% to
6.38%.
Guarantees
We and our subsidiaries entered into various contracts that include indemnification and guarantee provisions as
a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint
venture agreements, operation and maintenance agreements, fuel purchase and transportation agreements and other types
of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify
the counterparty for certain tax, environmental liability, litigation and other matters, as well as breaches of
representations, warranties and covenants set forth in these agreements.
Off-Balance Sheet Arrangements
As of December 31, 2019, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of
Regulation S-K.
Critical Accounting Policies and Estimates
Accounting standards require information be included in financial statements about the risks and uncertainties
inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment.
Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated,
requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the
time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets
and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and
liabilities at the date of our financial statements. We routinely evaluate these estimates utilizing historical experience,
consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual
results may differ significantly from our estimates, and any effects on our business, financial position or results of
operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the
revision become known.
In preparing our consolidated financial statements and related disclosures, examples of certain areas that require
more judgment relative to others include our use of estimates in determining the useful lives and recoverability of
property, plant and equipment and PPAs, the recoverability of equity investments, the recoverability of goodwill, the
recoverability of deferred tax assets, the fair value of our derivatives instruments, and fair values of acquired assets.
71
For a summary of our significant accounting policies, see Note 2 to the consolidated financial statements. We
believe that certain accounting policies are of more significance in our consolidated financial statement preparation
process than others; these policies are discussed below.
Long-lived asset impairment
Long-lived assets, such as property, plant and equipment, and other intangible assets subject to depreciation and
amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying
amount of an asset group may not be recoverable. Examples of such indicators include, among other factors, a
significant decrease in the market price of a long-lived asset, adverse business climate, current period loss combined
with a history of losses or the projection of future losses, and a change in our intent to hold or a greater than 50%
likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life. We also review a
project for impairment at the earlier of executing a new PPA (or other arrangement) or six months prior to the expiration
of an existing PPA. Factors such as the business climate, including current energy and market conditions, environmental
regulation, the condition of assets, and the ability to secure new PPAs are considered when evaluating long-lived assets
for impairment.
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to
estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset
exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount
of the asset exceeds its fair value. Our asset groups have been determined to be at the plant level, which is the lowest
level in which independent, separately identifiable cash flows have been identified.
The valuation of long-lived assets is considered a level 3 fair value measurement, which means that the
valuation of the assets and liabilities reflect management’s own judgments regarding the assumptions market participants
would use in determining the fair value of the assets and liabilities. Fair value determinations require considerable
judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance
that the estimates and assumptions made for purposes of an impairment test will prove to be accurate predictions of the
future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key
assumptions and ultimately impact the estimated fair value of our asset groups may include macroeconomic factors that
significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and
maintenance costs, or lower power prices than incorporated in our long-term forecasts. See “Risk Factors—Risks
Related to Our Business and Our Projects—Impairment of goodwill or long-lived assets or equity method investments
could have a material adverse effect on our business, results of operations and financial condition”.
We recorded a $5.8 million long-lived asset impairment at Calstock in the year ended December 31, 2019. We
did not record any long-lived asset impairments in 2018. Previously, we recorded long-lived asset impairments of
$29.1 million, $22.5 million, $21.2 million and $13.5 million, respectively, at our Williams Lake, Naval Station, North
Island and Naval Training Center reporting units in the year ended December 31, 2017. See Item 15 — Note 8, Property,
plant and equipment, net for discussion of these impairments.
Equity method investment impairment – other than temporary
Investments in and the operating results of 50%-or-less owned entities not consolidated are included in the
consolidated financial statements on the basis of the equity method of accounting. The standard for determining whether
an impairment must be recorded is whether a decline in the value is considered an other-than-temporary decline in value.
The evaluation and measurement of impairments for our equity method investments involves the same uncertainties as
described for long-lived assets. Similarly, these estimates are subjective, and the impact of variations in these estimates
could be material. Evidence of a loss in value that is other than temporary might include the absence of an ability to
recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would
justify the carrying amount of the investment or, where applicable, estimated sales proceeds that are insufficient to
recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than
temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of
the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally
72
consider our investments in our equity method investees to be strategic long-term investments. Therefore, we complete
our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value
and the decline in value is considered to be other than temporary, the asset is written down to its fair value.
We recorded equity method investment impairments of $49.2 million at our Chambers project in the year
ended December 31, 2019. We did not record any equity method investment impairments in 2018. We previously
recorded equity method investment impairments of $47.1 million, $28.3 million and $10.1 million, respectively, at our
Chambers, Frederickson and Selkirk projects in the year ended December 31, 2017. See Item 15 — Note 6, Equity
method investments in unconsolidated affiliates for discussion of these impairments.
Goodwill
Goodwill is not amortized. Instead, it is reviewed for impairment annually (in the fourth quarter) or more
frequently if indicators of impairment exist. A significant amount of judgment is involved in determining if an indicator
of impairment has occurred. Such indicators may include a prolonged decline in our market capitalization, deterioration
in general economic conditions, adverse changes in the market in which a reporting unit operates, decreases in energy or
capacity revenues as the result of re-contracting or increases in input costs that have a negative effect on earnings and
cash flows, or a trend of negative or declining cash flows over multiple periods, among others. The fair value that could
be realized in an actual transaction may differ from that used to evaluate the impairment of goodwill. Our goodwill is
allocated among and evaluated for impairment at the reporting unit level, which is one level below our operating
segments.
We apply a standard that provides an entity the option to first assess qualitative factors to determine whether the
existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair
value of a reporting unit is less than its carrying amount. These factors include an assessment of macroeconomic and
industry conditions, market events and circumstances as well as the overall financial performance of our reporting units.
For our 2019 test, we elected to not perform a qualitative assessment at any of our three of our reporting units, given the
passage of time since a quantitative test had been performed for each reporting unit.
Under the quantitative impairment test, the evaluation of impairment involves comparing the current fair value
of each reporting unit to its carrying value, including goodwill. In January 2017, the FASB issued authoritative guidance,
which removed the requirement to perform a hypothetical purchase price allocation to measure goodwill impairment.
Under this guidance, goodwill impairment is measured as the amount by which a reporting unit’s carrying value exceeds
its fair value, not to exceed the carrying amount of goodwill. We early adopted this guidance for our annual goodwill
impairment tests beginning in November 2017.
We determine the fair value of our reporting units using an income approach with discounted cash flow models
(“DCF”), as we believe forecasted cash flows are the best indicator of such fair value. A number of significant
assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including
assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure
requirements. The undiscounted and discounted cash flows utilized in our long-lived asset recovery, equity method
investment, and goodwill impairment tests for our reporting units are generally based on approved reporting unit
operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All
cash flow forecasts from DCF models utilize estimated plant output for determining assumptions around future
generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical
experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models
represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the
particular reporting unit and is based upon an assumed capital structure, cost of long-term debt and cost of equity
consistent with comparable independent power producers. The fair value that could be realized in an actual transaction
may differ from that used to evaluate the impairment of our reporting units.
We did not record any goodwill impairments in 2019 or 2018. We previously recorded a goodwill impairment
of $14.7 million at our Curtis Palmer reporting unit in the year ended December 31, 2017. See Item 15 — Note 9,
Goodwill for discussion of these impairments.
73
Fair value of derivatives
We utilize derivative contracts to mitigate our exposure to fluctuations in fuel commodity prices and foreign
currency rates and to balance our exposure to variable interest rates. We believe that these derivatives are generally
effective in realizing these objectives. We also enter into long-term fuel purchase agreements accounted for as
derivatives that do not meet the scope exclusion for normal purchase or normal sales.
In determining fair value for our derivative assets and liabilities, we generally use the market approach and
incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about
market risk and/or the risks inherent in the inputs to the valuation techniques.
A fair value hierarchy exists for inputs used in measuring fair value that maximizes the use of observable
inputs (Level 1 or Level 2) and minimizes the use of unobservable inputs (Level 3) by requiring that the observable
inputs be used when available. Our derivative interest rate swap, fuel purchase agreements and fuel swaps are classified
as Level 2. The fair values of our derivative instruments are based upon trades in liquid markets. Valuation model inputs
can generally be verified with market data and valuation techniques do not involve significant judgment. We use our best
estimates to determine the fair value of commodity and derivative contracts we hold. These estimates consider various
factors including closing exchange prices, time value, volatility factors and credit exposure. The fair value of each
contract is discounted using a risk-free interest rate. We also adjust the fair value of financial assets and liabilities to
reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. The
conversion option derivative for the Series E Debentures is classified within Level 3 of the fair value hierarchy. The
significant unobservable inputs used in developing fair value include the volatility of our common shares and the fair
value of the host contract, which is derived from recent similar convertible debenture offerings from peer companies. A
discounted cash flow valuation technique is utilized to calculate to fair value of the conversion option derivative.
Certain derivative instruments qualify for a scope exception to fair value accounting, as they are considered
normal purchases or normal sales. The availability of this exception is based upon the assumption that we have the
ability and it is probable to deliver or take delivery of the underlying physical commodity. Derivatives that are
considered to be normal purchases and normal sales are exempt from derivative accounting treatment and are recorded
as executory contracts.
Acquired assets
When we acquire a business, a portion of the purchase price is typically allocated to identifiable assets, such as
property, plant and equipment, PPAs or fuel supply agreements. Fair value of these assets is determined primarily using
the income approach, which requires us to project future cash flows and apply an appropriate discount rate. We amortize
tangible and intangible assets with finite lives over their expected useful lives. Our estimates are based upon assumptions
believed to be reasonable, but which are inherently uncertain and unpredictable. Assumptions may be incomplete or
inaccurate, and unanticipated events and circumstances may occur. Incorrect estimates and assumptions could result in
future impairment charges, and those charges could be material to our results of operations.
Accounting for insurance proceeds
We have insurance policies from various insurers which provides coverage for losses that may occur involving
our assets or operations of our projects. We record insurance recoveries for property losses only when we can reasonably
estimate the amount of an incurred loss for an event, or its range, and it is deemed probable that a recovery of that claim
will occur. Insurance proceeds received in excess of incurred losses will be accounted for as gain contingencies. The
assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is
estimable, often involves a series of complex judgments about future events. Anticipated reimbursements for lost profits,
or business interruption losses, are accounted for as a gain contingency because lost profits are not considered an
incurred loss. Further, all contingencies related to business interruption claims must be resolved before the
reimbursement can be recognized in earnings. For any insurance proceeds received that are unallocated from the insurer
and cover more than one type of loss (e.g., property, business interruption), we will allocate the proceeds to each type of
74
loss. Insurance recoveries are reviewed quarterly and estimates are adjusted to reflect the impact of all known
information, including advice of legal counsel, discussions with insurers and other information and events pertaining to a
particular matter.
During the three months ended December 31, 2019 and for the full year 2019, we received $11.3 million of
insurance proceeds, which were applied against the Cadillac insurance receivable of $24.2 million. Additionally, we
estimate anticipated insurance recoveries related to business interruption losses of $2.0 million for the three months
ended December 31, 2019. Anticipated reimbursements for business interruption losses were not recorded as of
December 31, 2019 as all contingencies related to these claims had not been resolved as of period end. We expect all
contingencies related to business interruption losses to be resolved once final payment is received from the insurers,
which is when we will recognize the reimbursements in earnings (loss).
Income taxes and valuation allowance for deferred tax assets
In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that
some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent
upon projected future taxable income in the United States and in Canada at each of our legal tax-paying entities and
available tax planning strategies. The valuation allowance is comprised primarily of provisions against available
Canadian and U.S. net operating loss carryforwards at specific legal tax-paying entities without sufficient projected
future taxable income to utilize the net operating losses. As of December 31, 2019, we have recorded a valuation
allowance of $145.4 million.
Recent Accounting Developments
See Item 15 — Note 2, Summary of Significant Accounting Policies, to the consolidated financial statements for
a discussion of recent accounting developments.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and
commodity prices, will affect our cash flows or the value of our holdings of financial instruments. The objective of
market risk management is to minimize the impact that market risks have on our cash flows as described in the following
paragraphs.
Our market risk-sensitive instruments and positions have been determined to be “other than trading.” Our
exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible
changes in fair value or future earnings that would occur assuming hypothetical future movements in fuel and electricity
commodity prices, currency exchange rates or interest rates. Our views on market risk are not necessarily indicative of
actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual
gains and losses will differ from those estimated based on actual fluctuations in fuel commodity prices, currency
exchange rates or interest rates and the timing of transactions. See Note 15, Accounting for derivative instruments and
hedging activities to the consolidated financial statements for additional information.
Fuel Commodity Market Risk
Our current and future cash flows are impacted by changes in electricity, natural gas, biomass and coal prices.
See “Item 1A. Risk Factors—Risks Related to Our Business and Our Projects—Our projects depend on third-party
suppliers under fuel supply agreements, and increases in fuel costs may adversely affect the results of the operations of
the projects.” We often employ (i) tolling structures, whereby an offtaker is responsible for fuel procurement,
(ii) long-term fuel contracts, where we lock in a set quantity of fuel at a predetermined price, or (iii) pass-through
arrangements, whereby the cost of fuel is borne by the ultimate offtaker. The combination of long-term energy sales and
fuel purchase agreements is generally designed to mitigate the impacts to cash flows of changes in commodity prices by
passing through changes in fuel prices to the buyer of the energy.
75
Natural Gas
Our strategy to mitigate future exposure to changes in natural gas prices at our projects consists of periodically
entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These
natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheets at fair value
and the changes in their fair market value are recorded in the consolidated statements of operations.
Our 50%-owned Orlando project is exposed to changes in natural gas prices. We have entered into various
natural gas swaps to effectively fix the price of 16.3 million MMBtu of future natural gas purchases at Orlando, which is
approximately 100% of our projected gas consumption through 2023. These contracts are accounted for as derivative
financial instruments and are recorded in the consolidated balance sheet at fair value at December 31, 2019. Changes in
the fair market value of these contracts are recorded in the consolidated statement of operations. Because we have fixed
the price of approximately 100% of our projected gas consumption, Orlando is not exposed to changes in the price of
natural gas through 2023.
Biomass
Biomass suppliers are generally small companies and unwilling or unable to enter into long-term contracts at a
fixed price, volume or term. At some plants, a significant portion of the cost of biomass fuel consists of the price of
diesel fuel used in forestry operations and over the road transportation of the fuel to the projects. A decline in major
industries such as pulp, paper and lumber can have a negative effect on the available biomass supply. Reduction in
volumes from the forestry sector can also impact availability and price.
Our Calstock project has six fuel suppliers, three of which provide up to 65% of its fuel requirements and are
under contract to provide fuel, with a tipping fee through the end of the PPA in May 2020. We are exposed to the
remaining 35% of the project’s estimated fuel requirements. A 10% per Ton change from our budgeted wood waste costs
at Calstock would have an estimated $0.2 million impact on forecasted cash distributions in 2020 based on planned
operations.
None of our other biomass projects have long-term biomass fuel contracts. A 10% per Ton change from our
budgeted wood waste cost based on planned operations would have the following approximate impact on forecasted cash
distributions in 2020 for each of these biomass plants:
• Allendale - $0.6 million
• Cadillac - $0.03 million
• Craven - $0.6 million
• Dorchester - $0.6 million
• Grayling - $0.2 million
• Piedmont - $1.2 million
• Williams Lake - $1.1 million
Coal
Our 40%-owned Chambers project is exposed to changes in coal prices. For 2020, we forecasted an average
coal price of $98 per Ton. A 10% change from our forecasted price would impact cash distributions in 2020 from
Chambers by an estimated $1.3 million based on planned operations.
Electricity Commodity Market Risk
Our current and future cash flows are impacted by changes in electricity prices at projects that operate with
PPAs that are based on spot market pricing or at projects that operate without a PPA. Our most significant exposure to
market power prices is at the Chambers and Morris projects.
76
At our 40%-owned Chambers project, plant capacity is sold forward pursuant to the PPA with our utility
customer. However, the project is economically dispatched, which impacts variable operating margins. For example,
during periods of low demand and low spot electricity prices, the project is dispatched less, which reduces the project’s
operating margin. In addition, the utility customer has the right to sell a portion of the output into the spot market if it is
economical to do so, and the Chambers project shares in the profit from these sales. This also adds some variability to
the project’s financial results. In 2020, projected cash distributions from Chambers would change by approximately
$0.8 million per 10% change in the PJM-East spot price of electricity.
At Morris, a portion of the capacity is contracted with the industrial customer through 2034. The remaining
capacity has been sold forward into the PJM capacity market through annual auctions covering the period through May
2022. The capacity revenues from these auctions generally represent the majority of the operating margin of the
uncontracted portion of the project. Energy associated with the capacity sold forward into the PJM market is generally
dispatched by PJM when economic to do so or when needed for other reasons. The project can also offer ancillary
services to the grid. The sale of energy and ancillary services from the uncontracted portion of the project is not at a
fixed price or margin and therefore can add variability to the project’s financial results. In 2020, projected cash
distributions from Morris would change by approximately $0.4 million per 10% change in the spot price of electricity
based on the forecasted level of approximately 200,000 MWh of grid sales and all other variables being held constant.
When a PPA expires or is terminated, it is possible that the price received by the project for power under
subsequent arrangements may be reduced and in some cases, significantly. Our projects may not be able to secure a new
agreement and could be exposed to sell power at spot market price. See Item 1A. “Risk Factors—Risk Related to Our
Business and Our Projects—The expiration or termination of our PPAs could have a material adverse impact on our
business, results of operations and financial condition.” It is possible that subsequent PPAs or the spot market may not
be available at prices that permit the operation of the project on a profitable basis. If this occurs, the affected project may
temporarily or permanently cease operations.
Foreign Currency Exchange Risk
We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates as we
generate cash flow in U.S. dollars and Canadian dollars. We currently have Canadian dollar payment obligations for
preferred dividends, interest on our Canadian dollar-denominated convertible debentures and our Medium Term Notes.
Principal and interest payments for our Term Loan as well as our U.S. dollar-denominated convertible debenture are
made in U.S. dollars. From time to time we will implement a hedging strategy for the purpose of mitigating the currency
risk impact on the future interest and principal payments, preferred dividends and other working capital requirements.
Currently, we expect Canadian dollar cash flows to exceed our Canadian dollar obligations in the upcoming years and,
accordingly, have not entered into any currency hedge positions.
The following table contains the components of recorded foreign exchange (gain) loss for the years ended
December 31, 2019, 2018, and 2017:
Year Ended December 31,
2018
2017
2019
Unrealized foreign exchange loss (gain):
Convertible debentures, corporate debt, and other
Foreign currency forwards
Realized foreign exchange (gain) loss
$
$
12.1 $
—
12.1
(0.2)
11.9 $
(22.2) $
0.1
(22.1)
(0.7)
(22.8) $
15.1
0.1
15.2
1.1
16.3
A 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar would have an
approximate impact of $25 million on the carrying value of our corporate debt and convertible debentures denominated
in Canadian dollars at December 31, 2019.
77
Interest Rate Risk
Changes in interest rates impact cash payments that are required on our debt instruments as approximately 98%
of our debt, including our share of the project-level debt associated with equity investments in affiliates, either bears
interest at variable rates or is not financially hedged through the use of interest rate swaps. After considering the impact
of interest rate swaps described below, a hypothetical change in the average interest rate of 100 basis points would
change annual interest costs, including interest expense at equity investments, by approximately $0.2 million at
December 31, 2019.
The Partnership
APLP Holdings has entered into several interest rate swap agreements to mitigate its exposure to changes in
interest at the Adjusted Eurodollar Rate. At December 31, 2019, these agreements totaled $370.6 million notional
amount of the remaining $380.0 million aggregate principal amount of borrowings under the Term Loan. These interest
rate swap agreements expire at various dates through March 31, 2022. Borrowings under the Term Loan bear interest at
a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 2.75%. Based on the terms of the Credit
Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00%, resulting in a minimum of a 3.75% all-in rate on
the Term Loan for the non-swapped portion of the remaining principal amount. The weighted average rate of these swap
agreements is 2.00%, resulting in an all-in rate of approximately 4.75% for $370.6.1 million of the Term Loan. In
February 2020, APLP Holdings entered into additional interest rate swap agreements. For the period beginning
March 31, 2020 through December 31, 2021, we mitigated exposure to changes in interest rates a one-month LIBOR
fixed rate of 1.39%. The notional amount of these interest rate swap agreements range between $9.4 million and
$45.0 million and are sized to the targeted debt balance payments over that period.
In February 2020, we amended the Term Loan to extend the maturity date by two years to April of 2025 and
added customary new provisions relating to the replacement of LIBOR as the benchmark for the Eurodollar Rate (as
defined in the Credit Agreement) replacement. Subsequent to the expiration of the outstanding interest rate swap
agreements on March 31, 2022, we are exposed to changes in interest at the Adjusted Eurodollar Rate or its replacement
through the maturity date of the Term Loan.
Cadillac
We have an interest rate swap at our consolidated Cadillac project to economically fix its exposure to changes
in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of
the forecasted interest payments under the project-level Cadillac debt and changes in its fair market value are recorded in
other comprehensive loss (“OCL”). The interest rate swap expires on September 30, 2025.
In accounting for the cash flow hedge, gains and losses on the derivative contract are reported in OCL, but only
to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain
from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net
loss. That is, for a cash flow hedge, all effective components of the derivative contract’s gains and losses are recorded in
OCL, pending occurrence of the expected transaction. OCL consists of those financial items that are included in
“Accumulated other comprehensive loss” in our accompanying consolidated balance sheets but not included in our net
loss. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, OCL changes by exactly as much as
the derivative contracts and there is no impact on net loss until the expected transaction occurs.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements are appended to the end of this Annual Report on Form 10-K, beginning
on page F-1.
78
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a)
Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer have evaluated the company’s disclosure controls and
procedures, as defined in Rules 13a- 15(e) and 15d-15(e) of the Exchange Act, as of the end of the period covered by
this report, and have concluded that these controls and procedures were effective.
Our management, including our Chief Executive Officer and our Chief Financial Officer, concluded that the
consolidated financial statements in this Annual Report on Form 10-K fairly present, in all material respects, the
Company’s financial condition, results of operations and cash flows for the periods presented, in conformity with
GAAP.
(b)
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial
reporting as defined in Rules 13a-15(f) and 15d-14(f) under the Exchange Act. Under the supervision and with the
participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an
evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019 using the criteria
established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission (“COSO”).
Based on our evaluation under the COSO framework, management has concluded that our internal control over
financial reporting is effective as of December 31, 2019 to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
Because of their inherent limitations, our disclosure controls and procedures and our internal control over
financial reporting may not prevent errors or fraud. A control system, no matter how well conceived and operated, can
provide only reasonable, not absolute, assurance that the objectives of the control system are met. The effectiveness of
our disclosure controls and procedures and our internal control over financial reporting is subject to risks, including that
the controls may become inadequate because of changes in conditions or that the degree of compliance with our policies
or procedures may deteriorate.
The effectiveness of our internal control over financial reporting as of December 31, 2019 has been audited by
KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included in Item 15 of
this Annual Report on Form 10-K on page F-2.
(c)
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth fiscal quarter ended
December 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over
financial reporting.
ITEM 9B. OTHER INFORMATION
None.
79
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information concerning our directors and executive officers required by Item 10 will be included in the
Proxy Statement and is incorporated herein by reference.
We have adopted a code of ethics that applies to directors, managers, officers and employees. This code of
ethics, titled “Code of Business Conduct and Ethics,” is posted on our website. The internet address for our website is
www.atlanticpower.com, and the “Code of Business Conduct and Ethics” may be found from our main Web page by
clicking first on “About Us” and then on “Code of Conduct.”
We intend to satisfy any disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or
waiver from, a provision of the “Code of Business Conduct and Ethics” by posting such information on our website, on
the Web page found by clicking through to “Conduct of Conduct” as specified above.
ITEM 11. EXECUTIVE COMPENSATION
The information concerning our directors and executive officers required by Item 11 will be included in the
Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information concerning security ownership and other matters required by Item 12 will be included in the
Proxy Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information concerning certain relationships and related transactions required by Item 13 will be included
in the Proxy Statement and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information concerning principal accountant fees and services required by Item 14 will be included in the
Proxy Statement and is incorporated herein by reference.
80
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
PART IV
See “Index to Consolidated Financial Statements” on page F-1 of this Annual Report on Form 10-K.
(a)(2) Financial Statement Schedules
See “Index to Consolidated Financial Statements” on page F-1 of this Annual Report on Form 10-K. Schedules
other than that listed have been omitted because of the absence of the conditions under which they are required or
because the information required is shown in the consolidated financial statements or the notes thereto.
(a)(3) Exhibits
Exhibit
No.
2.1
2.2
3.1
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
EXHIBIT INDEX
Description
Plan of Arrangement of Atlantic Power Corporation, dated as of November 24, 2005
Arrangement Agreement, dated as of June 20, 2011, among Capital Power Income L.P., CPI Income
Services Ltd., CPI Investments Inc. and Atlantic Power Corporation
Articles of Continuance of Atlantic Power Corporation, dated as of June 29, 2010
Form of common share certificate
Trust Indenture, dated as of October 11, 2006 between Atlantic Power Corporation and Computershare
Trust Company of Canada
First Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Secured
Debentures, dated November 27, 2009, between Atlantic Power Corporation and Computershare Trust
Company of Canada
Trust Indenture Providing for the Issue of Convertible Unsecured Subordinated Debentures, dated as of
December 17, 2009, between Atlantic Power Corporation and Computershare Trust Company of Canada
Form of First Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible
Unsecured Subordinated Debentures, between Atlantic Power Corporation and Computershare Trust
Company of Canada
Second Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Unsecured
Subordinated Debentures, dated July 5, 2012, between Atlantic Power Corporation and Computershare
Trust Company of Canada
Third Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Unsecured
Subordinated Debentures, dated August 17, 2012, between Atlantic Power Corporation and
Computershare Trust Company of Canada
Fourth Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Unsecured
Subordinated Debentures, dated as of November 29, 2012, among Atlantic Power Corporation,
Computershare Trust Company of Canada and Computershare Trust Company, N.A.
Fifth Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Unsecured
Subordinated Debentures, dated as of December 11, 2012, among Atlantic Power Corporation,
Computershare Trust Company of Canada and Computershare Trust Company, N.A.
Sixth Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Unsecured
Subordinated Debentures, dated as of March 22, 2013, among Atlantic Power Corporation and
Computershare Trust Company of Canada
81
Exhibit
No.
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22*
10.1
10.2
10.3
10.4
Description
Seventh Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Unsecured
Subordinated Debentures, dated as of January 29, 2018, among Atlantic Power Corporation,
Computershare Trust Company of Canada and Computershare Trust Company, N.A.
Indenture, dated as of November 4, 2011, by and among Atlantic Power Corporation, the Guarantors
named therein and Wilmington Trust, National Association
First Supplemental Indenture, dated as of November 5, 2011, by and among the New Guarantors signatory
thereto, Atlantic Power Corporation, the Existing Guarantors named therein and Wilmington Trust,
National Association
Second Supplemental Indenture, dated as of November 5, 2011, by and among Curtis Palmer LLC,
Atlantic Power Corporation, the Guarantors named therein and Wilmington Trust, National Association
Third Supplemental Indenture, dated as of February 22, 2012, by and among Atlantic Oklahoma
Wind, LLC, Atlantic Power Corporation, the Guarantors named therein and Wilmington Trust, National
Association
Fourth Supplemental Indenture, dated as of August 3, 2012, by and among Atlantic Rockland
Holdings, LLC, Atlantic Power Corporation, the Guarantors named therein and Wilmington Trust,
National Association
Fifth Supplemental Indenture, dated as of November 29, 2012, by and among Atlantic Ridgeline
Holdings, LLC, Atlantic Power Corporation, the Guarantors named therein and Wilmington Trust,
National Association
Sixth Supplemental Indenture, dated as of January 29, 2013, by and among the New Guarantors named
therein, Atlantic Power Corporation, the Existing Guarantors named therein and Wilmington Trust,
National Association
Registration Rights Agreement, dated as of November 4, 2011, by and among, Atlantic Power
Corporation, the Guarantors listed on Schedule A thereto and Morgan Stanley & Co. LLC and
TD Securities (USA) LLC, as representatives of the several Initial Purchasers
Shareholder Rights Plan Agreement, dated effective as of February 28, 2013, between Atlantic Power
Corporation and Computershare Investor Services, Inc., which includes the Form of Right Certificate as
Exhibit A
Advance Notice Policy, dated April 1, 2013
Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange
Act of 1934
Credit and Guaranty Agreement, dated as of February 24, 2014, among Atlantic Power Limited
Partnership, as Borrower, Certain Subsidiaries of Atlantic Power Limited Partnership, as Guarantors,
Various Lenders, Goldman Sachs Bank USA and Bank of America, N.A., as L/C Issuers, Goldman Sachs
Lending Partners LLC and Bank of American, N.A., as Joint Syndication Agents, Goldman Sachs
Lending Partners LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Joint Lead Arrangers
and Joint Bookrunners, Union Bank, N.A. and RBC Capital Markets, as Revolver Joint Lead Arrangers
and Revolver Joint Bookrunners, Union Bank, N.A. and Royal Bank of Canada, as Revolver
Co- Documentation Agents, and Goldman Sachs Lending Partners LLC, as Administrative Agent and
Collateral Agent
Second Amended and Restated Credit Agreement dated August 2, 2013, as amended, among Atlantic
Power Corporation, Atlantic Power Generation, Inc. and Atlantic Power Transmission, Inc., the Lenders
signatory thereto and Bank of Montreal, as Administrative Agent
Consent, dated as of November 19, 2012, among Atlantic Power Corporation, Atlantic Power
Generation, Inc., Atlantic Power Transmission, Inc. the Lenders signatory thereto and Bank of Montreal,
as Administrative Agent
Consent and Release, dated as of January 15, 2013, among Atlantic Power Corporation, Atlantic Power
Generation, Inc., Atlantic Power Transmission, Inc., the Subsidiaries signatory thereto, the Lenders
signatory thereto and Bank of Montreal, as Administrative Agent and Collateral Agent
82
Exhibit
No.
10.5
10.6+
10.7+
10.8+
10.9+
10.10+
10.11+
10.12+
10.13
10.14
10.15
10.16+
10.17+
10.18
10.19
10.20
10.21
10.22+
10.23
10.24
Description
Modification and Joinder Agreement, dated as of January 15, 2013, among Atlantic Power Corporation,
Atlantic Power Generation, Inc., Atlantic Power Transmission, Inc., Ridgeline Energy LLC, PAH RAH
Holding Company LLC, Ridgeline Eastern Energy LLC, Ridgeline Energy Solar LLC, Lewis Ranch
Wind Project LLC, Hurricane Wind LLC, Ridgeline Power Services LLC, Ridgeline Energy
Holdings, Inc., Ridgeline Alternative Energy LLC, Frontier Solar LLC, PAH RAH Project
Company LLC, Monticello Hills Wind LLC, Dry Lots Wind LLC, Smokey Avenue Wind LLC, Saunders
Bros. Transportation Corporation, Bruce Hill Wind LLC, South Mountain Wind LLC, Great Basin Solar
Ranch LLC, Goshen Wind Holdings LLC, Meadow Creek Holdings LLC, Ridgeline Holdings Junior Inc.,
Rockland Wind Ridgeline Holdings LLC, Meadow Creek Intermediate Holdings LLC and the other
Subsidiaries party thereto in favor of Bank of Montreal, as Administrative Agent
Employment Agreement, dated April 15, 2013, between Atlantic Power Corporation and Terrence Ronan
Addendum to Executive Employment Agreements of each of Terrence Ronan and Edward Hall, dated
August 30, 2013
Deferred Share Unit Plan, dated as of April 24, 2007 of Atlantic Power Corporation
Third Amended and Restated Long-Term Incentive Plan
Fourth Amended and Restated Long-Term Incentive Plan
Fifth Amended and Restated Long-Term Incentive Plan
Amendment No. 1 to the Fifth Amended and Restated Long-Term Incentive Plan of the Company
Termination of the Operating Agreement of Canadian Hills Wind, LLC, dated as of December 28, 2012
Purchase and sale agreement, dated as of January 30, 2013 among Quantum Lake LP, LLC, Quantum
Lake GP, LLC, Quantum Pasco LP, LLC, Quantum Pasco GP, LLC, Quantum Auburndale LP, LLC and
Quantum Auburndale GP, LLC (as Buyers) and Lake Investment, LP, NCP Lake Power, LLC, Teton New
Lake, LLC, NCP Dadee Power, LLC, Dade Investment, LP, Auburndale, LLC and Auburndale GP, LLC
(as Sellers)
Agreement dated November 24, 2014, by and among Clinton Group and the Company
Employment Agreement among the Company, Atlantic Power Services, LLC and James J. Moore, Jr.,
dated January 22, 2015
Transition Equity Grant Participation Agreement between Atlantic Power Services, LLC and James J.
Moore, Jr., dated January 22, 2015
Membership Interest Purchase Agreement by and between Atlantic Power Transmission, Inc. and
Terraform AP Acquisition Holdings, LLC dated as of March 31, 2015
Guaranty Agreement by Atlantic Power Corporation in favor of Terraform AP Acquisition Holdings,
LLC, dated as of March 31, 2015
Agreement dated May 21, 2015, by and among Mangrove Partners and the Company
Amendment No.1 to Membership Interest Purchase Agreement, dated June 3, 2015
Employment Agreement among the Company, Atlantic Power Services, LLC and Joseph E. Cofelice,
dated September 15, 2015
Credit and Guaranty Agreement, dated as of April 13, 2016, among APLP Holdings Limited Partnership,
as Borrower, Atlantic Power Corporation, as guarantor, Certain Subsidiaries of APLP Holdings Limited
Partnership, as Guarantors, Various Lenders, Goldman Sachs Bank USA and Bank of America, N.A., as
L/C Issuers, Goldman Sachs Lending Partners LLC and Bank of America, N.A., as Joint Syndication
Agents, Goldman Sachs Lending Partners LLC as Administrative Agent and Collateral Agent, and
Goldman Sachs Lending Partners LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital
Markets, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Wells Fargo Securities, LLC, and Industrial and
Commercial Bank of China, in their respective capacities as Joint Lead Arrangers and Joint Bookrunners
Securities Pledge Agreement, dated as of April 13, 2016, among Atlantic Power Corporation, Atlantic
Power GP II, Inc. and Goldman Sachs Lending Partners LLC as Collateral Agent
83
Exhibit
No.
10.25
10.26
10.27
10.28
10.29+
10.30+
10.31+
10.32
10.33
10.34
16.1
21.1*
23.1*
31.1*
Description
Amendment dated April 17, 2017 to the Credit and Guaranty Agreement, dated as of April 13, 2016,
among APLP Holdings Limited Partnership, as Borrower, Atlantic Power Corporation, as guarantor,
Certain Subsidiaries of APLP Holdings Limited Partnership, as Guarantors, Various Lenders, Goldman
Sachs Bank USA and Bank of America, N.A., as L/C Issuers, Goldman Sachs Lending Partners LLC and
Bank of America, N.A., as Joint Syndication Agents, Goldman Sachs Lending Partners LLC as
Administrative Agent and Collateral Agent, and Goldman Sachs Lending Partners LLC, Merrill Lynch,
Pierce, Fenner & Smith Incorporated, RBC Capital Markets, The Bank of Tokyo-Mitsubishi UFJ, Ltd.,
Wells Fargo Securities, LLC, and Industrial and Commercial Bank of China, in their respective capacities
as Joint Lead Arrangers and Joint Bookrunners
Second Amendment dated October 18, 2017 to the Credit and Guaranty Agreement, dated as of April 13,
2016, among APLP Holdings Limited Partnership, as Borrower, Atlantic Power Corporation, as
guarantor, Certain Subsidiaries of APLP Holdings Limited Partnership, as Guarantors, Various Lenders,
Goldman Sachs Bank USA and Bank of America, N.A., as L/C Issuers, Goldman Sachs Lending Partners
LLC and Bank of America, N.A., as Joint Syndication Agents, Goldman Sachs Lending Partners LLC as
Administrative Agent and Collateral Agent, and Goldman Sachs Lending Partners LLC, Merrill Lynch,
Pierce, Fenner & Smith Incorporated, RBC Capital Markets, The Bank of Tokyo-Mitsubishi UFJ, Ltd.,
Wells Fargo Securities, LLC, and Industrial and Commercial Bank of China, in their respective capacities
as Joint Lead Arrangers and Joint Bookrunners
Amendment to Employment Agreement, by and among Atlantic Power Services, LLC, the Company and
Joseph Cofelice, dated as of February 27, 2018
Amendment No. 2 to the Fifth Amended and Restated Long-Term Incentive Plan of the Company
Sixth Amended and Restated Long-Term Incentive Plan
Amendment to Transition Equity Grant Participation Agreement between Atlantic Power Services, LLC
and James J. Moore, Jr., dated as of January 23, 2019
Form of Legacy Award Amendment
Third Amendment dated April 19, 2018 to the Credit and Guaranty Agreement, dated as of April 13,
2016, among APLP Holdings Limited Partnership, as Borrower, Atlantic Power Corporation, as
guarantor, Certain Subsidiaries of APLP Holdings Limited Partnership, as Guarantors, Various Lenders,
Goldman Sachs Bank USA and Bank of America, N.A., as L/C Issuers, Goldman Sachs Lending Partners
LLC and Bank of America, N.A., as Joint Syndication Agents, Goldman Sachs Lending Partners LLC as
Administrative Agent and Collateral Agent, and Goldman Sachs Lending Partners LLC, Merrill Lynch,
Pierce, Fenner & Smith Incorporated, RBC Capital Markets, The Bank of Tokyo-Mitsubishi UFJ, Ltd.,
Wells Fargo Securities, LLC, and Industrial and Commercial Bank of China, in their respective capacities
as Joint Lead Arrangers and Joint Bookrunners.
Fourth Amendment dated October 31, 2018 to the Credit and Guaranty Agreement, dated as of April 13,
2016, among APLP Holdings Limited Partnership, as Borrower, Atlantic Power Corporation, as
guarantor, Certain Subsidiaries of APLP Holdings Limited Partnership, as Guarantors, Various Lenders,
Goldman Sachs Bank USA and Bank of America, N.A., as L/C Issuers, Goldman Sachs Lending Partners
LLC and Bank of America, N.A., as Joint Syndication Agents, Goldman Sachs Lending Partners LLC as
Administrative Agent and Collateral Agent, and Goldman Sachs Lending Partners LLC, Merrill Lynch,
Pierce, Fenner & Smith Incorporated, RBC Capital Markets, The Bank of Tokyo-Mitsubishi UFJ, Ltd.,
Wells Fargo Securities, LLC, and Industrial and Commercial Bank of China, in their respective capacities
as Joint Lead Arrangers and Joint Bookrunners.
Fifth Amendment to the Credit Agreement, dated as of January 31, 2020, among APLP Holdings, the
Company and certain subsidiaries of APLP Holdings, as guarantors, Goldman Sachs Lending Partners
LLC, as administrative agent and collateral agent, and the other lenders and L/C issuers party thereto.
Letter from KPMG LLP, Chartered Accountants, to the Securities and Exchange Commission, dated
August 10, 2010
Subsidiaries of Atlantic Power Corporation
Consent of KPMG LLP
Certification of Chief Executive Officer pursuant to Rule 13a- 14(a)/15d-14(a) under the Exchange Act
84
Exhibit
No.
31.2*
32.1**
32.2**
101*
Description
Certification of Chief Financial Officer pursuant to Rule 13a- 14(a)/15d-14(a) under the Exchange Act
Certification of the Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
Certification of the Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
The following materials from our Annual Report on Form 10-K for the year ended December 31, 2019
formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets,
(ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Shareholders’ Equity,
(iv) the Consolidated Statements of Cash Flows, and (v) related notes to these financial statements
+ Indicates management contract or compensatory plan or arrangement.
* Filed herewith.
** Furnished herewith.
(b) Exhibits:
See Item 15(a)(3) above.
(c) Financial Statement Schedules:
See Item 15(a)(2) above.
ITEM 16. FORM 10-K SUMMARY.
None.
85
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 27, 2020
Atlantic Power Corporation
/s/ TERRENCE RONAN
By:
Name: Terrence Ronan
Title: Chief Financial Officer (Duly Authorized
Officer and Principal Financial and Accounting
Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the
following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ JAMES J. MOORE, JR.
James J. Moore, Jr.
President, Chief Executive Officer and Director
February 27, 2020
(principal executive officer)
/s/ TERRENCE RONAN
Terrence Ronan
Chief Financial Officer (Duly Authorized
Officer and Principal Financial and Accounting Officer)
February 27, 2020
/s/ KEVIN HOWELL
Kevin Howell
Chairman of the Board, Director
February 27, 2020
/s/ R. FOSTER DUNCAN
R. Foster Duncan
Director
/s/ DANIELLE S. MOTTOR
Danielle S. Mottor
Director
/s/ GILBERT S. PALTER
Gilbert S. Palter
Director
February 27, 2020
February 27, 2020
February 27, 2020
86
Atlantic Power Corporation
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Audited Financial Statements
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive (Loss) Income
Consolidated Statements of Shareholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Financial Statement Schedules
Schedule I — Condensed Financial Information of the Registrant
Schedule II—Valuation and Qualifying Accounts
Page
F-2
F-4
F-5
F-6
F-7
F-8
F-9
F-66
F-70
F-1
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
Atlantic Power Corporation:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Atlantic Power Corporation and subsidiaries (the Company) as of
December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive (loss) income, shareholders’ equity,
and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes, (and financial statement
schedules I to II) (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present
fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its
operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with
U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States)(PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in
Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission,
and our report dated February 27, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over
financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to
error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining,
on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2010.
New York, New York
February 27, 2020
F-2
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
Atlantic Power Corporation:
Opinion on Internal Control Over Financial Reporting
We have audited Atlantic Power Corporation and subsidiaries’ (the Company) internal control over financial reporting as of
December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of
operations, comprehensive (loss) income, shareholders’ equity, and cash flows for each of the years in the three-year period ended
December 31, 2019, and the related notes, (and financial statement schedules I to II) (collectively, the consolidated financial
statements) and our report dated February 27, 2020 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal
Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities
and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in
the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material
effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
New York, New York
February 27, 2020
F-3
ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of U.S. dollars)
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Insurance recovery receivable (Note 23)
Current portion of derivative instruments asset (Notes 14 and 15)
Inventory (Note 7)
Prepayments
Income taxes receivable (Note 16)
Lease receivable (Note 24)
Other current assets
Total current assets
Property, plant, and equipment, net (Note 8)
Equity investments in unconsolidated affiliates (Note 6)
Power purchase agreements and intangible assets, net (Note 10)
Goodwill (Note 9)
Derivative instruments asset (Notes 14 and 15)
Operating lease right-of-use assets (Note 24)
Deferred income taxes (Note 16)
Other assets
Total assets
Liabilities
Current liabilities:
Accounts payable
Accrued interest
Other accrued liabilities
Current portion of long-term debt (Note 12)
Current portion of derivative instruments liability (Notes 14 and 15)
Convertible debentures (Note 13)
Operating lease liabilities (Note 24)
Other current liabilities
Total current liabilities
Long-term debt, net of unamortized discount and deferred financing costs (Note 12)
Convertible debentures, net of discount and unamortized deferred financing costs (Note 13)
Derivative instruments liability (Notes 14 and 15)
Deferred income taxes (Note 16)
Power purchase agreements and intangible liabilities, net (Note 10)
Asset retirement obligations, net (Note 11)
Operating lease liabilities (Note 24)
Other long-term liabilities (Note 11)
Total liabilities
Equity
Common shares, no par value, unlimited authorized shares; 108,675,294 and 108,341,738 issued and
outstanding at December 31, 2019 and December 31, 2018 (Note 19)
Accumulated other comprehensive loss (Note 5)
Retained deficit
Total Atlantic Power Corporation shareholders’ equity
Preferred shares issued by a subsidiary company (Note 20)
Total equity
Total liabilities and equity
See accompanying notes to consolidated financial statements.
F-4
$
$
$
December 31,
2019
2018
$
$
$
74.9
7.7
30.4
13.5
0.7
18.6
3.8
1.8
0.9
0.4
152.7
502.1
96.6
144.3
21.3
—
6.3
10.4
1.9
935.6
8.9
2.6
20.8
76.4
12.0
—
2.0
0.2
122.9
473.5
81.1
15.9
23.7
19.8
51.5
4.8
4.7
797.9
68.3
2.1
35.7
—
4.2
15.8
4.0
0.3
—
5.9
136.3
549.5
140.8
170.1
21.3
0.3
—
7.0
6.2
1,031.5
2.5
2.3
20.2
68.1
4.5
18.1
—
0.2
115.9
540.7
75.7
15.4
16.0
21.2
49.2
—
5.0
839.1
1,259.9
(140.7)
(1,164.2)
(45.0)
182.7
137.7
935.6
1,260.9
(146.2)
(1,121.6)
(6.9)
199.3
192.4
1,031.5
$
$
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions of U.S. dollars, except per share amounts)
Year Ended December 31,
2018
2019
2017
Project revenue:
Energy sales (Note 4)
Energy capacity revenue (Note 4)
Other (Note 4)
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (loss):
Change in fair value of derivative instruments (Notes 14 and 15)
Equity in (loss) earnings of unconsolidated affiliates (Note 6)
Interest, net
Impairment (Note 9)
Insurance loss (Note 23)
Other (expense) income, net
Project income (loss)
Administrative and other expenses:
Administration
Interest expense, net
Foreign exchange loss (gain)
Other expense (income), net (Note 14)
(Loss) income from operations before income taxes
Income tax expense (Note 16)
Net (loss) income
Net (loss) income attributable to preferred shares of a subsidiary company (Note
20)
Net (loss) income attributable to Atlantic Power Corporation
Net (loss) earnings per share attributable to Atlantic Power Corporation
shareholders: (Note 21)
Basic
Diluted
Weighted average number of common shares outstanding: (Note 21)
Basic
Diluted
$
138.0 $ 130.9 $ 148.9
105.8
97.9
125.4
176.3
53.5
18.2
431.0
282.3
281.6
72.3
77.0
64.5
213.8
(8.9)
(3.0)
(1.1)
(5.8)
(1.0)
(1.2)
(21.0)
46.8
23.9
44.0
11.9
1.0
80.8
(34.0)
9.8
(43.8)
73.1
85.0
83.7
241.8
2.2
43.2
(1.8)
—
—
4.1
47.7
88.2
23.9
52.7
(22.8)
(3.0)
50.8
37.4
0.2
37.2
106.3
87.8
113.1
307.2
2.1
(54.8)
(17.5)
(101.1)
—
0.1
(171.2)
(47.4)
23.6
64.2
16.3
(0.4)
103.7
(151.1)
(58.1)
(93.0)
(1.2)
(42.6) $
0.4
36.8 $
5.6
(98.6)
$
$
(0.39) $
(0.39)
0.33 $
0.29
(0.86)
(0.86)
109.3
109.3
112.0
141.8
115.1
115.1
See accompanying notes to consolidated financial statements.
F-5
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(in millions of U.S. dollars)
Net (loss) income
Other comprehensive income, net of tax:
Unrealized (loss) gain on hedging activities
Net amount reclassified to earnings
Net realized and unrealized gain on derivatives
$
$
Defined benefit plan, net of tax
Foreign currency translation adjustments
Other comprehensive income (loss), net of tax
Comprehensive (loss) income
Less: Comprehensive (loss) income attributable to preferred shares of a subsidiary
company
Comprehensive (loss) income attributable to Atlantic Power Corporation
$
Year Ended December 31,
2018
37.2 $
2019
(43.8) $
2017
(93.0)
(0.3) $
0.3
—
(0.3)
5.8
5.5
(38.3)
0.4 $
0.1
0.5
0.2
(12.1)
(11.4)
25.8
(0.1)
0.5
0.4
(0.7)
14.0
13.7
(79.3)
(1.2)
(37.1) $
0.4
25.4 $
5.6
(84.9)
See accompanying notes to consolidated financial statements.
F-6
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in millions of U.S. dollars)
Common Common
Shares
(Shares)
Shares
(Amount)
Retained
Deficit
Accumulated Preferred
Other
Shares of a
Comprehensive Subsidiary Shareholders’
Company
(Loss) Income
Equity
Total
Balance at January 1, 2017
Net (loss) income
Share-based compensation
Common share repurchases
Preferred share repurchases
Dividends on preferred shares of a subsidiary company
- Series 1 (Cdn$1.212500 per share)
Dividends on preferred shares of a subsidiary company
- Series 2 (Cdn$1.392500 per share)
Dividends on preferred shares of a subsidiary company
- Series 3 (Cdn$1.182500 per share)
Realized and unrealized gain on hedging activities, net
of tax of $0.3 million
Foreign currency translation adjustments
Defined benefit plan, net of tax of $0.3 million
Balance at December 31, 2017
Net income
Share-based compensation
Common share repurchases
Preferred share repurchases
Dividends on preferred shares of a subsidiary company
- Series 1 (Cdn$1.212500 per share)
Dividends on preferred shares of a subsidiary company
- Series 2 (Cdn$1.392500 per share)
Dividends on preferred shares of a subsidiary company
- Series 3 (Cdn$1.327539 per share)
Realized and unrealized gain on hedging activities, net
of tax of $0.1 million
Foreign currency translation adjustments
Defined benefit plan, net of tax of $0.1 million
Balance as of December 31, 2018
Net loss
Share-based compensation
Common share repurchases
Preferred share repurchases
Dividends on preferred shares of a subsidiary company
- Series 1 (Cdn$1.212500 per share)
Dividends on preferred shares of a subsidiary company
- Series 2 (Cdn$1.392500 per share)
Dividends on preferred shares of a subsidiary company
- Series 3 (Cdn$1.459115 per share)
Foreign currency translation adjustments
Defined benefit plan, net of tax of $0.1 million
114.6 $
—
0.7
(0.1)
—
—
—
—
—
—
—
115.2 $
—
0.9
(7.8)
—
—
—
—
—
—
—
108.3 $
—
1.4
(1.1)
—
—
—
—
—
—
1,272.9 $ (1,059.8) $
—
2.1
(0.2)
—
—
—
—
—
—
—
(98.6)
—
—
—
—
—
—
—
—
—
1,274.8 $ (1,158.4) $
—
2.7
(16.6)
—
—
—
—
—
—
—
36.8
—
—
—
—
—
—
—
—
—
1,260.9 $ (1,121.6) $
—
1.5
(2.5)
—
—
—
—
—
—
(42.6)
—
—
—
—
—
—
—
—
(148.5) $
—
—
—
—
221.3 $
5.6
—
—
(3.1)
—
—
—
0.4
14.0
(0.7)
(4.6)
(2.5)
(1.5)
—
—
—
(134.8) $
—
—
—
—
215.2 $
0.4
—
—
(8.0)
—
—
—
0.5
(12.1)
0.2
(146.2) $
—
—
—
—
—
—
—
5.8
(0.3)
(4.2)
(2.5)
(1.6)
—
—
—
199.3 $
(1.2)
—
—
(8.0)
(3.5)
(2.4)
(1.5)
—
—
Balance as of December 31, 2019
108.6 $
1,259.9 $ (1,164.2) $
(140.7) $
182.7 $
See accompanying notes to consolidated financial statements.
285.9
(93.0)
2.1
(0.2)
(3.1)
(4.6)
(2.5)
(1.5)
0.4
14.0
(0.7)
196.8
37.2
2.7
(16.6)
(8.0)
(4.2)
(2.5)
(1.6)
0.5
(12.1)
0.2
192.4
(43.8)
1.5
(2.5)
(8.0)
(3.5)
(2.4)
(1.5)
5.8
(0.3)
137.7
F-7
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of U.S. dollars)
Cash provided by operating activities:
Net (loss) income
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization
(Gain) loss on disposal of fixed assets and inventory
Asset retirement obligations
Gain on step acquisition of equity investment
Share-based compensation
Impairment
Insurance loss
Equity in loss (earnings) from unconsolidated affiliates
Distributions from unconsolidated affiliates
Unrealized foreign exchange loss (gain)
Change in fair value of derivative instruments
Amortization of debt discount, deferred financing costs and operating lease right-of-use
assets
Deferred income taxes
Change in other operating balances
Accounts receivable
Inventory
Prepayments and other assets
Accounts payable
Accruals and other liabilities
Cash provided by operating activities
Cash used in investing activities:
Investment in unconsolidated affiliate
Insurance proceeds
Cash paid for acquisition, net of cash received
Deposit for acquisition
Proceeds from sales of assets and equity investments, net
Purchase of property, plant and equipment
Cash used in investing activities:
Cash used in financing activities:
Proceeds from convertible debenture issuance
Repayment of convertible debentures
Common share repurchases
Preferred share repurchases
Repayment of corporate and project-level debt
Cash payments for vested LTIP units, including amounts withheld for taxes
Deferred financing costs
Dividends paid to preferred shareholders
Cash used in financing activities:
Net increase (decrease) in cash, restricted cash and cash equivalents
Cash, restricted cash and cash equivalents at beginning of period
Cash, restricted cash and cash equivalents at end of period
Supplemental cash flow information
Interest paid
Income taxes paid, net
Accruals for construction in progress
Years Ended December 31,
2018
2019
2017
$
(43.8)
$
37.2
$
(93.0)
64.4
(0.9)
1.4
—
1.5
5.8
1.0
3.0
59.5
12.2
10.7
8.6
4.8
8.2
(1.8)
3.9
5.1
1.1
144.7
(18.7)
11.3
(8.6)
—
1.6
(7.3)
(21.7)
—
(18.5)
(2.5)
(8.0)
(72.3)
(2.1)
—
(7.4)
(110.8)
12.2
70.4
82.6
37.6
2.3
0.3
$
$
$
$
83.7
(0.4)
3.5
(7.2)
2.7
—
—
(43.2)
61.6
(22.0)
(5.5)
9.4
(3.6)
18.8
1.6
8.7
(1.2)
(6.6)
137.5
—
—
(12.8)
(2.6)
0.2
(1.8)
(17.0)
92.2
(88.1)
(16.6)
(8.0)
(100.3)
(0.8)
(5.1)
(8.3)
(135.0)
(14.5)
84.9
70.4
41.3
3.1
(1.5)
$
$
$
$
113.1
0.1
—
—
2.1
101.1
—
54.8
47.3
15.2
(2.1)
10.8
(62.2)
(15.4)
(1.6)
0.4
(0.9)
(0.5)
169.2
—
—
—
—
1.0
(5.3)
(4.3)
—
—
(0.2)
(3.1)
(165.9)
(0.7)
(0.3)
(8.7)
(178.9)
(14.0)
98.9
84.9
72.0
4.4
1.2
$
$
$
$
See accompanying notes to consolidated financial statements.
F-8
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in millions of U.S. dollars, except per-share amounts)
1. Nature of business
General
Atlantic Power is an independent power producer that owns power generation assets in eleven states in the
United States and two provinces in Canada. Our power generation projects, which are diversified by geography, fuel
type, dispatch profile and offtaker, sell electricity to utilities and other large customers predominantly under long-term
power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of
December 31, 2019, our portfolio consisted of twenty-one projects operating with an aggregate electric generating
capacity of approximately 1,723 megawatts (“MW”) on a gross ownership basis and approximately 1,327 MW on a net
ownership basis. Sixteen of the projects are majority-owned by the Company.
Atlantic Power is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004
and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the Toronto Stock Exchange
under the symbol “ATP” and on the New York Stock Exchange under the symbol “AT.” Our registered office is located
at 1066 West Hastings Street, Suite 2600, Vancouver, British Columbia V6E 3X1 Canada and our headquarters is
located at 3 Allied Drive, Suite 155, Dedham, Massachusetts 02026, USA.
2. Summary of significant accounting policies
(a)
Principles of consolidation and basis of presentation:
The accompanying consolidated financial statements are prepared in accordance with accounting principles
generally accepted in the United States of America (“GAAP”) and include the consolidated accounts and operations of
our subsidiaries in which we have a controlling financial interest. The usual condition for a controlling financial interest
is ownership of the majority of the voting interest of an entity. However, a controlling financial interest may also exist in
entities, such as a variable interest entity (“VIE”), through arrangements that do not involve controlling voting interests.
We apply the standard that requires consolidation of VIEs, for which we are the primary beneficiary. The
guidance requires a variable interest holder to consolidate a VIE if that party has both the power to direct the activities
that most significantly impact the entities’ economic performance, as well as either the obligation to absorb losses or the
right to receive benefits that could potentially be significant to the VIE. We have determined that our equity investments
are not VIEs by evaluating their design and capital structure. Accordingly, we use the equity method of accounting for
all of our investments in which we do not have an economic controlling interest. We eliminate all intercompany accounts
and transactions in consolidation.
(b)
Cash and cash equivalents:
Cash and cash equivalents include cash deposited at banks and highly liquid investments with original
maturities of 90 days or less when purchased.
(c)
Restricted cash:
Restricted cash represents cash, cash equivalents and cash advances that are maintained by the projects or
corporate to support payments for maintenance costs, reconstruction costs and meet project level and corporate
contractual debt obligations. Restricted cash is classified as a current or long-term asset based on the timing and nature
of when or how the cash is expected to be used or when the restrictions are expected to lapse.
F-9
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(d)
Accounts receivable:
Accounts Receivable are carried at cost. We periodically assesses the collectability of accounts receivable,
considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts
receivable and other currently available evidence of the collectability, and record an allowance for doubtful accounts for
the estimated uncollectible amount as appropriate. We had no allowance for doubtful accounts recorded at December 31,
2019 and 2018, respectively.
(e)
Deferred financing costs:
Deferred financing costs represent costs to obtain long-term financing and are amortized using the effective
interest method over the term of the related debt, which ranges from 1 to 6 years. The carrying amount of deferred
financing costs were recorded on the consolidated balance sheets as net of long-term debt and convertible debentures and
was $8.5 million and $11.8 million at December 31, 2019 and 2018, respectively. Interest expense from the amortization
of deferred financing costs for the years ended December 31, 2019, 2018, and 2017 was $3.2 million, $5.1 million, and
$6.3 million, respectively.
(f)
Inventory:
Inventory represents spare parts, biofuel and natural gas, the majority of which is consumed by our projects in
provision of their services, and are valued at the lower of cost and net realizable value. Cost is the sum of the purchase
price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. The
cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not
interchangeable, cost is assigned using specific identification of their individual costs.
(g)
Property, plant and equipment:
Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a
straight-line basis over the estimated useful life of the related asset. Significant additions or improvements extending
asset lives or increasing generating capacity are capitalized as incurred, while repairs and maintenance that do not
improve or extend the life of the respective asset are charged to expense as incurred.
(h)
Project development costs and capitalized interest:
Project development costs are expensed in the preliminary stages of a project and capitalized when the project
is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among
others, obtaining a PPA.
When a project is available for operations, capitalized interest and project development costs are reclassified to
property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project’s
related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines
the costs to be unrecoverable.
F-10
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(i)
Power Purchase Agreements and intangible assets:
Intangible assets include PPAs and fuel supply agreements at our projects acquired as part of business
combinations. Carrying amounts for PPAs and fuel supply agreements are based on the fair value assigned in the
allocation of the purchase price of the acquired business. The balances are presented net of accumulated amortization in
the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the
agreement.
(j)
Investments accounted for by the equity method:
We have investments in entities that own power-producing assets with the objective of generating cash flow.
The equity method of accounting is applied to such investments in affiliates, which include joint ventures, partnerships,
and limited liability companies because the ownership structure prevents us from exercising a controlling influence over
the operating and financial policies of the projects. Our investments in partnerships and limited liability companies with
50% or less ownership, but greater than 5% ownership in which we do not have a controlling interest are accounted for
under the equity method of accounting. We apply the equity method of accounting to investments in limited partnerships
and limited liability companies with greater than 5% ownership because our influence over the investment’s operating
and financial policies is considered to be more than minor.
Under the equity method, equity in pre-tax income or losses of our investments is reflected as equity in earnings
of unconsolidated affiliates in the consolidated statements of operations. We apply the nature of distributions method for
the classification of our investments accounted for by the equity method in the Consolidated Statements of Cash Flows.
The cash flows that are distributed to us from these unconsolidated affiliates are directly related to the operations of the
affiliates’ power-producing assets and are classified as cash flows from operating activities in the consolidated
statements of cash flows. We record the return of our investments in equity investees as cash flows from investing
activities. Cash flows from equity investees are considered a return of capital when distributions are generated from
proceeds of either the sale of our investment in its entirety or a sale by the investee of all or a portion of its capital assets.
(k)
Impairment of long-lived assets, intangible assets and equity method investments:
Long-lived assets, such as property, plant and equipment, and other intangible assets and liabilities subject to
depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that
the carrying amount of an asset group may not be recoverable. Recoverability of assets to be held and used is measured
by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated
by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment
charge is recognized in the amount by which the carrying amount of the asset group exceeds its fair value. Our asset
groups have been determined to be at the plant level, which is the lowest level in which independent, separately
identifiable cash flows have been identified. We also review a project for impairment at the earlier of executing a new
PPA (or other arrangement) or six months prior to the expiration of an existing PPA. Factors such as the business
climate, including current energy and market conditions, environmental regulation, the condition of assets, and the
ability to secure new PPAs are considered when evaluating long-lived assets for impairment.
Investments in and the operating results of 50%-or-less owned entities not consolidated are included in the
consolidated financial statements on the basis of the equity method of accounting. We review our investments in such
unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying
amount of the investments may not be fully recoverable. Evidence of a loss in value that is other than temporary might
include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain
an earnings capacity which would justify the carrying amount of the investment or, where applicable, estimated sales
proceeds that are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline
F-11
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating
the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the
contrary. We generally consider our investments in our equity method investees to be strategic long-term investments.
Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be
less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to
its estimated fair value.
(l)
Goodwill:
Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of
the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated, as
of the date of the business combination, to our reporting units that are expected to benefit from the synergies of the
business combination.
Goodwill is not amortized and is tested for impairment annually as of November 30, or more frequently if
events or changes in circumstances indicate that would more likely than not reduce the fair value of a reporting unit
below its carrying value.
In our test, we first perform step zero to determine whether the existence of events or circumstances leads to a
determination that it is more likely than not (i.e. more than 50%) that the fair value of a reporting unit is less than its
carrying amount. Such qualitative factors may include the following: macroeconomic conditions, industry and market
considerations, cost factors, overall financial performance and other relevant entity-specific events. If the qualitative
assessment determines that an impairment is more likely than not, then we perform a quantitative impairment test. In the
quantitative analysis, the carrying amount of the reporting unit is compared with its fair value. When the fair value of a
reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired. When the
carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to the
excess, not to exceed the carrying amount of goodwill, and is recorded in the consolidated statements of operations.
We determine the fair value of our reporting units using an income approach with discounted cash flow models
(“DCF”), as we believe forecasted cash flows are the best indicator of such fair value. A number of significant
assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including
assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure
requirements. The undiscounted and discounted cash flows utilized in our long-lived asset recovery, equity method
investment, and goodwill impairment tests for our reporting units are generally based on approved reporting unit
operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All
cash flow forecasts from DCF models utilize estimated plant output for determining assumptions around future
generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical
experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models
represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the
particular reporting unit and is based upon an assumed capital structure, cost of long-term debt and cost of equity
consistent with comparable independent power producers. The fair value that could be realized in an actual transaction
may differ from that used to evaluate the impairment of our reporting units.
The valuation of long-lived assets, equity method investments and goodwill for the impairment analyses is
considered a level 3 fair value measurement, which means that the valuation of the assets and liabilities reflect
management’s own judgments regarding the assumptions market participants would use in determining the fair value of
the assets and liabilities. Fair value determinations require considerable judgment and are sensitive to changes in these
underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for
purposes of an impairment test will prove to be accurate predictions of the future. Examples of events or circumstances
F-12
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the
estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our
assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power
prices than incorporated in our long-term forecasts.
(m)
Accounts payable and other accrued liabilities:
Accounts payable consists of amounts due to trade creditors related to our core business operations. These
payables include amounts owed to vendors and suppliers for items such as fuel, maintenance, inventory and other raw
materials. Other accrued liabilities include items such as income taxes, legal contingencies and employee-related costs
including payroll, benefits and related taxes.
(n)
Derivative financial instruments:
We use derivative financial instruments in the form of interest rate swaps and foreign exchange forward
contracts to manage our current and anticipated exposure to fluctuations in interest rates and foreign currency exchange
rates. We also separate the conversion option of certain convertible debentures from the host instrument and account for
it as an embedded derivative liability as the conversion option is in a currency different from our functional currency.
We have also entered into natural gas supply contracts and natural gas forwards or swaps to minimize the effects of the
price volatility of natural gas, which is a significant operating cost. We do not enter into derivative financial instruments
for trading or speculative purposes. Certain derivative instruments qualify for a scope exception to fair value accounting
because they are considered normal purchases or normal sales in the ordinary course of conducting business. This
exception applies when we have the ability to, and it is probable that we will deliver or take delivery of the underlying
physical commodity.
We have designated one of our interest rate swaps as a hedge of cash flows for accounting purposes. Tests are
performed to evaluate hedge effectiveness and ineffectiveness at inception and on an ongoing basis, both retroactively
and prospectively. Derivatives accounted for as hedges are recorded at fair value in the balance sheet. Unrealized gains
or losses on derivatives designated as a hedge for accounting purposes are deferred and recorded as a component of
accumulated other comprehensive (loss) income (“OCL”) until the hedged transactions occur and are recognized in
earnings. The ineffective portion of the cash flow hedge, if any, is immediately recognized in earnings.
Derivative financial instruments not designated as a hedge for accounting purposes are measured at fair value
with changes in fair value recorded in the consolidated statements of operations. Derivative financial instruments under
master netting arrangements are recorded net, when applicable, in the consolidated balance sheets. The following table
summarizes derivative financial instruments that are not designated as hedges for accounting purposes and the
accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of
such derivative financial instrument:
Derivative financial instrument
Natural gas swaps
Fuel purchase agreements
Interest rate swaps
Convertible debenture conversion
option
Foreign currency forward contract
Classification of changes in fair value
Classification of cash settlements
Changes in fair value of derivative instrument Fuel expense
Changes in fair value of derivative instrument Fuel expense
Changes in fair value of derivative instrument Interest expense
Other expense (income), net
Foreign exchange loss (gain)
NA
Foreign exchange loss (gain)
F-13
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(o)
Income taxes:
Income tax expense includes the current tax obligation or benefit and change in deferred income tax asset or
liability for the period. We use the asset and liability method of accounting for deferred income taxes and record
deferred income taxes for all significant temporary differences. Income tax benefits associated with uncertain tax
positions are recognized when we determine that it is more-likely-than-not that the tax position will be ultimately
sustained. Refer to Note 16 for more information.
(p)
Revenue recognition:
We recognize energy sales revenue on a gross basis when electricity and steam are delivered and capacity
revenue when capacity is provided under the terms of the related contracts. PPAs, steam purchase arrangements and
energy services agreements are long-term contracts with performance obligations to provide electricity, steam and
capacity on a predetermined basis.
For certain PPAs determined to be operating leases, we recognize lease income consistent with the recognition
of energy sales and capacity revenue. When energy is delivered and capacity is provided, we recognize lease income as a
component of energy sales and capacity revenue.
We sell the majority of the capacity and energy from our power generation projects under PPAs to a variety of
utilities and other parties. Under the PPAs, which have expiration dates ranging from May 2020 to November 2043, we
receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for
electric generation capacity (known as capacity payments). We also sell steam from a number of our projects to
industrial purchasers under steam sales agreements. Sales of electricity are generally higher during the summer and
winter months, when temperature extremes create demand for either summer cooling or winter heating. The following is
a description of principal activities from which we generate our revenue.
F-14
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Products and services
Energy
Energy capacity
Nature, timing of satisfaction of performance obligations, and significant payment terms
Energy revenue is recognized upon transmission to the customer. Physical transactions, or the
sale of generated electricity to meet supply and demand, are recorded on a gross basis in our
consolidated statements of operations. The price of energy could be contracted under PPAs at set
prices or merchant sales based on market merchant price. Energy revenue is also recognized
under certain contracts for avoided generation during curtailment periods. Energy revenue is
billed and paid on a monthly basis.
Capacity revenues are recognized when contractually earned, and consist of revenues billed to a
third party at a negotiated contract price under the applicable PPAs for making installed
generation capacity available in order to satisfy reliability requirements or merchant capacity
sales based on the market price for such capacity. Energy capacity is billed and paid on a
monthly basis.
Other revenue includes the following:
Steam energy and
capacity
Steam revenue is recognized upon delivery to the customer. Steam capacity payments under the
applicable PPAs are recognized as the amount billable under the respective PPA. Steam capacity
is billed and paid on a monthly basis.
We generate electricity from excess steam provided by a nearby pipeline and its pumping station
in the Solid Fuel segment. Waste heat is earned when it is generated and paid as a portion of
monthly energy and capacity billing.
We provide ancillary and transmission services to our customers under the terms of our PPAs.
These services are billed and paid on a monthly basis.
We provide asset management and operation supervision to the Frederickson project, a facility
that we jointly own with Puget Sound Energy. We also provide operation and maintenance
services to several electric energy customers under the PPAs. All services are billed and paid on
a monthly basis.
Under certain contractual arrangements with our customers, we bill and are paid for not
generating electricity. This revenue is recognized monthly under the terms of those agreements.
Waste heat
Ancillary and
transmission
services
Asset management
and operation,
operation and
maintenance
Enhanced dispatch
contracts
Refer to Note 4 Revenue from contracts for disaggregation of revenue and further contract balance information.
We have entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain
leases which convey to the counterparty the right to the use of the project’s property, plant and equipment in return for
future payments. Such arrangements are classified as either capital or operating leases. PPAs that transfer substantially
all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases.
For PPAs accounted for as operating leases, we recognize lease income consistent with the recognition of
energy revenue due to variable volume of the generation. When energy is delivered, we recognize lease income in
energy revenue.
(q)
Administrative expenses:
Administrative expenses include corporate and other expenses primarily for executive management, finance,
legal, human resources and information systems, which are not directly allocable to our business segments.
F-15
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(r)
Foreign currency translation and transaction gains and losses:
The local currency is the functional currency of our U.S. and Canadian projects. Our reporting currency is the
U.S. dollar. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange.
Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The
resulting currency translation adjustments are not included in the determination of our statements of operations for the
period, but are accumulated and reported as a separate component of shareholders’ equity until sale of the net investment
in the project takes place. Foreign currency transaction gains or losses are reported within foreign exchange (gain) loss in
our consolidated statements of operations.
(s)
Equity compensation plans:
The officers and certain other employees are eligible to participate in the Long-Term Incentive Plan (“LTIP”).
Notional units granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards.
Notional units granted that are expected to be redeemed in common shares upon vesting are accounted for as equity
awards. Unvested notional units are entitled to receive dividends, if paid, equal to the dividends per common share
during the vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the
participant is not an employee at the vesting date.
We initially recognize compensation expense on the estimated number of notional units for which the requisite
service is expected to be rendered. We have estimated a weighted average forfeiture rate of 11% for all notional unit
grants under the LTIP. This estimate will be revisited if subsequent information indicates the actual number of notional
units forfeited is likely to differ from previous estimates. Compensation expense related to awards granted to participants
in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for
notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units
accounted for as liability awards.
(t)
Asset retirement obligations:
The fair value for an asset retirement obligation is recorded in the period in which it is incurred. Retirement
obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes,
and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the
timing and/or method of settlement may be conditional on a future event. When the liability is initially recorded, we
capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to
its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss.
(u)
Pension:
We offer pension benefits to certain employees through a defined benefit pension plan. We recognize the
funded status of our defined benefit plan in the consolidated balance sheets in other long-term liabilities and record an
offset to other comprehensive (loss) income. In addition, we also recognize on an after-tax basis, as a component of
other comprehensive (loss) income, gains and losses as well as all prior service costs that have not been included as part
of our net periodic benefit cost. The determination of our obligation and expenses for pension benefits is dependent on
the selection of certain assumptions. These assumptions determined by management include the discount rate, the
expected rate of return on plan assets, the rate of future compensation increases and retirement age. The assumptions
used may differ materially from actual results, which may result in a significant impact to the amount of our pension
obligation or expense recorded.
F-16
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(v)
Business combinations:
We account for our business combinations in accordance with the acquisition method of accounting, which
requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities
assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and
measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what
information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of
the business combination. In addition, transaction costs are expensed as incurred.
(w)
Concentration of credit risk:
The financial instruments that potentially expose us to credit risk consist primarily of cash and cash equivalents,
restricted cash, derivative instruments and accounts receivable. Cash and restricted cash are held by major financial
institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity,
gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including
declines in the creditworthiness of our customers. We do not normally require collateral or other security to support
energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable
due to the credit-worthiness and payment history of our customers. See Note 22, Segment and geographic information,
for a further discussion of customer concentrations.
(x)
Use of estimates:
The preparation of financial statements requires us to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements
and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates.
During the periods presented, we have made a number of estimates and valuation assumptions, including the useful lives
and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to
PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax
provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations, and
the fair values of acquired assets and liabilities assumed. In addition, estimates are used to test long-lived assets and
goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions
are based on present conditions and our planned course of action, as well as assumptions about future business and
economic conditions. As better information becomes available or actual amounts are determinable, the recorded
estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could
change by a material amount.
(y)
Recently adopted and issued accounting standards:
Accounting Standards Adopted in 2019
In February 2016, the FASB issued authoritative guidance intended to increase transparency and comparability
among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information
about leasing arrangements. Under the new guidance, lessees are required to recognize a right-of-use asset and a lease
liability, measured on a discounted basis, at the commencement date for all leases with terms greater than twelve
months. Additionally, this guidance requires disclosures to help investors and other financial statement users to better
understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative
requirements. Any leases that expired before the initial application date did not require any accounting adjustment. This
guidance became effective for annual reporting periods beginning after December 15, 2018, including interim periods
within those fiscal years, with early adoption permitted. We elected certain practical expedients permitted, including the
F-17
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
expedient that permits us to retain our existing lease assessment and classification. The Company has elected not to
apply the recognition requirements to short-term leases and not to separate non-lease components from associated lease
components, for all classes of underlying assets. In July 2018, the FASB issued further authoritative guidance to provide
an additional transition method to adopt the new lease requirements by allowing entities to initially apply the
requirements by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of
adoption. We elected this transition method.
As the result of our adoption of the guidance, we recorded $6.4 million and $7.2 million of right-of-use assets
and lease liabilities, respectively, in the consolidated balance sheets on January 1, 2019. We have no transitional
adjustments to our opening retained earnings or our consolidated statements of operations. See Note 16, Leases for
further information.
In August 2017, the FASB issued authoritative guidance to align an entity’s risk management activities and
financial reporting for hedging relationships through changes to both the designation and measurement guidance for
qualifying hedging relationships and the presentation of hedge results. The guidance expands and refines hedge
accounting for both nonfinancial and financial risk components and aligns the recognition and presentation of the effects
of the hedging instrument and the hedged item in the financial statements. The guidance became effective for fiscal years
beginning after December 15, 2018, with early adoption permitted. Adoption of this guidance did not impact the
consolidated financial statements.
In February 2018, the FASB issued authoritative guidance to allow a reclassification from accumulated other
comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017.
The guidance became effective for fiscal years beginning after December 15, 2018. Adoption of this guidance did not
impact the consolidated financial statements.
Accounting Standards Not Yet Adopted
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments-Credit Losses”(Topic 326),
Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This guidance amends the guidance on
measuring credit losses on financial assets held at amortized cost. ASU 2016-13 requires the measurement of all
expected credit losses for financial assets held at the reporting date based on historical experience, current conditions,
and reasonable and supportable forecasts. This guidance is effective for fiscal years beginning after December 15, 2019,
including interim periods within those fiscal years. The Company has adopted ASU 2016-13 effective January 1, 2020.
The impact of adoption will require additional disclosures commencing with our March 31, 2020 quarterly report on
Form 10-Q; however, there is no anticipated material impact on our consolidated financial statements.
In August 2018, the FASB issued authoritative guidance to modify the disclosure requirements on fair value
measurement disclosures. The guidance requires removals of certain disclosures, such as the amount of and reasons for
transfers between level 1 and level 2 of fair value hierarchy and the policy for timing of transfers between levels. The
guidance further requires modifications and additions surrounding the disclosures of level 3 fair value measurements and
related unrealized gains and losses. The guidance is effective for fiscal years beginning after December 15, 2019. We do
not expect this to have a material impact on the consolidated financial statements upon adoption.
In August 2018, the FASB issued authoritative guidance to remove disclosures that no longer are considered
cost-beneficial, clarify the specific requirements of disclosures, and add disclosure requirements identified as relevant.
The scope of the guidance is broad and includes reporting comprehensive income, debt modifications and
extinguishments and other sub topics. The guidance is effective for fiscal years beginning after December 15, 2019.
We are currently evaluating the impact that adoption will have on our disclosures.
F-18
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
In August 2018, the FASB issued ASU No. 2018-14, “Compensation -Retirement Benefits -Defined Benefit
Plans -General (Subtopic 715-20)”, to improve the effectiveness of benefit plan disclosures in the notes to financial
statements by facilitating clear communication of the information required by GAAP that is most important to users of
each entity’s financial statements. The amendments in this ASU modify the disclosure requirements for employers that
sponsor defined benefit pension or other postretirement plans. Additionally, the amendments in this ASU remove
disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures, and add
disclosure requirements identified as relevant. The amendments in this ASU are effective for fiscal years ending after
December 15, 2020, for public business entities and early adoption is permitted for all entities. We are currently
evaluating the impact that adoption will have on our disclosures.
In December 2019, the FASB issued amendments to the guidance for income taxes through ASU 2019-12,
“Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” The amendments in this update simplify the
accounting for income taxes by removing certain exceptions such as: 1) the incremental approach for intraperiod tax
allocation when there is a loss from continuing operations and income or a gain from other items, 2) the requirement to
recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method
investment, 3) the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method
investment becomes a subsidiary, and 4) the general methodology for calculating income taxes in an interim period
when a year-to-date loss exceeds the anticipated loss for the year. For public entities, the amendments are effective for
reporting periods beginning after December 15, 2020. Early adoption is permitted. We are in the process of evaluating
the potential impact of the new guidance on our consolidated financial statements.
3. Acquisitions and divestments
2019 Acquisitions
(a)
South Carolina Biomass Plants
On July 31, 2019, we completed the acquisition of two biomass plants in South Carolina, Allendale and
Dorchester, from EDF Renewables Inc. The Allendale plant is located in Allendale, South Carolina and has been in
service since November 2013. The Dorchester plant is located in Harleyville, South Carolina and has been in service
since October 2013. The two plants are identical in design and each of the plants has a capacity of 20 megawatts. All of
the output of the two plants is sold to Santee Cooper, a state-owned utility, under PPAs that run to 2043. The biomass
fuel for the plants consists primarily of mill and harvesting residues. We believe the acquisition represents a meaningful
addition to the level and length of our existing contracted cash flows.
F-19
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The final consideration paid for the two plants was $12.6 million. In September 2018, we made a $2.6 million
down payment for the acquisition of the plants and paid the remaining due at closing, less working capital adjustments
and transaction costs, from discretionary cash and cash equivalents. The South Carolina biomass plants are reflected in
our Solid Fuel segment. See Note 22, Segment and geographic information. The following is a summary of the estimated
fair values of the assets acquired and liabilities assumed:
Fair values
Cash(1)
Accounts receivable
Inventory
Property, plant, and equipment
Intangible assets
Accounts payable
Accrued liabilities
Other liabilities
Total purchase consideration
$
$
1.4
4.3
2.9
4.0
2.6
(2.0)
(0.3)
(0.3)
12.6
(1) The cash acquired was received in October 2019 and has been included in the Cash paid for acquisition, net of cash
received within the Statement of Cash Flows.
The $2.6 million of intangible assets recorded will be amortized straight-line through the remaining life of each
plant’s PPA, which expire on October 31, 2043 (Dorchester) and November 18, 2043 (Allendale).
Allendale and Dorchester contributed $10.8 million of revenue and net income of $1.0 million to the
consolidated statements of operations for the period from July 31, 2019 to December 31, 2019.
(b)
AltaGas
On August 13, 2019, we completed our acquisition of the equity ownership interests held by AltaGas Power
Holdings (U.S.) Inc. (“AltaGas”) in two contracted biomass plants, Craven and Grayling (as defined below), in North
Carolina and Michigan. Craven County Wood Energy (“Craven”) is a 48 megawatt (MW) biomass plant in North
Carolina that has been in service since October 1990. We acquired a 50% interest in the plant from AltaGas. The
remaining 50% interest is held by CMS Energy. Craven has a PPA with Duke Energy Carolinas that will expire on
December 31, 2027. The plant burns wood waste and poultry litter. Grayling Generating Station (“Grayling”) is a
37 MW biomass plant in Michigan that has been in service since June 1992. We acquired a 30% interest in the plant
from AltaGas. The remaining interests are held by Fortistar (20%) and CMS Energy (50%). Grayling has a PPA with
Consumers Energy, the utility subsidiary of CMS Energy, which will expire on December 31, 2027. The plant burns
wood waste from local mills, forestry residues, mill waste and bark. Both plants are operated by an affiliate of CMS
Energy. The purchase price totaled $18.7 million in cash consideration inclusive of approximately $0.2 million of
acquisition-related transaction costs.
Craven and Grayling are limited partnerships. We do not have financial control of the partnerships because
decision-making is shared and the partners must agree on all major decisions for each of the entities. Accordingly, we
account for our ownership in Craven and Grayling under the equity method of accounting because our ownership is
between five and fifty percent resulting in Atlantic Power Corporation maintaining more than minor influence over the
partnerships’ operating and financing policies.
Craven and Grayling contributed $1.0 million in equity in earnings from unconsolidated affiliates to the
consolidated statements of operations, and $0.9 million in equity method distributions for the period from August 13,
F-20
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
2019 to December 31, 2019.
2018 Acquisitions
(a)
Koma Kulshan Associates
On June 18, 2018, we purchased a 0.5% general partner interest in Concrete Hydro Partners L.P. (“Concrete”)
for $1.1 million from Mt. Baker Corporation with cash on-hand. Prior to the purchase, we owned a 0.5% general partner
interest and a 99.0% limited partner interest in Concrete; following the purchase, we own 100% of the entity. Concrete
was the owner of a 50% limited partner interest in Koma Kulshan Associates, L.P. (“Koma”). As a result of the
purchase, our ownership of Koma increased from 49.75% to 50.00%. With 50.00% percent ownership of Koma, we did
not have financial control of the entity as the two owner parties had joint control and substantive participating rights
through the structure of the partnership agreement. Accordingly, since we did not obtain control of the project, we
continued to account for Koma under the equity method of accounting as of June 30, 2018. The $1.1 million purchase
was accounted for as an additional equity method investment in Koma.
On July 27, 2018, we acquired the remaining 50% partnership interest in Koma from Covanta Energy
Americas, Inc. (“Covanta”) for a total purchase price of $12.5 million including working capital. As a result of this
purchase, we own 100% of Koma and consolidated the project on the date of the acquisition. We completed this
acquisition because we view hydro projects as assets that will provide us both near and long-term value.
Our acquisition of Koma is accounted for under the acquisition method of accounting as of the transaction
closing date. The $12.5 million total purchase price was funded with cash on-hand. We assumed operation of the project
from Covanta on the acquisition date of July 27, 2018. The final purchase price allocation for the business combination
is estimated as follows:
Fair value of consideration transferred:
Cash
Other items to be allocated to identifiable assets acquired and liabilities assumed:
$
Book value of our investment in Koma at the acquisition date
Gain recognized from step acquisition
Total purchase price
Final purchase price allocation
Cash
Working capital
Property, plant, and equipment
Intangible assets
Asset retirement obligation
Total identifiable net assets
$
$
$
12.5
5.4
7.2
25.1
0.8
0.1
1.2
24.8
(1.8)
25.1
The fair values of the assets acquired and liabilities assumed, as well as the fair value of our previous 50%
equity interest in Koma, were estimated by applying an income approach using the discounted cash flow method. These
measurements were based on significant inputs not observable in the market and thus represent a level 3 fair value
measurement. The primary considerations and assumptions that affected the discounted cash flows included the
operational characteristics and financial forecasts of the acquired facility, remaining useful life and a discount rate based
on the weighted average cost of capital adjusted for the risk and characteristics of the project. We recognized a
$7.2 million gain recorded in other income in the consolidated statements of operations for the year ended December 31,
2018 as a result of remeasuring our previous 50% equity interest in Koma immediately before the business combination
to fair value. The $24.8 million of intangible assets recorded will be amortized straight-line through the remaining life of
F-21
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Koma’s PPA, which expires on March 31, 2037. Additionally, we recorded $0.5 million of deferred tax liabilities and
deferred tax expense related to the step acquisition of Koma Kulshan.
Koma contributed $1.1 million of revenue and net income of $0.0 million (excluding the $7.2 million gain
recognized from the step acquisition) to the consolidated statements of operations for the period from July 27, 2018 to
December 31, 2018. The impact to pro forma results of operations was not significant to the years ended December 31,
2019, 2018 and 2017.
2017 Divestment
(a)
Selkirk Project
On November 2017, we sold our 17.7% interest in Selkirk Cogen Partners, LP (“Selkirk”) to JMC Selkirk LLC,
the project’s majority owner, for $1.0 million. Selkirk was accounted for under the equity method of accounting. In the
second quarter of 2017, we recorded a $10.6 million impairment at Selkirk and wrote our equity investment down to
zero. As a result of the sale, we recorded a $1.0 million gain on sale, which is included as a component of equity in
earnings (loss) from unconsolidated affiliates in the consolidated statement of operations for the year ended
December 31, 2017.
4. Revenue from contracts
Revenue, receivables and contract liabilities by segment consists of following:
Project revenue:
Energy sales
Energy capacity revenue
Steam energy and capacity revenue
Waste heat revenue
Ancillary and transmission services
Asset management and operation
Miscellaneous revenue
Project revenue:
Energy sales
Energy capacity revenue
Steam energy and capacity revenue
Waste heat revenue
Enhanced dispatch contracts
Ancillary and transmission services
Asset management and operation
Miscellaneous revenue
Year Ended December 31, 2019
Consolidated
Solid Fuel
Natural Gas Hydroelectric Corporate
Total
$
41.1 $
38.7
—
0.2
—
—
—
80.0
31.0 $
86.7
11.7
—
4.7
—
(2.3)
131.8
65.9 $
—
—
—
2.9
—
—
68.8
— $
—
—
—
—
1.0
—
1.0
138.0
125.4
11.7
0.2
7.6
1.0
(2.3)
281.6
Year Ended December 31, 2018
Consolidated
Solid Fuel
Natural Gas
Hydroelectric Corporate
Total
$
37.4 $
41.6
0.1
0.2
—
4.5
—
—
83.8
38.3 $
56.3
15.6
—
23.9
5.4
—
(0.3)
139.2
55.2 $
—
—
—
—
3.1
—
—
58.3
— $
—
—
—
—
—
1.0
—
1.0
130.9
97.9
15.7
0.2
23.9
13.0
1.0
(0.3)
282.3
F-22
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Contract balances
The following table provides information about receivables, contract assets and contract liabilities from
contracts with customers.
Accounts receivables
Contract liabilities
December 31,
December 31,
2019
2018
$
30.4 $
0.3
35.7
0.1
Contract liabilities as of December 31, 2019 include a $0.2 million fuel reserve fund at Dorchester and a
$0.1 million steam sale credit at the San Diego plants. Contract liabilities as of December 31, 2018 include a
$0.1 million steam sale credit at the San Diego plants.
F-23
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
5. Changes in accumulated other comprehensive income by component
The changes in accumulated OCI by component are as follows:
Foreign currency translation
Balance at beginning of period
Other comprehensive income (loss):
Foreign currency translation adjustments(1)
Balance at end of period
Pension
Balance at beginning and end of period
Other comprehensive loss:
Settlement
Curtailment gain
Tax (expense) benefit
Total Other comprehensive income (loss) before reclassifications, net of
tax
Total amount reclassified from accumulated other comprehensive income,
net of tax
Total other comprehensive (loss) income
Balance at end of period
Cash flow hedges
Balance at beginning of period
Other comprehensive income (loss):
Net change from periodic revaluations
Tax benefit (expense)
Total Other comprehensive (loss) income before reclassifications, net of
tax
Net amount reclassified to earnings:
Interest rate swaps(2)
Tax expense
Total amount reclassified from accumulated other comprehensive
income, net of tax
Total other comprehensive income
Balance at end of period
Year Ended December 31,
2018
2017
2019
$ (146.4) $ (134.3)
$ (148.3)
5.8
(12.1)
$ (140.6) $ (146.4)
14.0
$ (134.3)
$
(1.4) $
(1.6)
$
(0.9)
0.3
—
(0.1)
0.2
—
—
—
—
(0.5)
(0.3)
(1.7) $
0.2
0.2
(1.4)
$
$
1.6 $
1.1
(0.5)
0.2
0.5
(0.1)
(0.3)
0.4
0.4
(0.1)
0.3
—
1.6 $
0.2
(0.1)
0.1
0.5
1.6
$
$
$
$
—
(1.6)
0.4
(1.2)
0.5
(0.7)
(1.6)
0.7
(0.2)
0.1
(0.1)
0.9
(0.4)
0.5
0.4
1.1
(1)
In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to (loss)
earnings.
(2) This amount was included in interest expense, net on the accompanying consolidated statements of operations.
F-24
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
6. Equity method investments in unconsolidated affiliates
The following tables summarize our equity method investments in unconsolidated affiliates:
Entity name
Frederickson(1)
Orlando Cogen, LP
Chambers Cogen, LP
Craven County Wood Energy, LP (2)
Grayling Generating Station, LP (2)
Total
Percentage of
Ownership as of
December 31, 2019
Carrying value as of
December 31,
2019
50.2 % $ 65.2 $
50.0 %
40.0 %
50.0 %
30.0 %
2018
72.0
4.5
64.3
—
—
$ 96.6 $ 140.8
3.6
9.0
9.5
9.3
(1) We own 50.15% of Frederickson. However, we do not have financial control of the entity. The Frederickson
entity is organized under a joint ownership agreement. Under the terms of that agreement, the two owner parties
have joint control of the asset and substantive participating rights through the structure of its Owner’s
Committee. Each party has equal representation on this committee and unanimous consent is required over all
significant decisions of the entity. These significant decisions include, but are not limited to (i) approval of the
annual operating plan, annual operating budget, annual capital budget and five-year forecasts, (ii) approval of
all expenditures in excess of the approved budget, (iii) adoption of procedures intended to govern the operation
and conduct of the facility, and (iv) entering into, amending, supplementing or terminating any project
agreement. Disputes between the owners for these significant decisions are subject to independent arbitration.
Accordingly, since we do not control the project, Frederickson is accounted for under the equity method of
accounting.
In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3
Acquisitions and divestments.
(2)
Deficit in earnings of equity method investments, net of distributions, was as follows:
Entity name
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Craven County Wood Energy, LP (3)
Grayling Generating Station, LP (3)
Total (loss) earnings of unconsolidated affiliates
Distributions from equity method investments
Deficit in earnings of equity method investments, net of
distributions
Year Ended December 31,
2018
2019
$
9.1 $
6.9 $
33.0
—
(46.0)
—
0.1
0.8
(3.0)
(59.5)
30.1
0.6
5.6
—
—
—
43.2
(61.6)
2017
(27.9)
25.6
0.7
(42.6)
(10.6)
—
—
(54.8)
(47.3)
$ (62.5) $ (18.4) $ (102.1)
(1)
(2)
(3)
In July 2018, we purchased the remaining 50% partnership interest in Koma and consolidated the project in our
financial statements. See Note 3 Acquisitions and divestments.
In November 2017, we sold our 17.7% interest in Selkirk.
In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3
Acquisitions and divestments.
F-25
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Distributions from equity method investments exceeded (loss) earnings of equity method investments for the
years ended December 31, 2019, 2018 and 2017, respectively. Distributions from our equity method investments are
typically based on project-level cash flows from operations or other non-GAAP metrics, whereas equity earnings include
non-cash expenses such as depreciation and amortization, investment impairments or changes in the fair value of
derivative financial instruments.
The following summarizes the financial position at December 31, 2019, 2018 and 2017, and operating results
for the years ended December 31, 2019, 2018 and 2017, respectively, for our proportional ownership interest in equity
method investments:
Assets
Current assets
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Craven County Wood Energy, LP (2)
Grayling Generating Station, LP (2)
Non-current assets
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Craven County Wood Energy, LP (2)
Grayling Generating Station, LP (2)
Liabilities
Current liabilities
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Craven County Wood Energy, LP (2)
Grayling Generating Station, LP (2)
Non-current liabilities
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Craven County Wood Energy, LP (2)
Grayling Generating Station, LP (2)
2019
2018
2017
$
2.1 $
7.8
—
14.4
4.4
3.3
2.5 $
7.7
—
15.6
—
—
1.9
9.2
0.5
17.3
—
—
63.9
6.1
—
56.5
5.8
6.8
76.2
8.1
4.7
130.9
—
—
$ 171.1 $ 220.3 $ 248.8
70.0
7.1
—
117.4
—
—
$
0.3 $
— $
10.2
—
13.7
0.8
0.5
10.3
—
9.2
—
—
0.4
10.3
0.1
3.7
—
—
0.5
—
—
48.2
—
0.3
0.4
—
0.2
70.0
—
—
$ 74.5 $ 79.5 $ 85.1
0.5
—
—
59.5
—
—
(1)
(2)
In July 2018, we purchased the remaining 50% partnership interest in Koma and consolidated the project in our
financial statements. See Note 3 Acquisitions and divestments.
In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3
Acquisitions and divestments.
F-26
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Operating results
Revenue
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Craven County Wood Energy, LP (3)
Grayling Generating Station, LP (3)
Project expenses
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Craven County Wood Energy, LP (3)
Grayling Generating Station, LP (3)
Project other expenses
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Craven County Wood Energy, LP (3)
Grayling Generating Station, LP (3)
Net income (loss)
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Craven County Wood Energy, LP (3)
Grayling Generating Station, LP (3)
2019
2018
2017
$ 36.0 $ 21.0 $ 21.6
55.0
1.8
43.8
1.8
—
—
124.0
60.2
1.2
43.3
—
—
—
125.7
61.5
—
39.4
—
4.9
2.2
144.0
26.9
28.5
—
34.6
—
4.7
1.8
96.5
14.1
30.1
0.6
36.1
—
—
—
80.9
21.0
29.4
1.1
37.5
2.8
—
—
91.8
—
—
—
(50.9)
—
—
0.4
(50.5)
—
—
—
(1.6)
—
—
—
(1.6)
(28.4)
—
—
(48.9)
(9.7)
—
—
(87.0)
9.1
6.9
(27.8)
33.0
30.1
25.6
—
0.6
0.7
(46.1)
5.6
(42.6)
—
—
(10.7)
0.2
—
—
—
—
0.8
(3.0) $ 43.2 $ (54.8)
Equity in (loss) earnings of unconsolidated affiliates
$
(1)
(2)
(3)
In July 2018, we purchased the remaining 50% partnership interest in Koma and consolidated the project in our
financial statements. Amounts in the above table relate to the period Koma was accounted for under the equity
method of accounting. See Note 3 Acquisitions and divestments.
In November 2017, we sold our 17.7% interest in Selkirk.
In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3
Acquisitions and divestments.
During the year ended December 31, 2019, we recorded an investment impairment of $49.2 million at our
Chambers project. We recorded investment impairments of $47.1 million, $28.3 million and $10.6 million, respectively,
at our Chambers, Frederickson and Selkirk projects in the year ended December 31, 2017. These impairments are a
component of the operating results in the table above. There were no impairment triggers during 2018 and accordingly
F-27
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
no impairment tests were performed on equity method investments.
2019 – Event-driven test in the fourth quarter
Chambers
We own a 40% limited partner interest in Chambers Cogeneration Limited Partnership. The Chambers project
operates under a PPA that expires in March 2024. Prior to our impairment analysis, Chambers was recorded as a
$58.2 million component of our equity investments in unconsolidated affiliates on the consolidated balance sheets.
In connection with the preparation of the long-term forecast during the fourth quarter of 2019, we performed
an analysis of the post-PPA value of Chambers operating as a merchant facility. As a result, we identified a significant
decrease in the long-term outlook for power prices and spark spreads in PJM, the region where Chambers operates.
These forward power prices, which were obtained from a third party, including analysis of the forward prices for natural
gas and coal, had a significant negative impact on the discounted cash flows of Chambers post-PPA. The estimated post-
PPA value is a significant component of the project’s overall value when compared to its carrying value of
$58.2 million.
When determining if this decrease in estimated fair value was other than temporary, we considered the
likelihood that future conditions would change such that the gas and coal prices currently observed in the forward
pricing models would become more favorable over time in order for the plant to be profitable in a merchant market.
While declining power prices have been observed over the past several years, given that merchant curves have declined
further than what was observed in 2017, it was our assessment that future merchant pricing and spark spreads were likely
to remain low and that Chambers would be unable to recover its start fuel and start operations and maintenance costs
after expiration of its PPA in 2024. Based on these factors, we determined that the decline in the fair value of our
investment in Chambers was other than temporary. We recorded a $49.2 million impairment in earnings (loss) from
unconsolidated affiliates in the consolidated statements of operations for the year ended December 31, 2019.
2017 – Event-driven test in the fourth quarter
Frederickson
In the fourth quarter of 2017, we performed an impairment test of our investment in our Frederickson project.
The Frederickson project operates under three PPAs that expire in August 2022. Prior to our impairment analysis,
Frederickson was recorded as a $108.3 million component of our equity investments in unconsolidated affiliates on the
consolidated balance sheets.
We performed an analysis of the post-PPA value of Frederickson operating as a merchant facility. In our long-
term forecast completed in December 2017, we identified a significant decrease in the long-term peak demand outlook
for power prices in the Pacific Northwest, the region where Frederickson operates, which management determined to be
an other than temporary decline in prices. These forward prices, which were obtained from a third party, had a
significant negative impact on the estimated discounted cash flows of Frederickson post-PPA. The estimated post-PPA
value is a significant component of the project’s overall value when compared to its pre-impairment carrying value of
$108.3 million.
When determining if the decrease in fair value estimated in our 2017 test was other than temporary, we
considered the likelihood that future conditions would change such that the power prices currently observed in the
forward pricing models would become more favorable over time. Frederickson operates in a region with large, planned
coal facility retirements and strong population growth. However, it was our assessment that natural gas prices were
F-28
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
likely to remain low when considering the current and expected future supply of shale gas and that these factors would
negatively impact future merchant pricing. Based on these factors, we determined that the decline in the fair value of our
equity investment in Frederickson was other than temporary. We recorded a $28.3 million impairment in earnings from
unconsolidated affiliates in the consolidated statements of operations for the year ended December 31, 2017.
2017 – Event-driven test in the second quarter
In the second quarter of 2017, we performed event-driven impairment tests of our investments in our
Chambers and Selkirk projects, which are accounted for under the equity method of accounting.
Selkirk
We previously owned a 17.7% limited partner interest in Selkirk Cogen Partners, L.P. The project operated as
a merchant facility since the expiration of its PPA in August 2014. Since the expiration of its PPA, we did not receive a
distribution from Selkirk and recorded a cumulative $2.6 million project loss. Based on the project’s history of providing
no cash distributions while operating as a merchant facility, the short-term and long-term operational forecast, as well as
the likelihood that further investment would be required in order to operate the facility, we determined that our
investment in Selkirk was impaired and the decline in value was other than temporary. Accordingly, we recorded a
$10.6 million full impairment in earnings from unconsolidated affiliates in the consolidated statements of operations in
the three months ended June 30, 2017. We sold our interest in Selkirk in November 2017 and recorded a $1 million gain
on sale in the year ended December 31, 2017. The impairment charge and the gain on sale are both recorded in earnings
from unconsolidated affiliates in the statement of operations for the year ended December 31, 2017.
Chambers
Prior to our impairment analysis, Chambers was recorded as a $124 million component of our equity
investments in unconsolidated affiliates on the consolidated balance sheets.
During the second quarter of 2017, we performed an analysis of the post-PPA value of Chambers operating as
a merchant facility. While declining power prices had been observed over the past several years, in our long-term
forecast completed in July 2017, we identified a significant decrease in the long-term outlook for power prices in PJM,
which management determined to be an other than temporary decline in prices. These forward power prices, which were
obtained from a third party, including analysis of the forward prices for natural gas and coal, had a significant negative
impact on the DCFs of Chambers post-PPA. The estimated post-PPA value is a significant component of the project’s
overall value when compared to its carrying value of $124 million.
When determining if this decrease in fair value estimated in our event-driven 2017 test was other than
temporary, we considered the likelihood that future conditions would change such that the gas and coal prices currently
observed in the forward pricing models would become more favorable over time in order for the plant to be profitable in
a merchant market. We also engaged a separate third party to provide its outlook on post-PPA value for Chambers. It
was our assessment that future merchant pricing was likely to remain low due to lower natural gas prices from the
current and expected future supply of shale gas. The third party provided similar conclusions to our assessment.
Based on these factors, we determined that the decline in the fair value of our equity investment in Chambers
was other than temporary. We recorded a $47.1 million impairment in earnings from unconsolidated affiliates in the
consolidated statements of operations for the three months ended June 30, 2017.
F-29
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
7. Inventory
Inventory consists of the following:
Parts and other consumables
Fuel
Total inventory
8. Property, plant and equipment, net
Property, plant and equipment, net consists of the following:
December 31,
2019
12.2 $
6.4
18.6 $
2018
9.6
6.2
15.8
$
$
December 31, December 31, Depreciable
2018
Lives
2019
Land
Office equipment, machinery and other
Leasehold improvements
Asset retirement obligation
Plant in service
Construction in progress
$
Less accumulated depreciation
Total property, plant and equipment, net
$
3 - 10 years
7 - 15 years
1 - 43 years
1 - 45 years
6.4 $
6.5
2.1
23.4
848.1
7.2
893.7
(391.6)
502.1 $
5.3
6.0
2.1
24.1
874.4
—
911.9
(362.4)
549.5
Depreciation expense of $37.6 million, $40.0 million and $83.3 million, was recorded for the years ended
December 31, 2019, 2018 and 2017, respectively.
As described below, we recorded $4.0 million and $67.6 million of long-lived asset impairments to property,
plant and equipment in the years ended December 31, 2019 and 2017, respectively, with a corresponding charge to
Impairment in the statement of operations. No long-lived asset impairments to property, plant and equipment were
recorded in the year ended December 31, 2018.
2019 – Event-driven test performed in fourth quarter
Calstock – Long-lived assets
Calstock operates under a PPA that expires in June 2020. The near-term expiration of the PPA resulted in a
triggering event to test for long-lived asset impairment. We performed the test as of December 31, 2019, six months
prior to the contract expiration date. Calstock’s asset group for testing of long-lived assets totaled $7.8 million consisting
of $2.3 million of net working capital, $4.7 million property, plant and equipment (“PPE”), net and a $0.8 million
intangible PPA asset.
Because of the uncertainty of our ability to recontract the project, fair value of Calstock was determined based
solely on the cash flows remaining under the current contract. If our efforts to recontract are unsuccessful, the project
will be taken out of service but not decommissioned. Upon testing Calstock for long-lived asset impairment, the carrying
value of the asset group exceeded the estimated cash flows. Accordingly, we recorded a $4.7 million long-lived asset
impairment in the year ended December 31, 2019, which is the difference between the fair value and carrying value of
F-30
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
the reporting unit’s asset group, $0.7 million of the impairment related to intangible PPA assets and $4.0 million of the
impairment related to property, plant and equipment. We also recorded impairment losses of $1.1 million related to spare
parts inventory at Calstock. The Calstock biomass plant is a component of our Solid Fuel segment.
2018 – Event-driven test performed in fourth quarter
Williams Lake – Long-lived assets
Williams Lake previously operated under a PPA that expired June 30, 2019, or September 30, 2019 at the
option of BC Hydro, the project’s customer. The near-term expiration of the PPA resulted in a triggering event to test for
long-lived asset impairment. We performed the test as of December 31, 2018, six months prior to the earliest contract
expiration date. Williams Lake’s asset group for testing of long-lived assets totaled $11.4 million consisting of PPE, net
and spare parts inventory.
Because of the uncertainty of our ability to recontract the project, we performed a probability-based approach
when determining the weighted average fair value of Williams Lake. This approach considered the cash flows remaining
under the current contract assuming a September 30, 2019 expiration date, as well as a modeled hypothetical long-term
extension. In February 2019, the office of the Minister of Energy, Mines and Petroleum Resources in British Columbia
made recommendations that the government could direct BC Hydro to pursue renewal transactions for existing biomass
plants with expiring contracts. We considered these factors when creating our modeled hypothetical long-term extension.
This model incorporates significant judgments and estimates by management when determining outcome likelihood, as
well as long-term extension economics. Williams Lake has approximately 20 years of remaining useful life. We believe
that Williams Lake provides value to British Columbia based on its positioning as a renewable resource, its synergy with
the local forestry industry and its lower $/KW cost than new biomass construction.
Upon testing Williams Lake for long-lived asset impairment, the estimated weighted-average undiscounted cash
flows exceeded the carrying value of the asset group. Accordingly, no long-lived asset impairment was recorded at
December 31, 2018. We subsequently executed a new ten-year Energy Purchase Agreement with BC Hydro for
Williams Lake, which became effective October 1, 2019.
2017 – Event-driven test performed in fourth quarter
Williams Lake – Long-lived assets
Williams Lake previously operated under a PPA that expired on March 31, 2018 with BC Hydro. BC Hydro
elected not to exercise its renewal options under that PPA. Additionally, the Province of British Columbia planned to
commence an Integrated Resource Plan Process (IRP) in late 2018. This process is the Province’s long-term plan to meet
future electricity demand through conservation, generation and transmission and through upgrades to existing
infrastructure. At the time of our assessment, we believed that obtaining a long-term PPA extension prior to the
conclusion of the IRP was unlikely. In January 2018, the project entered into a PPA extension that commenced on
April 1, 2018 and expires June 30, 2019, or September 30, 2019 at the option of BC Hydro. The project entered into this
extension in order to bridge the period of the expiration of the previous PPA in March 2018 until the conclusion of the
IRP in order to increase the likelihood for the potential of a future long-term extension. The uncertainty of the results of
the IRP resulted in a triggering event to test for long-lived asset impairment. We performed the test as of December 31,
2017 in order to include the economics of the January 2018 extension in our long-term cash flow forecasts as the terms
F-31
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
of the extension were known at December 31, 2017. Williams Lake’s asset group for testing of long-lived assets totaled
$40.0 million consisting of $39.4 million in PPE, net and a $0.6 million intangible PPA asset.
Because of the uncertainty of the results of the IRP, we performed a probability-based approach when
determining the weighted average fair value of Williams Lake. This approach considered the cash flows under the
January 2018 extension, as well as a modeled long-term extension post-IRP incorporating similar economics to the 2018
extension with some additional allowances. These factors incorporated significant judgments and estimates by
management when determining outcome likelihood, as well as long-term extension economics. Williams Lake has
approximately 22 years of remaining useful life. We believe that Williams Lake provides value to the Province’s long-
term plan based on its positioning as a renewable resource, its synergy with the local forestry industry and its lower
$/KW cost than new biomass construction.
Upon testing Williams Lake for long-lived asset impairment, the carrying value of the asset group exceeded the
estimated weighted-average undiscounted cash flows. Because Williams Lake failed the recovery test, we calculated the
estimated weighted-average fair value utilizing a probability-based DCF and recorded a $29.1 million long-lived asset
impairment in the year ended December 31, 2017, which is the difference between the fair value and carrying value of
the reporting unit’s asset group. The impairment was allocated as a $0.6 million full impairment of intangible PPA assets
and a $28.5 million partial impairment of property, plant and equipment. The Williams Lake biomass plant is a
component of our Solid Fuel segment.
2017 – Event-driven test performed in third quarter
In the third quarter of 2017, we performed event-driven long-lived asset impairment tests at Naval Station,
North Island and Naval Training Center (“NTC”) (collectively, the “San Diego Projects”).
The San Diego Projects sold power to San Diego Gas & Electric (“SDG&E”) under PPAs that were scheduled
to expire in December 2019. In addition, the three projects supplied steam to the U.S. Navy under agreements that
provided these projects with the right to use the property at the respective sites on which each project is located (the
“Navy agreements”). In August 2017, we were unsuccessful in obtaining contracts to provide the Navy with energy
security that would have provided us with the right to continue using the sites beyond February 2018. Following
notification of the outcome of the Navy solicitation, we determined that it was unlikely that any of these projects will
operate beyond the expiration of the Navy agreements. As a result, we performed long-lived asset impairment tests at
each of these projects as of July 31, 2017.
In order to test the recoverability of the long-lived assets in the asset groups, we compared the carrying amount
of the assets to estimated undiscounted future cash flows expected to be generated by each of the San Diego Projects
through their expected decommissioning dates. The carrying value of each asset group includes its recorded property,
plant equipment and intangible assets related to PPAs. As a result of this test, we recorded a total $57.3 million
impairment ($22.5 million at Naval Station, $13.5 million at NTC and $21.2 million at North Island) in the year ended
December 31, 2017. This impairment is composed of an $18.2 million full impairment of intangible assets related to
PPAs ($10.3 million at Naval Station, $3.6 million at NTC and $4.2 million at North Island) and a $39.1 million partial
impairment of property, plant and equipment ($12.1 million at Naval Station, $9.9 million at NTC and $17.0 million at
North Island). At December 31, 2017, the San Diego projects’ remaining property, plant and equipment represent our
estimate of the projects’ remaining undiscounted cash flows and salvage values.
We were unable to extend our land use license agreements through the end of our PPAs and ceased operations
at these plants on February 7, 2018. The San Diego Projects are components of our Natural Gas segment.
F-32
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
9. Goodwill
The following table presents goodwill by reportable segment for the years ended December 31, 2019 and 2018:
Curtis Palmer
Morris
Nipigon
Total
Goodwill Impairment Testing
Segment
2019
2018
Hydroelectric
Natural Gas
Natural Gas
$
$
14.4 $
3.3
3.6
21.3 $
14.4
3.3
3.6
21.3
We perform our annual goodwill impairment test as of November 30 and update the test between annual tests if
events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying
value.
Based on the results of the annual goodwill impairment tests for years ended December 31, 2019 and 2018,
management determined that no adjustment to the carrying value for any reporting unit was necessary because in all
cases, the estimated fair values of the reporting units exceeded their respective carrying values. The fair value of all
reporting units was determined using an income approach and considered project-specific assumptions for the future
discounted cash flows.
For the year ended December 31, 2019, we performed a quantitative test at each reporting unit. For the year
ended December 31, 2018, we performed a quantitative test at our Curtis Palmer reporting unit and qualitative
assessments at our Morris and Nipigon reporting units. Curtis Palmer’s fair value exceeded its carrying value by
approximately $8.3 million or 9% at November 30, 2018.
In the fourth quarter of 2017, based on the results of the annual quantitative goodwill impairment test,
management determined that the fair value of the Curtis Palmer reporting unit was below its respective carrying value,
including goodwill. Accordingly, we recorded a $14.7 million goodwill impairment at Curtis Palmer during the year
ended December 31, 2017. Subsequent to the impairment, Curtis Palmer has $14.4 million of goodwill remaining at
December 31, 2017. As a hydro facility, Curtis Palmer has substantial useful life beyond the expiration of its PPA in
2027. Estimates of fair value beyond the end of its PPA expiration utilize merchant pricing assumptions and are sensitive
to changes in forward power prices. These forward prices declined significantly from those observed in our 2016 test,
resulting in a reduction of the fair value from our impairment test performed in the fourth quarter of 2016.
The other remaining reporting units with goodwill recorded, Nipigon ($3.6 million of goodwill at December 31,
2017) and Morris ($3.3 million of goodwill at December 31, 2017), had fair values that exceeded their carrying values
by approximately $111.7 million or 118% and accordingly, no goodwill impairment was recorded as of December 31,
2017.
10. PPAs and other definite-lived intangible assets and liabilities
Other intangible assets and liabilities include PPAs, fuel supply agreements and capitalized development costs.
F-33
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following tables summarize the components of our intangible assets and other liabilities subject to
amortization at December 31, 2019 and 2018:
Assets
Gross balances, December 31, 2019
Less: accumulated amortization
Net carrying amounts, December 31, 2019
Gross balances, December 31, 2018
Less: accumulated amortization
Net carrying amounts, December 31, 2018
Liabilities
Gross balances, December 31, 2019
Less: accumulated amortization
Net carrying amounts, December 31, 2019
Gross balances, December 31, 2018
Less: accumulated amortization
Net carrying amounts, December 31, 2018
Other Intangible Assets, Net
Power Purchase
Agreements
$
$
365.6 $
(221.3)
144.3
$
Total
365.6
(221.3)
144.3
Other Intangible Assets, Net
Power Purchase
Agreements
$
$
362.7 $
(192.6)
170.1
$
Total
362.7
(192.6)
170.1
Power Purchase and Fuel Supply Agreement Liabilities, Net
Fuel Supply
Power Purchase
Agreements
Agreements
Total
$
$
(28.1)
14.4
(13.7)
$
(12.6) $
6.5
(6.1)
$
(40.7)
20.9
(19.8)
Power Purchase and Fuel Supply Agreement Liabilities, Net
Fuel Supply
Power Purchase
Agreements
Agreements
Total
$
$
(28.7)
14.0
(14.7)
$
(12.6) $
6.1
(6.5)
$
(41.3)
20.1
(21.2)
The following table presents amortization expense of intangible assets for the years ended December 31, 2019,
2018 and 2017:
2019
2017
2018
$ 26.4 $ 43.4 $ 36.5
(0.4)
$ 26.0 $ 43.0 $ 36.1
(0.4)
(0.4)
PPAs
Fuel supply agreements
Total amortization
F-34
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table presents estimated future amortization expense for the next five years:
Year Ended December 31,
2020
2021
2022
2023
2024
$
22.1
20.2
15.9
12.6
12.6
The weighted average remaining amortization period related to our intangible assets and liabilities was 8.6
years as of December 31, 2019.
11. Other long-term liabilities
Other long-term liabilities consist of the following at December 31:
Long-term contract liability
Net pension liability
Accrued LTIP and director share units
Other
2019
2018
$
$
0.2 $
1.2
1.6
1.7
4.7 $
—
1.2
1.4
2.4
5.0
The following table is a rollforward of asset retirement obligations for the years ended December 31:
Asset retirement obligations beginning of year
Accretion and change in estimate of asset retirement obligation
Acquisition
Costs incurred
Translation adjustments
Asset retirement obligations, end of year
2019
49.2 $
2.3
—
(1.0)
1.0
51.5 $
2018
45.3
4.3
1.8
(0.5)
(1.7)
49.2
$
$
In the third quarter of 2017, we performed an event-driven long-lived asset impairment test at our Naval
Station, North Island and Naval Training Center projects. See Note 8, Property, plant and equipment for discussion of
the facts and circumstances resulting in the impairment. At the time of the assessment, we had not completed our process
for estimating decommissioning costs at those facilities. In the fourth quarter of 2017, based on information provided by
third parties, we determined that the estimated costs to remove the facilities and return the land to the conditions required
under their respective land rights agreements was approximately $1.7 million. Prior to adjustment, we had recorded asset
retirement obligations for Naval Station, North Island and Naval Training Center of $6.7 million. These retirement
obligations were based on estimates made at the time of their acquisition in November 2011, as well as engineering
studies performed at the inception of these projects. These asset retirement obligations were accreted based on inflation
and discount rates. As a result of the change in estimate for decommissioning costs, we recorded a $5.0 million decrease
to amortization expense in the fourth quarter of 2017. These projects ceased operations in February 2018. Subsequent to
their shutdown, we have been actively planning the decommissioning of these facilities. Although the process is not
final, changes to both the scope and cost of decommissioning these facilities resulted in a change of estimate of the asset
retirement obligation. We increased the asset retirement obligation by $1.4 million and $3.5 million and recorded a
corresponding decommissioning loss in the consolidated statements of operations for the years ended December 31,
F-35
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
2019 and 2018, respectively.
12. Long-term debt
Long-term debt consists of the following:
Recourse Debt:
Senior secured term loan facility, due 2025(1)
Senior unsecured notes, due June 2036 (Cdn$210.0)
Non-Recourse Debt:
Cadillac term loan, due 2025 (3)
Less: unamortized discount
Less: unamortized deferred financing costs
Less: current maturities
Total long-term debt
Current maturities consist of the following:
December 31, December 31,
2019
2018
Interest Rate
$
380.0 $
161.7
450.0
154.0
LIBOR(2) plus
2.75 %
5.95 %
LIBOR plus
1.61 %
18.7
(5.8)
(4.7)
(76.4)
473.5 $
21.0
(9.0)
(7.2)
(68.1)
540.7
$
Current Maturities:
Senior secured term loan facility, due 2025(1)
Cadillac term loan, due 2025 (3)
Total current maturities
December 31, December 31,
2019
2018
Interest Rate
$
$
72.5 $
3.9
76.4 $
65.0
3.1
68.1
LIBOR(2) plus
LIBOR plus
2.75 %
1.61 %
(1) On a quarterly basis, we make a cash sweep payment to fund the principal balance, based on terms as defined in the
Credit Agreement and disclosed below. The portion of the Term Loan classified as current is based on principal
payments required to reduce the aggregate principal amount of Term Loan outstanding to achieve a target principal
amount that declines quarterly based on a pre-determined specified schedule.
(2) LIBOR cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to
changes in LIBOR for $370.6 million of the $380.0 million remaining aggregate borrowings under our Term Loan
at December 31, 2019. See Note 15, Accounting for derivative instruments and hedging activities for further details.
On January 31, 2020, the repricing of the Term Loan became effective, reducing the interest rate to LIBOR plus
2.50% with no change to the 1.00% LIBOR floor. The maturity date for the Term Loan was also extended to April
2025. The repricing also adds customary new provisions relating to the replacement of LIBOR as the benchmark for
the Eurodollar Rate (as defined in the Credit Agreement) replacement.
(3) We have entered into interest rate swap agreements to economically fix our exposure to changes in interest rates for
this non-recourse debt. See Note 15, Accounting for derivative instruments and hedging activities, for further
details.
F-36
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Principal payments on the maturities of our debt due in the next five years and thereafter are as follows:
2020
2021
2022
2023
2024
Thereafter
Credit Facilities
$
$
76.4
95.7
109.3
63.3
39.7
176.0
560.4
On April 13, 2016, APLP Holdings, our wholly-owned subsidiary, entered into new Senior Secured Credit
Facilities, comprising $700 million in aggregate principal amount of Senior Secured Term Loan facilities (the “Term
Loan”) and $200 million in aggregate principal amount of senior secured credit facilities (the “Revolver” and together
with the Term Loan, the “Credit Facilities”). At December 31, 2019, $380.0 million of the Term Loan is outstanding and
letters of credit in an aggregate face amount of $78.3 million are issued (but not drawn) pursuant to the revolving
commitments under the Revolver and used (i) to fund a debt service reserve in an amount equivalent to six months of
debt service, and (ii) to support contractual credit support obligations of APLP Holdings and its subsidiaries and of
certain other affiliates of the Company.
Borrowings under Credit Facilities are available in U.S. dollars and Canadian dollars and, at inception, bore
interest at a rate equal to the Adjusted Eurodollar Rate, the Base Rate or the Canadian Prime Rate as applicable, plus an
applicable margin between 4.00% and 5.00% that varied depending on whether the loan is a Eurodollar Rate Loan, Base
Rate Loan, or Canadian Prime Rate Loan. In April 2017, the repricing of the Credit Facilities became effective reducing
the interest rate margin on the Term Loan and Revolver by 0.75% to LIBOR plus 4.25%. In October 2017, a second
repricing reduced the interest rate margin on the Credit Facilities by another 0.75% to LIBOR plus 3.50%. In April 2018,
a third repricing reduced the interest rate margin on the Credit Facilities by an additional 0.50% to LIBOR plus 3.00%
and in October 2018, a fourth repricing reduced the interest rate margin on the Credit Facilities by 0.25% to LIBOR plus
2.75%.
In January 2020, APLP Holdings completed the repricing of the $380 million Term Loan and Revolver. As a
result of the repricing, the interest rate margin on the Term Loan and the Revolver was reduced by 0.25% to LIBOR plus
2.50% with no change to the 1.00% LIBOR floor. An additional 0.25% step down in the interest rate margin will
become effective in the event the Leverage Ratio (as defined in the Credit Agreement) is 2.75:1.00. Additionally, APLP
Holdings amended its existing Term Loan to extend the maturity date by two years to April 2025. The repricing also
adds customary new provisions relating to the replacement of LIBOR as the benchmark for the Eurodollar Rate (as
defined in the Credit Agreement) replacement. The Revolver will mature in April 2022. Targeted debt balances were
adjusted to reflect the previously announced anticipated closing of the sale of our Manchief power plant in 2022,
resulting in lower targeted debt repayment in 2020 and higher targeted debt repayment in 2022 as compared to the
previous schedule.
The Term Loan includes a 3% original issue discount. Letters of credit are available to be issued under the
Revolver until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. In
addition to paying interest on outstanding principal under the Credit Facilities, APLP Holdings is required to pay a
commitment fee of 0.75% times the unused commitments under the Revolver.
The Credit Facilities are secured by a pledge of the equity interests in APLP Holdings and certain of its
subsidiaries, guaranties from certain of the subsidiaries of APLP Holdings (the “Subsidiary Guarantors”), a downstream
F-37
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
guarantee from the Company, a limited recourse guaranty from Atlantic Power GP II, Inc., the entity that holds all of the
equity interest in APLP Holdings, a pledge of certain material contracts and certain mortgages over material real estate
rights, an assignment of all revenues, funds and accounts of APLP Holdings and its subsidiaries (subject to certain
exceptions), and certain other assets. The Credit Facilities also have the benefit of a debt service reserve account, which
is required to be funded and maintained at the debt service reserve requirement, equal to six months of debt service. The
reserve requirement is maintained utilizing a letter of credit. APLP, a wholly-owned, indirect subsidiary of the
Company, is a party to an existing indenture governing its Cdn$210 million aggregate principal amount of MTNs that
prohibits APLP (subject to certain exceptions) from granting liens on its assets (and those of its material subsidiaries) to
secure indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness. Accordingly, in
connection with the execution of the Credit Agreement, APLP Holdings has granted an equal and ratable security
interest in the collateral package securing the Credit Facilities in favor of the trustee under the indenture governing the
MTNs for the benefit of the holders of the MTNs.
The Credit Agreement contains customary representations, warranties, terms and conditions, and covenants.
The negative covenants include a requirement that APLP Holdings and its subsidiaries maintain a Leverage Ratio (as
defined in the Credit Agreement) ranging from 5.00:1.00 at December 2019 to 4.25:1.00 from June 30, 2020, and an
Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 3.25:1.00 at December 31, 2019 to 4.00:1.00
from June 30, 2022. At December 31, 2019, we were in compliance with these covenants. In addition, the Credit
Agreement includes customary restrictions and limitations on APLP Holdings’ and its subsidiaries’ ability to (i) incur
additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into mergers,
consolidations, reorganizations, or certain other corporate transactions, (iv) dispose of assets, (v) modify material
contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and (viii) make dividend
payments or other distributions, in each case subject to certain exceptions and other customary carve-outs and various
thresholds. Specifically, APLP Holdings may be restricted from making dividend payments or other distributions to
Atlantic Power Corporation, and APLP and its subsidiaries may be prohibited from making dividends or distributions to
Atlantic Power Preferred Equity Limited shareholders in the event of a covenant default or if APLP Holdings fails to
achieve a target principal amount on the new Term Loan that declines quarterly based on a predetermined specified
schedule.
Under the Credit Agreement, if a Change of Control (as defined in the Credit Agreement) occurs, unless APLP
Holdings elects to make a voluntary prepayment of the Term Loan under the Credit Facilities, it will be required to offer
each electing lender a prepayment of such lender’s term loan under the Credit Facilities at a price equal to 101% of par.
In addition, in the event that APLP Holdings elects to repay, prepay, refinance or replace all or any portion of the Term
Loan within six months from the repricing date under the Credit Agreement, it will be required to do so at a price of
101% of the principal amount so repaid, prepaid, refinanced or replaced.
The Credit Agreement also contains a mandatory amortization feature and other mandatory prepayment
provisions, including prepayments:
• from the proceeds of asset sales (except from the sale proceeds of certain excluded projects), insurance
proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary
carve-outs; and
• with respect to excess cash flows, to be determined by using the greater of (i) 50% of the cash flow of
APLP Holdings and its subsidiaries that remains after the application of funds, in accordance with a
customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt
service on the Credit Facilities and the MTNs, funding of the debt service reserve account, debt service on
other permitted debt of APLP Holdings and its subsidiaries, capital expenditures permitted under the
Credit Agreement, and payment on the preferred equity issued by Atlantic Power Preferred Equity Ltd., a
F-38
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
subsidiary of APLP Holdings or (ii) such other amount up to 100% of the cash flow described in clause
(i) above that is required to reduce the aggregate principal amount of Term Loan outstanding to achieve a
target principal amount that declines quarterly based on a pre-determined specified schedule. Failure to
achieve the specified target principal amount for any quarter does not constitute a default by APLP
Holdings.
Under certain conditions the lending commitments under the Credit Agreement may be terminated by the
lenders and amounts outstanding under the Credit Agreement may be accelerated. Such events of default include failure
to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations or
warranties in any material respect, non-payment or acceleration of other material debt of APLP Holdings and its
subsidiaries, bankruptcy, material judgments rendered against APLP Holdings or certain of its subsidiaries, certain
ERISA or regulatory events, a Change of Control of APLP Holdings (solely with respect to the Revolver), or defaults
under certain guaranties and collateral documents securing the Credit Facilities, in each case subject to various
exceptions and notice, cure and grace periods.
Notes of the Partnership
Atlantic Power Limited Partnership (the “Partnership”), a wholly-owned subsidiary acquired on November 5,
2011, has outstanding Cdn$210.0 million ($161.7 million as of December 31, 2019) aggregate principal amount of
5.95% senior unsecured notes, due June 2036 (MTNs). Interest on the MTNs is payable semi-annually at 5.95%.
Pursuant to the terms of the MTNs, we must meet certain financial and other covenants, including a financial covenant
generally based on the ratio of debt to capitalization of the Partnership. At December 31, 2019, we were in compliance
with these covenants. The MTNs are guaranteed by Atlantic Power Corporation and Atlantic Power Preferred Equity
Ltd., an indirect, wholly-owned subsidiary acquired in connection with the acquisition of the Partnership.
Non-Recourse Debt
Project-level debt at our consolidated projects is secured by the respective project and its contracts with no
other recourse to us. Project-level debt generally amortizes during the term of the respective revenue-generating
contracts of the projects. The loans have certain financial covenants that must be met in order to distribute available
cash. At December 31, 2019, all of our projects were in compliance with the covenants contained in project-level debt.
Projects that do not meet their debt service coverage ratios are limited from making distributions, but the debt is not
callable or subject to acceleration under the terms of their debt agreements.
13. Convertible debentures
The following table provides details related to outstanding convertible debentures:
6.00% Debentures due January 2025 (Series E) (Cdn $115.0 million) $
6.00% Debentures due December 2019 (Series D) (Cdn $24.7
million)
Less: Unamortized deferred financing costs
Less: Unamortized discount
Total current and long-term convertible debentures
$
2019
2018
88.5 $
84.3
—
(3.8)
(3.6)
81.1 $
18.1
(4.6)
(4.0)
93.8
December 31, December 31,
On April 10, 2019, we redeemed, in full, the aggregate principal amount of Cdn$24.7 million of the outstanding
6.00% Debentures due December 2019 (the “Series D Debentures”) and paid accrued interest of Cdn$0.4 million.
F-39
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Series E Debentures
On January 29, 2018, we closed the Series E Debentures Offering of Cdn$100 million aggregate principal
amount of Series E Debentures. We also granted the underwriters the option to purchase up to an additional
Cdn$15 million aggregate principal amount of Series E Debentures at any time up to 30 days after the date of closing of
the Series E Debentures offering to cover over-allotments. The underwriters exercised that option, for the full
Cdn$15 million aggregate principal amount, on February 2, 2018.
The Series E Debentures have a maturity date of January 31, 2025. The Series E Debentures bear interest at a
rate of 6.00% per year, and are convertible into our common shares at an initial conversion rate of approximately
238.0952 common shares per Cdn$1,000 principal amount, representing a conversion price of Cdn$4.20 per common
share. The Series E Debentures may not be redeemed by the Company prior to January 31, 2021 (except in certain
limited circumstances following a change of control). On and after January 31, 2021 and prior to January 31, 2023, the
Series E Debentures may be redeemed by us, in whole or in part from time to time, on not more than 60 days and not
less than 30 days prior notice at a redemption price equal to their principal amount plus accrued and unpaid interest, if
any, up to but excluding the date set for redemption, provided that the daily volume-weighted average trading price of
our common shares on the Toronto Stock Exchange, averaged for the 20 consecutive trading days ending five trading
days prior to the date on which notice of redemption is provided, is not less than 125% of the conversion price at the
time notice of redemption is given. On and after January 31, 2023 and prior to the maturity date, the Series E Debentures
may be redeemed in whole or in part from time to time, on not more than 60 days and not less than 30 days prior notice,
at a redemption price equal to their principal amount plus accrued and unpaid interest, if any, up to but excluding the
date set for redemption. The Series E Debentures are our direct, subordinated, unsecured obligations and rank equally
with the other series of debentures and with all other future subordinated unsecured indebtedness and rank subordinate to
all of our existing and future senior indebtedness.
On the initial closing date, we received net proceeds from the Series E Debentures offering, after deducting the
underwriting fee and expenses, of approximately Cdn$94.7 million. We received an additional Cdn$14.4 million of net
proceeds from the exercise of the over-allotment option. On March 2, 2018, we redeemed all of the $42.5 million
remaining principal amount of Series C Debentures with the use of a portion of the proceeds from the Series E
Debentures Offering. On March 3, 2018, we redeemed Cdn$56.2 million principal amount of the Series D Debentures
with the remaining proceeds from the Series E Debentures Offering.
Series E Conversion Option
We assessed the conversion option of the Series E Debentures and determined it should be separated from the
host instrument and accounted for as an embedded derivative liability as the conversion option is in a currency different
from our functional currency. Changes in the fair value of the conversion option derivative are recorded in the
consolidated statements of operation. The conversion option derivative was initially measured at fair value
($4.7 million), with the host contract carried at a value equal to the difference between the carrying value of the Series E
Debenture and the fair value of the derivative. Accordingly, no gain or loss was recorded on the initial measurement of
the derivative. The fair value of the conversion option derivative liability was $3.2 million and $1.2 million at
December 31, 2019 and December 31, 2018, respectively. The portion of the proceeds allocated to the separated
derivative also created a discount of $4.7 million, which will be amortized to interest expense over the maturity period of
the Series E Debentures. For additional information, see Note 15, Accounting for derivative instruments and hedging
activities.
F-40
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
14. Fair value of financial instruments
The estimated carrying values and fair values of our recorded financial instruments related to operations are as
follows:
December 31,
2019
2018
Cash and cash equivalents
Restricted cash
Derivative assets current
Derivative assets non-current
Derivative liabilities current
Derivative liabilities non-current
Long-term debt, including current portion
Convertible debentures
Carrying
Carrying
Amount Fair Value Amount
$ 74.9 $
74.9 $ 68.3 $
7.7
0.7
—
12.0
15.9
560.4
88.5
7.7
0.7
—
12.0
15.9
589.5
93.0
2.1
4.2
0.3
4.5
15.4
625.0
102.4
Fair Value
68.3
2.1
4.2
0.3
4.5
15.4
607.6
101.8
Our financial instruments that are recorded at fair value have been classified into levels using a fair value
hierarchy.
The three levels of the fair value hierarchy are defined below:
Level 1—Unadjusted quoted prices available in active markets for identical assets or liabilities as of
the reporting date. Financial assets utilizing Level 1 inputs include active exchange-traded securities.
Level 2—Quoted prices available in active markets for similar assets or liabilities, quoted prices for
identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly
observable, and inputs derived principally from market data.
Level 3—Unobservable inputs from objective sources. These inputs may be based on entity-specific
inputs. Level 3 inputs include all inputs that do not meet the requirements of Level 1 or Level 2.
F-41
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following represents the recurring measurements of fair value hierarchy of our financial assets and
liabilities that were recognized at fair value as of December 31, 2019 and December 31, 2018. Financial assets and
liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
December 31, 2019
Level 1
Level 2
Level 3 Total
Assets:
Cash and cash equivalents
Restricted cash
Derivative instruments asset
Total
Liabilities:
Derivative instruments liability
Total
Assets:
Cash and cash equivalents
Restricted cash
Derivative instruments asset
Total
Liabilities:
Derivative instruments liability
Total
$ 74.9 $
7.7
—
— $ — $ 74.9
7.7
—
0.7
0.7
$ 82.6 $ 0.7 $ — $ 83.3
—
—
$
$
— $ 24.7 $ 3.2 $ 27.9
— $ 24.7 $ 3.2 $ 27.9
December 31, 2018
Level 1
Level 2
Level 3 Total
$ 68.3 $
2.1
—
— $ — $ 68.3
2.1
—
4.5
4.5
$ 70.4 $ 4.5 $ — $ 74.9
—
—
$
$
— $ 18.7 $ 1.2 $ 19.9
— $ 18.7 $ 1.2 $ 19.9
For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the
short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The fair values of our derivative instruments are based upon trades in liquid markets. Valuation model inputs
can generally be verified and valuation techniques do not involve significant judgment. The fair values of such financial
instruments are classified within Level 2 of the fair value hierarchy. We use our best estimates to determine the fair
value of commodity and derivative contracts we hold. These estimates consider various factors including closing
exchange prices, time value, volatility factors and credit exposure. The fair value of each contract is discounted using a
risk free interest rate.
We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on
our credit rating and the credit rating of our counterparties. As of December 31, 2019, the credit valuation adjustments
resulted in a $1.1 million net increase in fair value, which consists of a $0.1 million pre-tax gain in other comprehensive
income and a $1.0 million gain in change in fair value of derivative instruments. As of December 31, 2018, the credit
valuation adjustments resulted in a $1.0 million net increase in fair value, which consists of a $0.1 million pre-tax gain in
other comprehensive income and a $0.9 million gain in change in fair value of derivative instruments.
The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their
short-term nature. The fair value of long-term debt and convertible debentures was determined using quoted market
prices, as well as discounting the remaining contractual cash flows using a rate at which we could issue debt with a
similar maturity as of the balance sheet date.
F-42
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The conversion option derivative for the Series E Debentures is classified within Level 3 of the fair value
hierarchy. The significant unobservable inputs used in developing fair value include the volatility of our common shares
and the fair value of the host contract, which is derived from recent similar convertible debenture offerings from peer
companies. A discounted cash flow valuation technique is utilized to calculate to fair value of the conversion option
derivative.
The following table reconciles, for the year ended December 31, 2019, the beginning and ending balances for
the conversion option derivative liability that is recognized at fair value in the consolidated financial statements, using
significant unobservable inputs:
Beginning balance of liability at January 1, 2019
Total unrealized loss
Currency transaction loss
Ending balance of liability at December 31, 2019
15. Accounting for derivative instruments and hedging activities
Fair value
Measurement
Using Significant
Unobservable
Inputs (Level 3)
Year Ended
December 31, 2019
$
$
1.2
1.8
0.2
3.2
We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at
fair value each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective
portion of the change in fair value of the derivatives in accumulated other comprehensive (loss) income, until the hedged
transactions occur and are recognized in (loss) earnings. The ineffective portion of a cash flow hedge is immediately
recognized in (loss) earnings. For our other derivatives that are not designated as cash flow hedges, the changes in the
fair value are immediately recognized in (loss) earnings. These guidelines apply to our natural gas swaps, interest rate
swaps, and foreign exchange contracts.
Gas purchase and sale agreements
We have a gas purchase agreement at our Nipigon project that expires on December 31, 2022 under which we
purchase a minimum of 6,500 Gigajoules (“Gj”) of natural gas per day at a price of Cdn$4.57 per Gj. This agreement
does not qualify for the normal purchase normal sales (“NPNS”) exemption and is accounted for as a derivative financial
instrument because we could not conclude that it is probable that this contract will not settle net and will result in
physical delivery. This derivative financial instrument is recorded in the consolidated balance sheets at fair value and the
changes in its fair market value is recorded in the consolidated statements of operations. We also have a corresponding
gas sales agreement at Nipigon, whereby 6,500 Gj of natural gas per day is sold at the spot market price. This contract is
not accounted for as a derivative.
On April 23, 2019, we also entered into natural gas purchase agreements at our Morris project for
approximately 700,000 MMBtu to effectively mitigate seasonal fluctuations of future natural gas prices from January
2020 through February 2020. This contract is accounted for as a derivative financial instrument and is recorded in the
consolidated balance sheet at fair value. Changes in the fair market value of this contract are recorded in the consolidated
statement of operations.
F-43
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Natural gas swaps
Our strategy to mitigate future exposure to changes in natural gas prices at our projects consists of periodically
entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These
natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheets at fair value
and the changes in their fair market value are recorded in the consolidated statements of operations.
We have entered into various natural gas swaps to effectively fix the price of 16.3 million MMBtu of future
natural gas purchases at our Orlando project, which is approximately 100% of our share of the expected natural gas
purchases in 2020 through 2023. These contracts are accounted for as derivative financial instruments and are recorded
in the consolidated balance sheet at fair value at December 31, 2019. Changes in the fair market value of these contracts
are recorded in the consolidated statement of operations.
Interest rate swaps
APLP Holdings has entered into several interest rate swap agreements to mitigate its exposure to changes in
interest at the Adjusted Eurodollar Rate. At December 31, 2019, these agreements totaled $370.6 million notional
amount of the remaining $380.0 million aggregate principal amount of borrowings under the Term Loan. These interest
rate swap agreements expire at various dates through March 31, 2022. Borrowings under the Term Loan bear interest at
a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 2.75%. Based on the terms of the Credit
Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00%, resulting in a minimum of a 3.75% all-in rate on
the Term Loan for the non-swapped portion of the remaining principal amount. The weighted average rate of these swap
agreements is 2.00%, resulting in an all-in rate of approximately 4.75% for $370.6 million of the Term Loan. In
February 2020, APLP Holdings entered into additional interest rate swap agreements. For the period beginning
March 31, 2020 through December 31, 2021, we mitigated exposure to changes in interest rates a one-month LIBOR
fixed rate of 1.39%. The notional amount of these interest rate swap agreements range between $9.4 million and
$45.0 million and are sized to the targeted debt balance payments over that period.
The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.1% through
February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the
interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac’s debt. This
swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the
effective portion of the changes in the fair market value is recorded in accumulated other comprehensive (loss) income.
Foreign currency forward contracts
We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates as we
generate cash flow in U.S. dollars and Canadian dollars. We currently have Canadian dollar payment obligations for
preferred dividends, interest on our Canadian dollar-denominated convertible debentures and our MTNs due June 23,
2036. Principal and interest payments for our Term Loan are made in U.S. dollars. We have a hedging strategy for the
purpose of mitigating the currency risk impact on the future interest and principal payments, preferred dividends and
other working capital requirements. Foreign currency forward contracts are not designated as hedges, and changes in
their market value are recorded in foreign exchange on the consolidated statements of operations. As of December 31,
2019, we have no foreign currency forward contracts.
F-44
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Volume of forecasted transactions
We have entered into derivative instruments in order to economically hedge the following notional volumes of
forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS
exemption at December 31, 2019 and December 31, 2018:
Natural gas swaps
Gas purchase agreements
Interest rate swaps
Fair value of derivative instruments
Units
December 31, December 31,
2019
2018
Natural Gas (MMbtu)
Natural Gas (Gigajoules)
Interest (US$)
16.3
6.4
468.4
16.3
9.0
616.6
We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not
offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our
derivative assets and liabilities:
December 31, 2019
Derivative
Assets
Derivative
Liabilities
$
— $
—
—
0.4
1.1
1.5
—
—
—
0.7
—
—
0.7
0.7 $
1.9
1.1
1.9
4.2
4.6
9.5
3.2
26.4
27.9
Derivative instruments designated as cash flow hedges:
Interest rate swaps current
Interest rate swaps long-term
Total derivative instruments designated as cash flow hedges
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current
Interest rate swaps long-term
Natural gas swaps current
Natural gas swaps long-term
Gas purchase agreements current
Gas purchase agreements long-term
Convertible debenture conversion option
Total derivative instruments not designated as cash flow hedges
Total derivative instruments
$
F-45
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Derivative instruments designated as cash flow hedges:
Interest rate swaps current
Interest rate swaps long-term
Total derivative instruments designated as cash flow hedges
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current
Interest rate swaps long-term
Natural gas swaps current
Natural gas swaps long-term
Gas purchase agreements current
Gas purchase agreements long-term
Convertible debenture conversion option
Total derivative instruments not designated as cash flow hedges
Total derivative instruments
$
Accumulated other comprehensive income
December 31, 2018
Derivative
Assets
Derivative
Liabilities
$
— $
—
—
0.4
1.0
1.4
4.2
0.3
—
—
—
—
—
4.5
4.5 $
—
—
0.1
1.4
2.8
13.0
1.2
18.5
19.9
The following table summarizes the changes in the accumulated other comprehensive income (“OCI”) balance
attributable to derivative financial instruments designated as a hedge, net of tax:
Year Ended December 31, 2019
Accumulated OCI balance at January 1, 2019
Change in fair value of cash flow hedges
Realized from OCI during the period
Accumulated OCI balance at December 31, 2019
Settlements expected to be recognized from OCI in expense in the
next 12 months, net of $0.1 million of tax
Year Ended December 31, 2018
Accumulated OCI balance at January 1, 2018
Change in fair value of cash flow hedges
Realized from OCI during the period
Accumulated OCI balance at December 31, 2018
Interest Rate
Swaps
Interest Rate
Swaps
1.6
(0.3)
0.3
1.6
0.3
1.1
0.4
0.1
1.6
$
$
$
$
$
F-46
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Impact of derivative instruments on the consolidated statements of operations
The following table summarizes realized loss (gain) for derivative instruments not designated as cash flow
hedges:
Gas purchase agreements
Natural gas swaps
Interest rate swaps
Classification of loss (gain)
recognized in income
Fuel
Fuel
Interest, net
Year Ended December 31,
2018
2017
2019
$ 8.2 $ 4.1 $ 7.5
0.4
0.9
0.9
(3.2)
0.3
(3.3)
The following table summarizes the unrealized (loss) gain resulting from changes in the fair value of derivative
financial instruments that are not designated as cash flow hedges:
Natural gas swaps
Gas purchase agreements
Interest rate swaps
Convertible debenture conversion option
Foreign currency forwards
16. Income tax expense
2019
Classification of (loss) gain
recognized in income
Year ended December 31,
2017
2018
Change in fair value of derivatives $ (4.6) $ (0.5) $ (1.8)
(5.0)
Change in fair value of derivatives
8.9
Change in fair value of derivatives
2.1
—
$ — $ 0.1 $ —
Other expense (income), net
Foreign exchange loss
3.2
(7.5)
(8.9)
1.8
3.7
(1.0)
2.2
(1.2)
The following table summarizes the current and deferred portions of the net income tax expense (benefit) by
jurisdiction:
Current income tax expense
Deferred income tax expense (benefit)
Total income tax expense (benefit), net
2019
Year Ended December 31,
2018
2017
$
$
4.9 $
4.9
9.8
$
3.8
(3.6)
0.2
$
$
4.1
(62.2)
(58.1)
F-47
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following is a reconciliation of the income taxes calculated at the Canadian enacted statutory rate of 27%
for the years ended December 31, 2019, 2018 and 2017, respectively, to the provision for income taxes in the
consolidated statements of operations:
Computed income tax (benefit) expense at Canadian statutory rate
Increases (decreases) resulting from:
Operating in countries with different income tax rates
Change in valuation allowance
Dividend withholding tax and other cash taxes
Foreign exchange
Changes in tax rates
Remeasurement of deferred tax assets and liabilities
Capital gain (loss) on intercompany notes
Impairments
Other
Income tax expense (benefit)
$
Year Ended December 31,
2018
2017
2019
(9.2)
0.1
(9.1)
5.7
(3.4)
1.3
1.7
2.2
—
0.1
7.7
0.2
13.2
9.8
$
10.1
0.1
10.2
(6.7)
3.5
0.5
—
(3.3)
—
(1.1)
—
0.6
(3.3)
0.2
$
(39.3)
(20.1)
(59.4)
(34.6)
(94.0)
0.2
(2.4)
(1.5)
28.5
(0.1)
9.9
1.3
35.9
(58.1)
F-48
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and
deferred tax liabilities at December 31, 2019 and 2018 are presented below:
Deferred tax assets:
Loss carryforwards
Capital loss carryforwards
Interest expense limitation carryforwards
Finance and share issuance costs
Tax Credits
Stock-based compensation
Derivative contracts
Other long-term notes
Other
Total deferred tax assets
Less: Valuation allowance
Deferred tax liabilities:
Intangible assets
Property, plant and equipment
Basis difference in joint ventures
Other long-term investments
Total deferred tax liabilities
Net deferred tax liability
Net deferred tax (liability) asset by jurisdiction
U.S. Federal and State
Canada
Net deferred tax liability
2019
2018
$ 135.9 $ 163.3
34.4
10.9
0.5
1.4
2.9
3.2
1.5
—
218.1
(139.7)
78.4
35.8
9.7
0.1
1.4
2.4
5.7
—
0.9
191.9
(145.4)
46.5
(21.9)
(31.2)
(5.4)
(1.3)
(59.8)
(13.3)
(30.0)
(41.9)
(15.5)
—
(87.4)
(9.0)
$
2019
(23.7) $
10.4
(13.3)
2018
(16.0)
7.0
(9.0)
Income tax expense for the year ended December 31, 2019 was $9.8 million. Expected income tax benefit for
the same period, based on the Canadian enacted statutory rate of 27%, was $9.2 million. The primary items impacting
the tax rate for the year ended December 31, 2019 were $7.7 million related to impairments and a net increase to our
valuation allowances of $5.7 million, consisting of $7.9 million increases in Canada and $2.2 million decreases in the
United States. In addition, the rate was further impacted by $2.2 million related to changes in tax rates, $1.7 million
relating to foreign exchange, $1.3 million relating to withholding and state taxes and $0.4 million of other permanent
differences.
Income tax expense for the year ended December 31, 2018 was $0.2 million. Expected income tax expense for
the same period, based on the Canadian enacted statutory rate of 27%, was $10.1 million. The primary items impacting
the tax rate for the twelve months ended December 31, 2018 were $0.5 million relating to withholding and state taxes
and $0.7 million of other permanent differences. These items were offset by a net decrease to our valuation allowance of
$6.7 million, consisting of $0.1 million of decreases in Canada due to utilization of net operating losses and $6.6 million
decreases in the United States. Based on initiatives recently completed, we determined that sufficient deferred tax
liabilities were likely to reverse in a timely manner against certain deferred tax assets, resulting in a reduction of the
valuation allowance in the United States. In addition, the rate was further impacted by $3.3 million relating to changes in
tax rates and $1.1 million related to capital loss on intercompany notes.
F-49
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
During the preparation of our 2019 consolidated financial statements, we identified an immaterial error in our
previously issued financial statements relating to the presentation of deferred taxes in accordance with ASC 740 -
Income Taxes. Under this guidance, entities are prohibited from offsetting deferred tax liabilities from one jurisdiction
against deferred tax assets of another jurisdiction. At December 31, 2018, we recorded deferred tax assets in Canada of
$7.0 million and deferred tax liabilities of $16.0 million in the U.S. Prior to the correction, we presented a net deferred
tax liability of $9.0 million. The prior period balance sheet has been revised to correct this error. This reclassification did
not impact the consolidated statement of operations or consolidated statement of cash flows.
Valuation allowances are reserves that have been recorded to offset some or all of its deferred tax assets. The
amount of the allowances recorded have been based on that portion of the tax assets for which evidence suggests it is
more likely than not that a tax benefit will not be realized. As of December 31, 2019, we have recorded a valuation
allowance of $145.4 million. This amount is comprised primarily of provisions against available Canadian and U.S. net
operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more
likely than not that some portion or all of the deferred tax asset will be realized. The ultimate realization of the deferred
tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax
planning strategies.
As of December 31, 2019, we had the following net operating loss carryforwards that are scheduled to expire in
the following years:
U.S.
$
Canada Total
- $ 27.3 $ 27.3
41.1
-
25.8
-
19.2
5.8
44.1
23.5
131.4
9.1
154.1
-
37.3
20.3
25.6
8.9
10.1
10.1
6.9
6.9
$ 411.0 $ 111.9 $ 522.9
41.1
25.8
13.4
20.6
122.3
154.1
17.0
16.7
-
-
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
F-50
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
17. Equity compensation plans
Long-term incentive plan (“LTIP”)
The following table summarizes the changes in outstanding LTIP notional shares during the years ended
December 31, 2019, 2018 and 2017:
Outstanding at December 31, 2016
Granted
Vested and redeemed
Forfeitures
Outstanding at December 31, 2017
Granted
Vested and redeemed
Forfeitures
Outstanding at December 31, 2018
Granted
Vested and redeemed
Forfeitures
Outstanding at December 31, 2019
Grant Date
Weighted-Average
Notional Shares Fair Value per Notional Share
2.08
2.38
2.22
2.32
2.22
2.02
2.22
2.09
2.09
2.72
2.10
2.17
2.38
2,101,118 $
1,817,463
(1,009,780)
(24,227)
2,884,574
2,483,237
(1,388,671)
(26,939)
3,952,201
1,724,081
(2,071,335)
(26,855)
3,578,092 $
On March 29, 2019, the compensation committee of our board of directors determined that all notional shares
granted under the LTIP held by non-officer employees will be settled in cash following vesting, rather than two-thirds in
common shares and one-third in cash, with the cash portion being utilized to satisfy the tax withholding and remittance
obligations related to the common share settlement. As a result of the modification, all future vesting of notional shares
for this employee group will be settled in cash. The portion of LTIP grants settled in common shares was accounted for
as equity awards. On the modification date, the equity awards were reclassified as liability awards and a liability equal to
the modification-date fair value was recognized. The impact of the modification was not material on the date of the
change in accounting.
The total grant date fair value of all outstanding notional shares under the LTIP was $8.5 million, $8.3 million
and $6.4 million for the years ended December 31, 2019, 2018 and 2017. The weighted average remaining vesting term
for outstanding notional shares was 1.7 years at December 31, 2019. Approximately $3.6 million of total unrecognized
compensation expense is expected to be recognized over the term of the outstanding LTIP shares. Compensation expense
related to LTIP was $4.9 million, $3.6 million and $3.4 million for the years ended December 31, 2019, 2018 and 2017,
respectively. Cash payments made for vested notional shares were $2.1 million, $0.9 million and $0.7 million for the
years ended December 31, 2019, 2018 and 2017, respectively.
Transition Equity Participation Agreement
We also have 269,952 transition notional shares outstanding at December 31, 2019 under the Transition Equity
Participation Agreement with James J. Moore, Jr. These notional shares will vest on or any time after January 22, 2017 if
the weighted average Canadian dollar closing price of our common shares on the TSX for a period of at least three
consecutive calendar months has exceeded the market price per common share determined as of January 22, 2015
(Cdn$3.18) by at least 50% (Cdn$4.77). These notional shares will also vest in the event that Mr. Moore is terminated
F-51
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
without cause, resigns for good reason, or dies.
18. Employee benefit plans
Defined benefit pension plan
We sponsor and operate a defined benefit pension plan that is available to certain legacy employees of Atlantic
Power Limited. The Atlantic Power Services Canada LP Pension Plan (the “Plan”) is maintained solely for certain
eligible legacy Partnership participants. The Plan is a defined benefit pension plan that allows for employee
contributions. We expect to contribute $0.4 million to the pension plan in 2020.
The net annual periodic pension cost related to the pension plan for the years ended December 31, 2019, 2018
and 2017 includes the following components:
Service cost benefits earned
Interest cost on benefit obligation
Expected return on plan assets
Settlements
Net period benefit cost
2019
$
2018
2017
0.3 $
0.5
(0.7)
0.3
0.4 $
0.3 $
0.5
(0.7)
—
0.1 $
0.5
0.6
(0.9)
—
0.2
$
A comparison of the pension benefit obligation and related plan assets for the pension plan at December 31 is as
follows:
2019
2018
Projected benefit obligation at January 1
Service cost
Interest cost
Actuarial (gain) loss
Employee contributions
Benefits paid
Settlements
Foreign currency adjustment
Projected benefit obligation at December 31
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Employee contributions
Benefits paid
Settlements
Foreign currency adjustment
Fair value of plan assets at December 31
Funded status at December 31-excess of obligation over assets
Amounts recognized in the balance sheet at December 31 were as follows:
(0.3)
(0.5)
(2.0)
(0.1)
0.2
2.4
(0.6)
(14.1)
$ (13.2) $ (15.8)
(0.3)
(0.5)
1.4
(0.1)
0.8
—
1.3
(13.2)
$ 12.0 $ 13.9
(0.4)
0.4
0.1
(0.8)
—
(1.2)
12.0
(1.2)
2.0
0.8
0.1
(0.2)
(2.4)
0.6
12.9
(1.2) $
$
Non-current liabilities
2019
2018
$
1.2 $
1.2
F-52
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Amounts recognized in accumulated OCL that have not yet been recognized as components of net periodic
benefit cost were as follows, net of tax:
Unrecognized (gain) loss
2019
(1.7) $
2018
1.4
$
We estimate that there will be no amortization of net loss for the pension plan from accumulated OCI to net
periodic cost over the next fiscal year.
The following table presents the balances of significant components of the pension plan:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
2019
2018
$ 14.1 $ 13.2
12.2
12.0
12.9
12.9
The market-related value of the pension plan’s assets is the fair value of the assets. Plan assets are invested in a
common collective trust which totaled $12.9 million and $12.0 million for the years ended December 31, 2019 and 2018,
respectively.
We determine the level in the fair value hierarchy within which the fair value measurement in its entirety falls,
based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the
common/collective trust is valued at a fair value which is equal to the sum of the market value of the fund’s investments,
and is categorized as Level 2. There are no investments categorized as Level 1 or 3.
The following table presents the significant assumptions used to calculate our benefit obligations:
Weighted-Average Assumptions
Discount rate
Rate of compensation increase
2019
2018
3.25 %
2.0 %
4.0 %
2.0 %
The following table presents the significant assumptions used to calculate our benefit expense:
Weighted-Average Assumptions
Discount rate
Rate of return on plan assets
Rate of compensation increase
2019 2018
2017
4.0 %
5.8 %
2.0 %
3.5 %
5.8 %
2.0 %
4.0 %
5.8 %
2.0 %
We use December 31 as the measurement date for the Plan, and we set the discount rate assumptions on an
annual basis on the measurement date. This rate is determined by management based on information agreed with our
actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively
settled at the end of the year. The discount rate assumptions used to determine future pension obligations as of the year
ended December 31, 2019, 2018 and 2017, were based on the CIA / Fiera curve, which was designed by the Canadian
Institute of Actuaries and Fiera Capital Investment Management Inc. to provide a means for sponsors of Canadian plans
to value the liabilities of their pension and postretirement benefit plans. The CIA / Fiera curve is a hypothetical yield
curve represented by extrapolating the corporate AA-rated yield curve beyond 10 years using yields on provincial AA
bonds with a spread added to the provincial AA yields to approximate the difference between corporate AA and
F-53
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
provincial AA credit risk. The CIA / Fiera curve utilizes this approach because there are very few corporate bonds rated
AA or above with maturities of 10 years or more in Canada.
We employ a balanced total return investment approach, whereby a mix of equities and fixed income
investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is
established through careful consideration of plan liabilities, and the plan’s funded status. Plan assets in the common
collective trust are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity
investments are diversified across Canadian, U.S. and other international equities, as well as among growth, value and
small and large capitalization stocks.
The pension plan assets weighted average allocations in the common collective trust were as follows:
Canadian equity
U.S. equity
International equity
Canadian fixed income
Real estate equities
2019
2018
30 %
14 %
14 %
39 %
3 %
100 %
29 %
14 %
13 %
41 %
3 %
100 %
Our expected future benefit payments for each of the next five years and in the aggregate for the five years
thereafter, are as follows in Cdn$:
Years ending December 31,
2020
2021
2022
2023
2024
2025-2029
Defined Contribution Plans
Cdn$
0.4
0.5
0.6
0.7
0.8
4.7
We maintain a 401(k) retirement savings plan, registered retirement savings plan, and another defined
contribution plan for the benefit of our eligible employees. Substantially all of our employees who meet certain service
and age requirements are eligible to participate in these plans. Our plan documents provide that any matching
contributions by us are discretionary. We have made or accrued matching contributions to these plans of $1.3 million,
$1.4 million, and $1.2 million for the years ended December 31, 2019, 2018 and 2017, respectively.
19. Common shares
Our common shares have no par value and unlimited authorization. We had 108,675,294 and 108,341,738
common shares issued and outstanding at December 31, 2019 and December 31, 2018, respectively.
Stock Repurchase Program
During the year ended December 31, 2019, we repurchased and canceled 1,064,081 common shares at a total
cost of approximately $2.5 million under an NCIB that expired on December 30, 2019. In the year ended December 31,
2018, we repurchased and canceled 7,772,971 common shares at a total cost of approximately $16.6 million.
F-54
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
On December 31, 2019, we commenced a new NCIB for our Series E Debentures, our common shares and for
each series of the preferred shares of APPEL, our wholly-owned subsidiary. The NCIBs expire on December 30, 2020 or
such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB. Under the
NCIBs, we may purchase up to a total of 10,578,799 common shares based on 10% of our public float as of
December 17, 2019 and we are limited to daily purchases of 9,243 common shares per day with certain exceptions
including block purchases and purchases on other approved exchanges. All purchases made under the NCIBs will be
made through the facilities of the TSX or other Canadian designated exchanges and published marketplaces and in
accordance with the rules of the TSX at market prices prevailing at the time of purchase. Common share purchases under
the NCIBs may also be made on the New York Stock Exchange in compliance with Rule 10b-18 under the Exchange
Act, as amended, or other designated exchanges and published marketplaces in the U.S. in accordance with applicable
regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory
approval.
The Board authorization permits the Company to repurchase common and preferred shares and convertible
debentures. Therefore, in addition to the current NCIBs, from time to time we may repurchase our securities, including
our common shares, our convertible debentures and our APPEL preferred shares through open market purchases,
including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the Exchange Act, as amended,
NCIBs, issuer self tender or substantial issuer bids, or in privately negotiated transactions. There can be no assurances as
to the amount, timing or prices of repurchases, which may vary based on market conditions, other market opportunities
and other factors. Any share repurchases outside of previously authorized NCIBs would be effected after taking into
account our then current cash position and then anticipated cash obligations or business opportunities.
Subsequent to December 31, 2019 and through February 26, 2020, we have repurchased and cancelled
1,742,919 common shares at a cost of $4.1 million under the new NCIB.
Shelf Registration
On February 9, 2016, we announced the elimination of our common stock dividend, effective immediately. In
conjunction with the elimination of the common stock dividend, our dividend reinvestment plan (the “Plan”) also was
eliminated. We filed a post-effective amendment to our registration statement on Form S-3 (Registration
No. 333-194204) to deregister all of the Company’s common shares that remain unissued under the Plan.
20. Preferred shares issued by a subsidiary company
In 2007, a subsidiary acquired in our acquisition of the Partnership issued 5.0 million 4.85% Cumulative
Redeemable Preferred Shares, Series 1 (the “Series 1 Shares”) priced at Cdn$25.00 per share. Cumulative dividends are
payable on a quarterly basis. The Series 1 Shares are redeemable by the subsidiary company at Cdn$25.00 per share,
plus an amount equal to all accrued and unpaid dividends thereon. At December 31, 2019, there were 3,847,500 Series 1
Shares outstanding.
In 2009, a subsidiary company acquired in our acquisition of the Partnership issued 4.0 million 7.0%
Cumulative Rate Reset Preferred Shares, Series 2 (the “Series 2 Shares”) priced at Cdn$25.00 per share. The Series 2
Shares pays a fixed dividend when declared. The dividend on the Series 2 Shares is cumulative. Beginning on
December 31, 2014 and each fifth-year anniversary thereafter, (i) the rate on the Series 2 shares is reset at a rate equal to
the sum of the then five-year Government of Canada bond yield and 4.18%, and (ii) holders of Series 2 Shares have the
right, subject to certain limitations, to convert their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the
“Series 3 Shares”) of the subsidiary. On December 31, 2019, the rate on the Series 2 Shares was reset to 5.67% and
holders of the Series 2 Shares converted 23,618 Series 2 Shares into Series 3 Shares.
F-55
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The holders of Series 3 Shares are entitled to receive quarterly floating rate dividends, as and when declared by
the board of directors of the subsidiary, at a rate equal to the sum of the then 90-day Government of Canada Treasury bill
rate and 4.18%. The dividend on the Series 3 Shares is cumulative. The dividend rate for the Series 3 Shares was reset on
December 31, 2019 to 5.83%. Beginning on December 31, 2019, and on each fifth-year anniversary thereafter, holders
of Series 3 Shares have the right, subject to certain limitations, to convert their shares into Series 2 Shares. On
December 31, 2019, the rate on the Series 3 Shares was reset to 5.83% and holders of the Series 3 Shares converted
295,032 Series 3 Shares into Series 2 Shares.
The Series 2 Shares and Series 3 Shares are redeemable by the subsidiary company at Cdn$25.00 per share,
plus an amount equal to all accrued and unpaid dividends thereon. At December 31, 2019, there were 2,504,131 Series 2
Shares and 1,077,391 Series 3 Shares outstanding.
The Series 1 Shares, the Series 2 Shares and the Series 3 Shares are fully and unconditionally guaranteed by us
and by the Partnership on a subordinated basis as to: (i) the payment of dividends, as and when declared; (ii) the
payment of amounts due on a redemption for cash; and (iii) the payment of amounts due on the liquidation, dissolution
or winding up of the subsidiary company. If, and for so long as, the declaration or payment of dividends on the Series 1
Shares, the Series 2 Shares or the Series 3 Shares is in arrears, the Partnership will not make any distributions on its
limited partnership units and we will not pay any dividends on our common shares.
The Series 1, 2 and 3 Shares are accounted for as a non-controlling interest on our consolidated balance sheets
and consolidated statements of operations. The subsidiary company paid aggregate dividends of $7.4 million,
$8.3 million and $8.7 million for the years ended December 31, 2019, 2018 and 2017, respectively. In 2019, we
repurchased and cancelled 427,500 of the Series 1 Shares, 100,377 of the Series 2 Shares and 148,311 Series 3 Shares,
respectively for a total cost of $8.0 million. We also repurchased and cancelled preferred shares at a cost of $8.0 million
and $3.1 million in the years ended December 31, 2018 and 2017, respectively. As a result of the repurchases, losses of
$8.6 million, $7.9 million and $3.0 million were attributed to the preferred shares of a subsidiary company in the
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017, respectively.
Subsequent to December 31, 2019 and through February 26, 2020, we repurchased and cancelled 247,894
Series 1 Shares at a cost of $3.1 million.
21. Basic and diluted (loss) earnings per share
Basic (loss) earnings per share is calculated by dividing net (loss) income attributable to Atlantic Power
Corporation by the weighted average common shares outstanding during their respective periods. Shares issued and
shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted (loss)
earnings per share is computed in a manner consistent with that of basic (loss) earnings per share while giving effect to
all potentially dilutive common shares that were outstanding during the period. The dilutive effect of our convertible
debentures is calculated using the “if-converted method.” Under the if-converted method, the debentures are assumed to
be converted at the beginning of the period, and the resulting common shares are included in the denominator of the
diluted (loss) earnings per share calculation for the entire period being presented. Interest expense, net of any income tax
effects, would be added back to the numerator for purposes of the if-converted calculation. The outstanding equity
compensation for non-vested LTIP and Transition Equity Participation Agreement notional shares are not considered
outstanding for purposes of computing basic (loss) earnings per share. However, these instruments are included in the
denominator, when dilutive, for purposes of computing diluted (loss) earnings per share under the treasury stock method.
F-56
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table sets forth the diluted net (loss) income and potentially dilutive shares utilized in the per
share calculation for the years ended December 31, 2019, 2018 and 2017:
Basic
Numerator:
(Loss) income attributable to Atlantic Power Corporation
Denominator:
Weighted average basic shares outstanding
Basic (loss) earnings per share attributable to Atlantic Power Corporation
Diluted
Numerator:
Net (loss) income attributable to Atlantic Power Corporation
Add: convertible debenture interest expense
Denominator:
Weighted average basic shares outstanding
Convertible debentures
Share-based compensation
Diluted (loss) earnings per share attributable to Atlantic Power Corporation
2019
2018
2017
$
(42.6) $
36.8 $
(98.6)
109.3
(0.39) $
112.0
0.33 $
115.1
(0.86)
$
(42.6)
—
(42.6)
109.3
—
—
109.3
(0.39)
36.8
4.7
41.5
112.0
27.8
2.0
141.8
0.29
(98.6)
—
(98.6)
115.1
—
—
115.1
(0.86)
The following table summarizes our outstanding instruments that are anti-dilutive and were not included in the
computation of our diluted (loss) `earnings per share:
Share-based compensation
Convertible debentures
Total
22. Segment and geographic information
2019
1.5
27.8
29.3
2018
—
—
—
2017
1.6
8.1
9.7
We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our
reportable business segments in the fourth quarter of 2019 as the result of recent acquisitions, PPA expirations and
project decommissioning and in order to align with changes to management’s structure, resource allocation and
performance assessment in making decisions regarding our operations. Our financial results for the years ended
December 31, 2018 and 2017 have been revised to reflect these changes in operating segments. The segment classified
as Corporate (formerly Un-Allocated Corporate) includes activities that support the executive and administrative offices,
capital structure, costs of being a public registrant, costs to develop future projects and intercompany eliminations. These
costs are not allocated to the operating segments when determining segment profit or loss.
We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as
project (loss) income plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and
changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and
does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar
measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about
segment performance without considering how projects are capitalized or whether they contain derivative contracts that
are required to be recorded at fair value. Our equity investments in unconsolidated affiliates are presented on a
proportionally consolidated basis in Project Adjusted EBITDA and in the reconciliation of Project Adjusted EBITDA to
project (loss) income.
F-57
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
A reconciliation of Project Adjusted EBITDA to net (loss) income is included in the tables below:
Year Ended December 31, 2019
Project revenues
Segment assets
Goodwill
Capital expenditures
Project Adjusted EBITDA
Change in fair value of derivative instruments
Depreciation and amortization
Interest, net
Insurance loss
Impairment
Other project expense
Project (loss) income
Administration
Interest expense, net
Foreign exchange loss
Other expense, net
Net (loss) income before income taxes
Income tax expense
Net (loss) income
Year Ended December 31, 2018
Project revenues
Segment assets
Goodwill
Capital expenditures
Project Adjusted EBITDA
Change in fair value of derivative instruments
Depreciation and amortization
Interest, net
Other project expense (income)
Project income (loss)
Administration
Interest expense, net
Foreign exchange gain
Other income, net
Net income (loss) before income taxes
Income tax expense
Net income (loss)
Solid Fuel Natural Gas Hydroelectric Corporate
Consolidated
$ 80.0 $
222.7
—
6.8
$ 32.7 $
—
23.9
2.6
1.0
55.0
—
(49.8)
—
—
—
—
(49.8)
—
$ (49.8) $
131.8 $
241.0
6.9
0.1
108.2 $
1.4
37.2
(0.1)
—
—
1.2
68.5
—
—
—
—
68.5
—
68.5 $
68.8 $
388.3
14.4
0.4
55.5 $
—
19.5
—
—
—
—
36.0
—
—
—
—
36.0
—
36.0 $
1.0 $
83.6
—
—
(0.3) $
7.5
0.1
—
—
—
—
(7.9)
23.9
44.0
11.9
1.0
(88.7)
9.8
(98.5) $
281.6
935.6
21.3
7.3
196.1
8.9
80.7
2.5
1.0
55.0
1.2
46.8
23.9
44.0
11.9
1.0
(34.0)
9.8
(43.8)
Solid Fuel Natural Gas Hydroelectric Corporate Consolidated
1.0 $
87.9
—
0.3
0.5 $
1.0
0.1
—
—
(0.6)
23.9
52.7
(22.8)
(3.0)
(51.4)
0.2
(51.6) $
282.3
1,031.5
21.3
1.8
185.1
(2.2)
99.7
3.4
(4.0)
88.2
23.9
52.7
(22.8)
(3.0)
37.4
0.2
37.2
$ 83.8 $
258.3
—
1.3
$ 46.7 $
—
23.7
3.3
—
19.7
—
—
—
—
19.7
—
$ 19.7 $
139.2 $
280.8
6.9
—
90.4 $
(3.2)
57.0
0.1
3.2
33.3
—
—
—
—
33.3
—
33.3 $
58.3 $
404.5
14.4
0.2
47.5 $
—
18.9
—
(7.2)
35.8
—
—
—
—
35.8
—
35.8 $
F-58
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Solid Fuel Natural Gas Hydroelectric Corporate Consolidated
Year Ended December 31, 2017
Project revenues
Segment assets
Goodwill
Capital expenditures
Project Adjusted EBITDA
Change in fair value of derivative instruments
Depreciation and amortization
Interest, net
Impairment
Other project (income) expense
Project (loss) income
Administration
Interest, net
Foreign exchange loss
Other income, net
Net (loss) income before income taxes
Income tax benefit
Net (loss) income
$ 93.7 $
284.2
—
4.7
$ 54.9 $
(8.1)
30.4
19.1
76.2
(0.1)
(62.6) $
—
—
—
—
(62.6)
—
$ (62.6) $
276.8 $
369.0
6.9
—
185.3 $
7.9
84.5
0.1
96.2
(1.0)
(2.4) $
—
—
—
—
(2.4)
—
(2.4) $
59.5 $
408.8
14.4
0.8
47.2 $
—
17.7
—
14.7
—
14.8 $
—
—
—
—
14.8
—
14.8 $
1.0 $
96.8
—
—
1.4 $
(1.9)
0.6
—
—
(0.1)
2.8
23.6
64.2
16.3
(0.4)
(100.9)
(58.1)
(42.8) $
431.0
1,158.8
21.3
5.5
288.8
(2.1)
133.2
19.2
187.1
(1.2)
(47.4)
23.6
64.2
16.3
(0.4)
(151.1)
(58.1)
(93.0)
The table below provides information, by country, about our consolidated operations for each of the years
ended December 31, 2019, 2018 and 2017 and Property, Plant and Equipment, PPAs and other Intangible and total
assets as of December 31, 2019 and 2018, respectively. Revenue is recorded in the country in which it is earned and
assets are recorded in the country in which they are located.
United States
Canada
Total
United States
Canada
Total
$
$
2019
208.4 $
73.2
281.6 $
Revenue
2018
203.4 $
78.9
282.3 $
2017
262.4
168.6
431.0
Property, Plant and
Equipment, net of
accumulated depreciation
PPAs and
other intangible assets, net of
accumulated amortization
Total assets
2019
353.9 $
148.2
502.1 $
2018
396.5 $
153.0
549.5 $
2019
142.8 $
1.5
144.3 $
$
$
2019
2018
165.9 $ 762.3 $
4.2 173.3
2018
842.2
189.3
170.1 $ 935.6 $ 1,031.5
Niagara Mohawk Power Corporation, IESO, Equistar Chemicals L. P. and Georgia Power Company provided
19.6%, 12.9%, 12.0% and 11.1%, respectively, of total consolidated revenues for the year ended December 31, 2019.
Niagara Mohawk, Atlantic City Electric, BC Hydro, Georgia Power Company and IESO provided 15.1%, 12.6%,
12.5%, 10.9% and 10.8%, respectively, of total consolidated revenues for the year ended December 31, 2018. IESO,
Niagara Mohawk, San Diego Gas & Electric and BC Hydro provided 20.3%, 10.7%, 10.6% and 10.3%, respectively, of
total consolidated revenues for the year ended December 31, 2017. IESO purchased electricity from the Calstock,
F-59
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Nipigon and Tunis projects and previously purchased electricity from our North Bay and Kapuskasing projects in the
Natural Gas segment. Niagara Mohawk purchases electricity from the Curtis Palmer project in the Hydroelectric
segment and BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the
Hydroelectric and Solid Fuel segments. Georgia Power Company purchases electricity from the Piedmont project in the
Solid Fuel segment. Atlantic City Electric purchases electricity from the Chambers project in the Solid Fuel segment.
San Diego Gas & Electric previously purchased electricity from our Naval Station, Naval Training Center and North
Island projects in the Natural Gas segment.
23. Commitments and contingencies
Commitments
Management Service Commitments
Our Manchief project is operated by a third party under a contract that expires in April 2022. As of
December 31, 2019, our commitments under this agreement are estimated as follows:
2020
2021
2022
2023
2024
Thereafter
$
$
0.4
0.4
0.2
—
—
—
1.0
Fuel Supply and Transportation Commitments
We have entered into long-term contractual arrangements to procure fuel and transportation services for our
projects. We have also entered into long-term arrangements for firm gas sales. The commitments listed below include
only contracts for fuel contracts that are not reimbursed or passed through under the terms of the relevant PPAs and are
presented net of estimated future gas sales. As of December 31, 2019, our commitments under such outstanding
agreements are estimated as follows:
2020
2021
2022
2023
2024
Thereafter
$
$
5.0
5.0
5.2
—
—
—
15.2
F-60
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Guarantees
We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a
routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint
venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and
other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental
liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these
agreements.
Contingencies
Fire at Cadillac project
On September 22, 2019, the Cadillac project experienced a malfunction in its steam turbine that began a
cascade of events, sparking a fire. The fire was contained by the local fire department and did not result in any injuries or
known environmental violations.
Physical Damage
The biomass plant suffered significant damage to the turbine, generator and other components in that area of the
plant as a result of the fire. The boiler, cooling tower, fuel pile and fuel handling equipment were not affected. Cadillac
is expected to be offline for an extended period. Our insurance provides coverage for the repair or replacement of the
assets that experienced loss or damage. The property damage deductible under the policies insuring the Cadillac assets is
$1.0 million. Our losses have exceeded the deductible under these insurance policies.
Business Interruption
Our insurance policies also provide coverage for interruption to Cadillac’s business, including lost profits. The
policies also reimburse for other expenses and costs it has incurred relating to the damages and loss it has suffered. The
policies provide for coverage during the reconstruction period. At this time, we are unable to determine the Cadillac
plant’s expected return to service date. The business interruption deductible under the policies insuring the Cadillac
assets is 45 days of lost production, which had an approximate $1.4 million impact to cash flows from operations in
2019.
Impact
The fire resulted in a triggering event to test the Cadillac’s asset group for long-lived asset impairment. Based
on our expectation of insurance recoveries and a full repair of the plant, we did not record an impairment at Cadillac
because its estimated undiscounted future cash flows exceed the carrying value of the asset group at the date of the
incident.
Because the plant experienced significant damage and it is probable that insurance proceeds will be received in
order to repair the facility, we applied accounting for gains and losses on involuntary conversions. Based on loss
estimates and expenses incurred through third quarter of 2019, we recorded a $25 million write-down of Cadillac’s
property, plant and equipment and a $0.3 million write-down of capital spares inventory in the three months ended
September 30, 2019. This was our best estimate at the time the loss was incurred, but may be subject to future
adjustments based on actual experience of replacement cost. We also recorded a corresponding insurance receivable
($24.2 million), a component of other current assets, less the $1.0 million property damage deductible, which was
recorded as a charge to other project income, because we believe that it is probable we will receive insurance recoveries
up to our estimated plant write-down. As the plant is repaired, any costs incurred will be capitalized to property, plant
F-61
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
and equipment. As of December 31, 2019, we have recorded $5.1 million in capital additions related to repairs at
Cadillac. Insurance proceeds in excess of the net book value of the property, plant and equipment write-down, if any,
would be recorded as a gain in the period those proceeds are received.
During the three months ended December 31, 2019 and for the full year 2019, we received $11.3 million of
insurance proceeds with respect to the fire at Cadillac, which were applied against the September 30, 2019 insurance
receivable of $24.2 million. During the three months ended December 31, 2019, we recorded a $0.6 million write-down
of fuel inventory, with a corresponding increase to the insurance receivable. As of December 31, 2019, the insurance
receivable balance totals $13.5 million. Additionally, we estimate anticipated insurance recoveries related to business
interruption losses of $2.0 million for the three months ended December 31, 2019. Anticipated reimbursements for lost
profits, or business interruption losses, are accounted for as a gain contingency because lost profits are not considered an
incurred loss. Anticipated reimbursements for business interruption losses were not recorded as of December 31, 2019 as
all contingencies related to these claims had not been resolved as of period end. We expect all contingencies related to
business interruption losses to be resolved once final payment is received from the insurers, which is when we will
recognize the reimbursements in earnings. The Cadillac biomass plant is a component of our Solid Fuel segment.
General
From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that
arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies
when a loss is likely and can be reasonably estimated. There are no matters pending which are expected to have a
material adverse impact on our financial position or results of operations or have been reserved for as of December 31,
2019.
24. Leases
Real estate leases and equipment leases
We lease our office properties and equipment under operating leases expiring on various dates through 2024.
Certain operating lease agreements include provisions for scheduled rent increases over their lease terms. We recognize
the effects of these scheduled rent increases on a straight-line basis over the lease term. One of our leased office
properties is sub-leased to third parties. The sub-lease is an operating lease and the rental income received is recorded
net of rental expense in the Consolidated Statements of Operations.
On January 1, 2019, we implemented FASB ASU No. 2016-02, Leases (Topic 842). To calculate lease
liabilities on the implementation date, we utilized an incremental borrowing rate of 3.75%, which is our minimum all-in
rate on the Term Loan for the non-swapped portion of the remaining principal amount.
The following table presents the components of lease expense.
Lease cost: (1)
Operating lease cost
Short-term lease cost
Sublease income
Total lease cost
(1) Finance lease costs are immaterial to the Company.
F-62
Year Ended
December 31,
2019
$
$
1.9
0.1
(1.2)
0.8
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table presents operating lease maturities and a reconciliation of the undiscounted cash flows to operating
lease liabilities.
2020
2021
2022
2023
2024
Thereafter
Total operating lease payments
Less: present value discount
Total operating lease liabilities
2020
2021
2022
Thereafter
Total finance lease payments
Less: amount representing interest
Total finance lease liabilities
Lease
Income from Net lease
Payments subleasing payments
1.2
$
0.9
0.6
0.5
0.1
—
3.3
(1.1) $
(1.1)
(1.1)
(0.7)
—
—
(4.0) $
2.3 $
2.0
1.7
1.2
0.1
—
7.3 $
(0.5)
6.8
$
$
Lease
Payments
$
0.1
0.1
0.1
—
0.3
(0.1)
0.2
$
$
Other Information:
Cash paid for amounts included in the measurement of lease liabilities (1):
$
Operating cash flows from operating leases
(1) Cash flows from finance leases are immaterial to the Company
0.8
Lease assets obtained in exchange for new lease liabilities (non-cash):
$
Operating
Finance
Weighted average remaining lease term (in years):
Operating leases
Finance leases
Weighted average discount rate - operating leases
Weighted average discount rate - finance leases
1.6
0.2
3.5
2.4
3.92 %
4.06 %
F-63
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table presents future minimum lease payments under operating leases, which at inception had a
non-cancelable term of more than one year, as previously reported.
2019
2020
2021
2022
2023
Thereafter
Lease
Income from Net lease
Payments subleasing payments
0.6
$
0.3
0.3
0.3
0.1
—
1.6
1.7 $
1.4
1.4
1.4
0.8
—
6.7
(1.1) $
(1.1)
(1.1)
(1.1)
(0.7)
—
(5.1) $
$
We have no lease transactions with related parties. We did not utilize practical expedients for separating lease
components for all operating leases that we lease.
PPA Leases
We have entered into PPAs to sell power at predetermined rates. PPAs were assessed as to whether they contain
leases, which convey to the counterparty the right to control the use of the project’s property, plant and equipment in
return for future payments. Such arrangements are classified as either operating or finance leases. We recognize lease
income consistent with the recognition of energy sales and capacity revenue. When energy is delivered and capacity is
provided, we recognize lease income as a component of energy sales and capacity revenue. Finance income related to
leases or arrangements accounted for as finance leases is recognized in a manner that produces a constant rate of return
on the net investment in the lease. The net investment is comprised of net minimum lease payments and unearned
finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying
value of the leased property. Unearned finance income is deferred and recognized in net (loss) income over the lease
term. We elected the practical expedient that permits us to retain our existing lease assessment and classification.
As of December 31, 2019, we have twelve PPAs accounted for as operating leases and one PPA accounted as a
direct financing lease among our twenty-one projects in operation. No extension terms exist for our PPAs accounted for
as leases and the remaining lease term varies from eight months to twenty-four years. At December 31, 2019, a net
investment in lease of $0.9 million is recorded in current assets on the consolidated balance sheets for our direct
financing lease. The following table provides lease income recorded as energy and capacity sales by segment from PPAs
accounted for as operating leases:
Solid Fuel
Natural Gas
Hydroelectric
Rental Income from operating leases
Year Ended
December 31,
2019
2018
$
$
$
79.1
24.4
68.8
172.3 $
83.8
20.8
58.3
162.9
For certain of our PPAs accounted for as leases, the lessee has the option to purchase the plant. In May 2019,
we entered into an agreement to sell Manchief to PSCo following the expiration of the PPA in April 2022 for
$45.2 million subject to working capital and other customary adjustments. BC Hydro has an option to purchase
Mamquam that is exercisable in November 2021 and every five-year anniversary thereafter.
F-64
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
25. Unaudited selected quarterly financial data
Unaudited selected quarterly financial data are as follows:
Quarter Ended
2019
Project revenue
Project (loss) income
Net (loss) income
Net (loss) income attributable to Atlantic Power
Corporation
December 31, September 30, June 30,
$
66.2 $
(33.4)
(63.4)
71.1 $ 71.3 $
27.9
14.3
21.7
2.9
73.0 $ 281.6
46.8
30.6
(43.8)
2.4
March 31, Total
(65.3)
12.6
1.2
8.9
(42.6)
(Loss) income per share attributable to Atlantic Power
Corporation
Weighted average number of common shares
outstanding-basic
Diluted (loss) income per share attributable to Atlantic
Power Corporation
Weighted average number of common shares
outstanding-diluted
$
(0.60) $
0.12 $ 0.01 $
0.08 $ (0.39)
109.3
109.4
109.7
108.9
109.3
$
(0.60) $
0.10 $ 0.01 $
0.07 $ (0.39)
109.3
137.8
110.2
138.6
109.3
Project revenue
Project income
Net income (loss)
Net income (loss) attributable to Atlantic Power
Corporation
December 31,
$
Quarter Ended
2018
September 30,
June 30,
March 31,
Total
70.7 $
20.1
26.7
65.4 $ 66.2 $
26.2
(4.7)
13.6
1.0
80.0 $ 282.3
88.2
28.3
37.2
14.2
24.7
(3.2)
(0.6)
15.9
36.8
Income (loss) per share attributable to Atlantic Power
Corporation
Weighted average number of common shares
outstanding-basic
Diluted income (loss) per share attributable to Atlantic
Power Corporation
Weighted average number of common shares
outstanding-diluted
$
0.23 $
(0.03) $ (0.01) $
0.14 $ 0.33
109.6
111.1
112.4
114.8
112.0
$
0.18 $
(0.03) $ (0.01) $
0.12 $ 0.29
140.7
111.1
112.4
140.6
141.8
F-65
ATLANTIC POWER CORPORATION
SCHEDULE I—CONDENSED BALANCE SHEETS (PARENT COMPANY ONLY)
(in millions of U.S. dollars)
Assets
Current assets:
Cash and cash equivalents
Prepayments and other current assets
Total current assets
Investment in and advances to / from subsidiaries
Total assets
Liabilities
Current liabilities:
Accounts payable and accrued liabilities
Derivative liability
Convertible debentures
Total current liabilities
Convertible debentures
Other long-term liabilities
Total liabilities
Shareholders’ equity
Total liabilities and shareholders’ equity
See accompanying notes to condensed financial statements.
December 31,
2019
2018
$
$
$
$
$
$
43.2
0.8
44.0
0.3
44.3
3.6
3.2
—
6.8
81.1
1.4
89.3
42.4
3.3
45.7
51.6
97.3
3.4
1.2
18.1
22.7
80.4
1.1
104.2
(45.0)
44.3
$
(6.9)
97.3
$
F-66
SCHEDULE I—CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)
ATLANTIC POWER CORPORATION
(in millions of U.S. dollars)
Year Ended December 31,
2018
2017
2019
Administrative and other expenses:
Administrative expense
Interest expense, net
Foreign exchange loss (gain)
Other expense (income)
Loss from parent company
$
4.6 $
5.0 $
10.0
4.3
2.0
(20.9)
13.5
(9.4)
(3.1)
(6.0)
5.4
11.6
4.0
0.2
(21.2)
Equity (loss) earnings of subsidiaries, net of income tax benefit
(22.9)
43.2
(71.8)
Net (loss) income
$
(43.8) $
37.2 $
(93.0)
See accompanying notes to condensed financial statements.
F-67
SCHEDULE I—CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)
ATLANTIC POWER CORPORATION
(in millions of U.S. dollars)
Years Ended December 31,
2018
2017
2019
Cash provided by operating activities:
Net (loss) income
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash losses (earnings) from subsidiaries, net of taxes
Dividends received from subsidiaries
Unrealized foreign exchange loss (gain)
Change in fair value of convertible debenture conversion option derivative
Amortization of debt discount and deferred financing costs
Change in other operating balances
Accounts receivable
Prepayments and other assets
Accounts payable and accrued liabilities
Cash provided by operating activities
Cash used in investing activities:
Advances to / from investments in subsidiaries
Cash paid for acquisition
Deposit for acquisition
Cash used in investing activities
Cash used in financing activities:
Common share repurchases
Repayment of convertible debentures
Deferred financing costs
Proceeds from convertible debenture issuance
Repayment of intercompany note
Cash used in financing activities
Net increase (decrease) in cash and cash equivalents
Cash, restricted cash and cash equivalents at beginning of period
Cash, restricted cash and cash equivalents at end of period
Supplemental cash flow information
Interest paid
$
(43.8) $
37.2 $
(93.0)
22.9
68.5
4.3
1.8
0.7
(9.0)
2.5
1.4
49.3
(27.5)
—
—
(27.5)
(43.2)
39.0
(9.4)
(3.2)
2.6
7.4
1.0
0.8
32.2
2.4
(13.6)
(2.6)
(13.8)
(2.5)
(18.5)
—
—
—
(21.0)
0.8
42.4
43.2 $
(16.6)
(88.1)
(5.1)
92.2
(0.2)
(17.8)
0.6
41.8
42.4 $
71.8
67.9
4.0
—
—
(1.1)
1.4
0.5
51.5
(57.8)
—
—
(57.8)
(0.2)
—
—
—
(0.9)
(1.1)
(7.4)
49.2
41.8
5.2 $
4.7 $
6.2
$
$
See accompanying notes to condensed financial statements
F-68
SCHEDULE I—NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)
ATLANTIC POWER CORPORATION
(in millions of U.S. dollars)
1. Nature of business
Atlantic Power Corporation (the “Parent Company”) is a holding company that conducts substantially all of its
business through its subsidiaries. As specified in certain of its subsidiaries’ credit agreements, there are restrictions on
the Parent Company’s ability to obtain funds from certain of its subsidiaries through dividends (refer to Note 11, “Long-
term debt”, to the consolidated financial statements). As of December 31, 2019, total Atlantic Power Corporation
shareholders’ deficit was $45.0 million and approximately $5.3 million of net assets at certain subsidiaries constituted
restricted net assets as defined in Rule 4-08(e)(3) of Regulation S-X. The restricted net assets of these subsidiaries
exceeded our consolidated net assets, thus requiring this Schedule I, “Condensed Financial Information of the
Registrant.” Accordingly, the balance sheets as of December 31, 2019 and 2018, and the statements of operations and
cash flows for the years ended December 31, 2019, 2018 and 2017, have been presented on a “Parent-only” basis. In
these statements, the Parent Company’s investments in its consolidated subsidiaries are presented under the equity
method of accounting. We had no undistributed earnings from our unconsolidated investments for the years ended
December 31, 2019, 2018 and 2017, respectively.
As disclosed in Note 12 of the consolidated financial statements, APLP Holdings may be restricted from
making dividend payments or other distributions to Atlantic Power Corporation, and APLP and its subsidiaries may be
prohibited from making dividends or distributions to Atlantic Power Preferred Equity Limited shareholders in the event
of a covenant default or if APLP Holdings fails to achieve a target principal amount on the Term Loan that declines
quarterly based on a predetermined specified schedule. APLP Holdings has made principal payments to meet the
targeted debt balance requirement as of December 31, 2019 and is not prohibited from making dividends to the Parent
Company. The consolidated equity of APLP Holdings was approximately $4.9 million at December 31, 2019 and
includes the subsidiaries with restricted net assets of $5.3 million at December 31, 2019 disclosed above.
The Parent-only financial statements should be read in conjunction with our consolidated financial statements
included elsewhere herein.
2. Dividends received
The Parent Company received dividends of $68.5 million, $39.0 million and $67.9 million in 2019, 2018 and
2017, respectively, from its consolidated and unconsolidated subsidiaries.
F-69
ATLANTIC POWER CORPORATION
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017
(in millions of U.S. dollars)
Balance at Charged to
Beginning of Costs and
Expenses
Period
Charged to
Balance at
Other Accounts Deductions End of Period
Income tax valuation allowance, deducted from
deferred tax assets:
Year ended December 31, 2019
Year ended December 31, 2018
Year ended December 31, 2017
$
$
$
139.7 $
5.7 $
151.4 $ (11.7) $
(34.6) $
186.0
— $
— $
— $
— $
— $
— $
145.4
139.7
151.4
F-70
Exhibit 31.1
I, James J. Moore, certify that:
CERTIFICATION
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K of Atlantic Power Corporation;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant ’s ability to record,
process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: February 27, 2020
/s/ JAMES J. MOORE, JR.
James J. Moore, Jr.
President and Chief Executive Officer
(Principal Executive Officer)
Exhibit 31.2
I, Terrence Ronan, certify that:
CERTIFICATION
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K of Atlantic Power Corporation;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant ’s ability to record,
process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: February 27, 2020
/s/ TERRENCE RONAN
Terrence Ronan
Chief Financial Officer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
Exhibit 32.1
The undersigned officer of Atlantic Power Corporation (the “Company”) hereby certifies to his knowledge that
the Company’s Annual Report on Form 10-K for the year ended ended December 31, 2019 (the “Report”), as filed with
the Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or
15(d), as applicable, of the Securities Exchange Act of 1934, as amended, and that the information contained in the
Report fairly presents, in all material respects, the financial condition and results of operations of the Company. This
certification shall not be deemed “filed” for any purpose, nor shall it be deemed to be incorporated by reference into any
filing under the Securities Act of 1933 or the Securities Exchange Act of 1934 regardless of any general incorporation
language in such filing.
Date: February 27, 2020
/s/ JAMES J. MOORE, JR.
James J. Moore, Jr.
President and Chief Executive Officer
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
Exhibit 32.2
The undersigned officer of Atlantic Power Corporation (the “Company”) hereby certifies to his knowledge that
the Company’s Annual Report on Form 10-K for the year ended December 31, 2019 (the “Report”), as filed with the
Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or 15(d),
as applicable, of the Securities Exchange Act of 1934, as amended, and that the information contained in the Report
fairly presents, in all material respects, the financial condition and results of operations of t he Company.
Date: February 27, 2020
/s/ TERRENCE RONAN
Terrence Ronan
Chief Financial Officer
(Principal Financial Officer)
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Stock Exchange Information
TSX Ticker Symbol: ATP
NYSE Ticker Symbol: AT
Investor Information
Individual shareholders, security analysts,
portfolio managers and other institutional
investors seeking information about the company
should contact Atlantic Power Corporation
Investor Relations at 617.977.2700 or by email at
info@atlanticpower.com.
CORPORATE INFORMATION
Corporate Headquarters
3 Allied Drive, Suite 155
Dedham, MA 02026
Tel: 617.977.2400
www.atlanticpower.com
Transfer Agent
Computershare Investor Services, Inc.
100 University Avenue, 8th Floor
Toronto, ON M5J 2Y1 CANADA
Legal Counsel
Goodmans LLP
Bay Adelaide Centre
333 Bay Street, Suite 3400
Toronto, ON M5H 2S7 CANADA
Cleary Gottlieb
One Liberty Plaza
New York, NY 10006 USA
Auditor
KPMG LLP
345 Park Avenue
New York, NY 10154 USA
Annual Meeting
The Annual Meeting of Shareholders will be
held on June 17, 2020.
14SEP201110485170