14SEP201110485170
2018
Annual Report
Report to Shareholders
Dear Shareholder,
Atlantic Power had a solid year of progress in 2018. This letter will review the past and present
highlights and provide an outlook.
In my first letter to shareholders in the 2014 annual report, I quoted The Outsiders: Eight
Unconventional CEOs and Their Radically Rational Blueprint for Success1 by William N. Thorndike in
laying out our management approach. Four years later, that remains our approach. Shareholders can
judge whether we have followed these principles:
(cid:129) Capital allocation is a CEO’s most important job.
(cid:129) What counts in the long run is the increase in per share value, not overall growth or size.
(cid:129) Cash flow, not reported earnings, is what determines long-term value.
(cid:129) Decentralized organizations release entrepreneurial energy and keep both costs and ‘‘rancor’’
down.
(cid:129) Independent thinking is essential to long-term success, and interactions with outside advisers
(Wall Street, the press, etc.) can be distracting and time-consuming.
(cid:129) Sometimes the best investment opportunity is your own stock.
(cid:129) With acquisitions, patience is a virtue . . . as is occasional boldness.
PAST (2015 – 2018)
We completed a multiyear restructuring of our business and our balance sheet, as follows:
Reduced debt. Consolidated debt decreased by $1,028 million, from $1,755 million at year-end
2014 to $727 million2 at year-end 2018. Nearly all of this was attributable to debt amortization and
redemptions, asset divestitures, and discretionary debt repurchases.
Lowered cash interest payments. Primarily as a result of the significant reduction in debt, our
cash interest payments have declined by $86 million, from $127 million in 2014 (excluding $42 million
of non-recurring cash costs associated with redemptions and refinancing transactions) to $41 million in
2018. The four re-pricings of our senior secured credit facilities since April 2016 (from LIBOR plus
500 basis points to LIBOR plus 275) have been another contributing factor to the reduction in interest
payments.
Improved debt maturity profile. At year-end 2014, we had $671 million of bullet maturities in the
following five years, but as a result of debt repayment and refinancing in the past four years, today
slightly more than half of our existing debt is amortizing and repaid from operating cash flow. Earlier
this month, we redeemed the remaining Cdn$24.7 million of Series D convertible debentures that were
scheduled to mature in December 2019. As a result, our only bullet maturity in the next five years is
our senior secured term loan, which we expect will have a remaining principal of $125 million at
maturity in April 2023.
Reduced corporate overheads. During this period, we reduced corporate general and
administrative expense by more than half, from a peak level of $54 million in 2013 to an average of
approximately $23 million for the past three years. Last year we relocated our corporate headquarters
to a smaller space within the same building, reducing the annual rent by approximately $245,000 or
more than 40%.
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The combination of lower corporate overheads and lower cash interest payments resulted in
$107 million of recurring cash savings to the Company in 2018 relative to 2014.
Divested assets. We sold our five wind plants in 2015 for $350 million and used the net proceeds
primarily to redeem $311 million of 9% senior unsecured notes. This transaction was $2 million
accretive to our cash flow, and improved our leverage ratio3 and debt maturity profile.
Mothballed two plants and in the process of closing three others.
In early 2017, we mothballed
three of our Ontario plants but in November 2018 we returned Nipigon to service under a revised
contractual agreement with the plant’s customer. The other two plants may have option value should
the Ontario market improve at some point in the future. We are in the process of decommissioning our
three plants in San Diego. Although we were able to procure new Power Purchase Agreements (PPAs),
we were unable to achieve an agreement with the U.S. Navy that would allow us to economically
remain on the sites. We expect to complete the decommissioning late this year.
PRESENT (2019)
As a result of these restructuring efforts, we have an improved credit profile and strong liquidity,
including discretionary cash available for capital allocation, as follows:
Leverage ratio. Our leverage ratio at year-end 2018 was 4.5 times, which was significantly
improved from 6.9 times at year-end 2014. Although the 4.5 level was higher than the previous year
due to significantly lower Project Adjusted EBITDA4 in 2018, as expected, our planned repayment of
$86 million of consolidated debt in 2019 should result in an improvement to the leverage ratio
beginning later this year.
Improved credit ratings. Our corporate credit ratings from Moody’s and Standard & Poor’s are
Ba3 and B+, respectively. Moody’s has upgraded our credit rating twice since 2015. Standard & Poor’s
recently changed our credit outlook to positive as a result of improved credit metrics.
Strong liquidity. Our liquidity at year-end 2018 was $191 million, including $68 million of
unrestricted cash and $123 million of availability under our revolver, which has a maturity of April
2022. After setting aside cash held at the plants or needed for working capital purposes, we had
approximately $39 million of discretionary cash at the parent at year-end 2018.
Stable outlook for 2019 Project Adjusted EBITDA and operating cash flow. Our 2018 results for
Project Adjusted EBITDA4 and operating cash flow were in line with or better than our expectations,
though below 2017 levels primarily as a result of significant PPA expirations at year-end 2017 and in
early 2018. We have only one PPA expiring in 2019 (Williams Lake) and three relatively modest
contributors expiring in 2020. Our guidance for 2019 Project Adjusted EBITDA4 is in line with the
2018 result of $185 million5. We expect 2019 operating cash flow of $100 million to $115 million,
assuming no changes in working capital, which is slightly lower than 2018 operating cash flow of
$116 million on the same basis (excluding changes in working capital).
Growth. The work we have done on the cost side and in strengthening our balance sheet has
allowed us to credibly pursue external growth, with our efforts currently focused on evaluation of
potential acquisitions of out-of-favor generating assets. In 2018, we completed our first external
acquisition in more than five years, consolidating our ownership of the Koma Kulshan hydro plant,
which has a PPA that runs through March 2037. We also executed an agreement to purchase two
operating biomass plants in South Carolina with a capacity of 20 megawatts each and PPAs that run
through October 2043. This acquisition is on track to close in the second half of 2019. We expect that
the Koma Kulshan and biomass acquisitions will extend our average remaining PPA life (currently six
years) and strengthen longer-term cash flows. Our total investment for these acquisitions is nearly
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$26 million, of which we funded approximately $16 million in 2018. We will fund the remaining
$10 million this year. The potential returns on these acquisitions represent an attractive use of capital.
Earlier this year, we added two new executives to our Commercial Development team, taking it to
four. This team is responsible both for recontracting our existing plants and new business development
efforts, including asset acquisitions.
Our Operations team continues to focus on safety first. Nothing we do is more important. The
team is also continuously improving our processes and looking to gain efficiencies and reduce costs
while maintaining our assets for the long haul. They have also been invaluable in assessing external
acquisitions and in delivering solid cash flows from our assets while operating them safely.
FUTURE
Capital Allocation
We aim to allocate our capital as rationally as possible. Our focus is on strengthening the balance
sheet and on intrinsic value per share. Debt reduction is about risk reduction, not the returns available
from paying off the debt. We rank order the rest of our opportunities, both internal (such as the
repurchase of common and preferred shares) and external (such as acquisitions), and then we allocate
capital to the uses that seem to be the strongest from a discounted cash flow perspective. We don’t go
into a year with a target of allocating X dollars to one bucket and Y dollars to another. We have
quarterly debt reduction targets on our Term Loan B, which we view as a prudent use of our cash flow
to continue to reduce leverage and de-risk our financial position. Beyond that commitment, we want to
do the most intelligent things we can with our capital, focusing on growth in intrinsic value per share,
not growth in absolute size.
In 2018, we used the majority of our operating cash flow to repay $100 million of corporate and
project debt. We also invested slightly less than $17 million in the repurchase of common shares, at an
average price ($2.13) we considered attractive relative to our estimates of intrinsic value per share, and
we invested $8 million in the repurchase of preferred shares, at an implied after-tax yield of
approximately 11% on average. As I noted, we also committed $26 million to two external acquisitions
that will increase our generating capacity, extend our average remaining PPA term, and provide
longer-term cash flows.
Power Market Scenarios
Low power prices (‘‘Lower for Longer’’): As our existing PPAs expire, our revenue will be
determined by PPA recontracting options available at that time, or the market price of power if
recontracting is not feasible. If power market conditions deteriorate and returns on new investments
are unattractive, we would continue to apply our operating cash flow to repayment of debt while having
the options of cutting overheads further and using our discretionary cash to maximize the return of
capital to shareholders, most likely via share buybacks.
Status quo:
In the current power market environment (in which the market price of power
generally doesn’t sufficiently compensate dependable plants for the value they provide to the grid), we
are focused on reducing debt, controlling overhead costs and looking opportunistically for asset
acquisitions that can be had at attractive returns. This is the path we have followed the last four years
and are continuing on into 2019.
Power market recovery: At the bottom of a cycle, pessimism is conventional wisdom and more
optimistic scenarios seem unrealistic. At those times, it is often possible to acquire assets with attractive
returns, but it is harder to sell. Prices do tend to fluctuate, though, and the relative values of assets
may change. Although we have low power prices today, we also have low interest rates, which have
driven up asset valuations.
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More broadly, wind and solar energy are deemed to be low-cost resources today, but the economic
impact of intermittency is often ignored in those calculations. When high levels of intermittent power
are integrated onto a grid, the grid incurs higher costs to support the intermittent power. Also, as the
level of intermittent resources on the grid increases, the value of the incremental additions decreases,
because these resources may then produce more energy than needed at certain times—and insufficient
amounts when there is no wind, for example. It does seem that these issues are beginning to receive
more attention, as are the environmental impacts of wind and solar (land use and high level of material
use for non-dense energy) and the efficacy of using material-dense intermittent sources of power to
replace existing plants to reduce CO2 emissions.
If the true costs of intermittent power and battery storage are recognized, then gas plant values
may start to reflect their better balance of economic and environmental attributes. We don’t know if
power prices will return to the highs of the past four or five years (far from the peak) or, if they do,
what will be the catalysts for the increases. We do know that commodity prices tend to fluctuate in
surprising ways and group think often turns out to be strongest just before it is proven wrong. As I’ve
noted before, in 2001 I handed out copies of a book on peak oil to the board of directors of a wind
energy company. Anyone at all familiar with subsequent events will realize that I was aligned with
conventional wisdom and I was spectacularly wrong in believing that we were reaching peak levels of
oil production.
If power prices rise because of a more favorable supply-demand balance or because of a need for
more dependable generation, that would benefit most merchant power plants (or ones with expiring
PPAs), in terms of their recontracting opportunities and asset values. Our equity valuation ought to
increase significantly in this scenario.
Competitive Position
Balance sheet, cash flow, and PPA cover. Our PPAs generate significant cash flow that we are
applying to further reduce debt, even in an environment where the market price of power stays low or
goes lower. In addition to this cash flow, we have ample liquidity, so if returns on asset acquisitions
become compelling we’d have discretionary capital available to take advantage of higher-return
opportunities. This also means that we are well positioned for deflation. On the flip side, if the
inflation hedging attributes of power plants become more recognized, then we have plant capacity
available to sell into the market. The average remaining PPA term of six years puts us in a balanced
positon. We are able to pay down debt even if merchant prices remain low, and at the end of the
average PPA life we will have lower debt levels and capacity available to sell into markets if power
prices rise.
Operational expertise. Our operations team is valuable in both running our existing plants and in
evaluating potential acquisitions and ensuring that we run acquired plants more efficiently. This core
competency has, for example, allowed us to take a cigar butt approach to investing in biomass plants.
We turned around our Piedmont biomass plant and are now achieving significantly higher normalized
EBITDA than pre-turnaround. Our operational expertise has also helped us to find value in two
biomass plants in South Carolina that we are in the process of acquiring. We are looking at other asset
acquisitions as well.
We are technology agnostic. We have invested in and owned coal, natural gas, biomass, hydro,
wind, solar, and other types of power plants. We are driven by returns.
Management experience. Some members of the management team have been in the energy
business since 1983, and several have been focused in the power sector since 1986. We have developed
a track record of countercyclical, patient, and disciplined investing. We recognize the sector is capital-
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intensive, commodity-priced and cyclical, so our focus is on intrinsic value per share, not on absolute
growth.
Insider ownership. Our view is the best way to align management’s interests with those of
shareholders is to be a shareholder. The officers and directors of Atlantic Power have made significant
personal investments in the Company’s shares, totaling $5.0 million. These investments were made with
their own funds (i.e., they do not include shares acquired through equity compensation plans or
received by directors as part of their compensation).
Approach to capital allocation. Our mode of operation is to come in each day and try to be as
rational as possible. We are value investors. We constantly look at buying and selling assets. We look at
joint ventures and spin-offs. We have been involved in the sales and spin-offs of IPP companies several
times in our careers. We want to be aggressive buyers when prices are attractive, cautious investors or
sellers when they are high, and patient in between. We want to allocate capital as rationally as possible,
by estimating the discounted value of cash flows from our existing plants and potential acquisitions and
doing our best to estimate the intrinsic value of our shares under different scenarios. We want the
mindset of a family business with our name on the door, doing our best to protect, preserve and grow
the business.
We look forward to meeting those shareholders who can attend our Annual and Special Meeting
this year, which will be held at the King Edward Hotel in Toronto on June 19, beginning at 10:00 a.m.
Our Chairman, Irving Gerstein, has decided to retire from the Board at the conclusion of this
year’s Meeting. Four and a half years ago I met him as a stranger in a conference room in Boston.
Today he is my friend and mentor. Thank you for your service, Irving.
21APR201521422407
James J. Moore, Jr.
President and Chief Executive Officer
April 30, 2019
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Safety
2018 Business and Financial Highlights
(cid:129) Environmental, health, and safety performance. Safety remains our highest priority. We believe
that our commitment to a culture of excellence and continual improvement is the linchpin of our
safety efforts. We had one lost-time incident in 2018, the same number as in 2017, and our
lost-time incident rate was 0.41, significantly better than the industry average. In 2018, eight of
the 14 plants that we operate completed at least five years of operation without a lost-time
incident. We had four recordable injuries in 2018 as compared to three in 2017, but fortunately
all were relatively minor. We received no environmental notices of violation in 2018, nor did we
receive any from either the Federal Energy Regulatory Commission or the North American
Electric Reliability Council. Our Kenilworth plant received a Governor’s Safety Award for the
prevention of occupational injuries from the New Jersey Division of Public Safety.
Culture
(cid:129) 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.
Servant leaders seek to be good listeners, to be humble, and to lead by example. We place very
high importance on this effort, as we believe a strong culture is the bedrock of building
long-term sustainable value. In 2018, we continued to roll out training to the plant level.
Operational
(cid:129) Improved plant availability. Our plants had an availability factor of 96.5%, a strong performance
that was significantly improved from the 90.3% recorded in 2017. During 2018, we had fewer
planned and unplanned outages than in 2017, which was the primary driver of improved
availability.
(cid:129) Continued focus on operating costs. As part of our ongoing effort to control operating costs while
improving the operating performance of our plants, we rolled out Predictive Analytic
maintenance software (PRiSM) at three additional plants this year, and now have PRiSM
installed at six of our plants. During 2018, this system allowed us to avoid potential maintenance
issues that could have hurt reliability or increased costs, by providing us an early alert on ten
different occasions. We completed an external benchmarking of the thermal plants that we
operate and have begun implementing some of the recommendations, with a focus on
maintenance outage frequency and standardization. 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.
(cid:129) Asset management. We recommissioned our Tunis plant under a new Power Purchase Agreement
(PPA), which involved seven major upgrades to the plant, which had not been in operation since
2014. We also returned our Nipigon plant to operation under a revised PPA and began the
planning for several upgrades of systems and components at this plant that will occur in 2019.
We made modifications to the fuel-handling system at our Piedmont plant to allow more urban
wood waste, reducing our fuel costs. We made significant progress in preparing to decommission
our three plants in San Diego, and realized $1.7 million of salvage proceeds that will partially
offset our expected cash outlay.
Commercial
(cid:129) PPA extension for our Kenilworth plant. During 2018, we executed two successive one-year
extensions of our PPA with Merck, the customer at our Kenilworth plant, to September 2020.
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We continue to engage with Merck on short-term and long-term options for their power supply
needs.
(cid:129) Acquisition of remaining interest in Koma Kulshan plant. In July 2018, we closed the acquisition
of our partners’ interests in the 13 megawatt Koma Kulshan hydro facility. This was our first
external acquisition following a three-year business restructuring process. We also bought out the
operation and maintenance and management contracts from our partner. As a result, we
increased our ownership from 50% to 100% and gained operating control of a hydro project
with a PPA that runs to 2037 and, we believe, has economic life beyond the PPA term.
(cid:129) Agreement to acquire two contracted biomass plants. In September 2018, we agreed to acquire two
biomass plants in South Carolina from EDF Renewables. The plants, which each have a capacity
of 20 megawatts, have been in operation since 2013 and are under PPAs that run through late
2043. Closing of the acquisition is expected in the third or fourth quarter of 2019. The long
remaining term of the PPAs provides a stable base of cash flows, and we see upside potential
from executing on optimization initiatives to deliver targeted operational and financial results.
Financial
(cid:129) Results in line with or better than guidance. Cash provided by operating activities (a GAAP
measure) was $137.5 million. Excluding a net working capital benefit, cash flow was
approximately $116 million, which exceeded our estimated range of $95 million to $110 million.
Project Adjusted EBITDA was $185.1 million, which was at the high end of our guidance range
of $170 million to $185 million. (Project Adjusted EBITDA is a non-GAAP measure; see
page 59 of the Company’s 2018 Annual Report on Form 10-K for a reconciliation to its nearest
GAAP measure.)
(cid:129) Continued to significantly reduce debt. We repaid $100.3 million of term loan and project debt in
2018 from operating cash flow, representing an approximate 12% reduction in debt from the
year-end 2017 level. Since year-end 2013, we have reduced consolidated debt by approximately
$1.1 billion or approximately 60%.
(cid:129) Reduced the cost of our credit facilities. In April 2018 and again in October 2018, we successfully
re-priced the spread on our term loan and revolver by a total of 75 basis points, to LIBOR plus
275 basis points. The cumulative expected interest savings resulting from the 2018 re-pricings
through the maturity dates of the respective facilities are approximately $11.8 million. Since
issuing these credit facilities in 2016, we have re-priced the spread a total of four times, with a
cumulative reduction in the spread of 225 basis points.
(cid:129) Reduced interest payments. We reduced our cash interest payments by $31 million from the 2017
level, or by $21 million excluding the termination of an interest rate swap in 2017. We achieved
this as a result of continued debt repayment, including the redemption of our Piedmont project
debt in full, the reductions in the spread on our credit facilities, and the timing of interest
payments on a new convertible debenture issue. We also continue to manage our exposure to
increases in market interest rates. At year-end 2018, approximately 96% of our debt carried
either a fixed rate or a variable rate that has been fixed through interest rate swaps.
(cid:129) Improved our debt maturity profile. In January 2018, we completed our first capital markets
offering in more than five years, issuing a new convertible debenture with a 6.0% interest rate
and a 2025 maturity. We used the proceeds to redeem the substantial majority of our convertible
debentures scheduled to mature in 2019.
(cid:129) Maintained strong liquidity. Our liquidity at year-end 2018 was $191 million, including
approximately $39 million of discretionary cash. Even as we completed an acquisition and
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repurchased a significant amount of common and preferred shares during 2018, our liquidity was
reduced only $7 million from the year-end 2017 level.
(cid:129) Maintained stable overhead costs. Corporate general and administrative (G&A) costs of
$23.9 million were approximately $2 million higher than in 2017, although cash costs were
approximately 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. In 2018, we relocated our corporate
headquarters to smaller space at the same location, which reduced our annual lease expense by
approximately $245,000 or more than 40%.
Capital Allocation
(cid:129) Repurchases of common and preferred shares. During 2018, we repurchased and canceled
approximately 7.8 million common shares at a total cost of $16.6 million, or an average price of
$2.13 per share. These repurchases reduced our outstanding common shares by approximately
6.7%. 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 645,000 preferred shares at a total cost of Cdn$10.3 million or
$8.0 million on a US$ equivalent basis, representing an approximate 36% discount to par value
and an attractive after-tax yield of approximately 11%. We consider the returns on these
repurchases of our common and preferred shares to be more compelling than the returns
generally available in the current power market environment.
(cid:129) Reoriented toward growth with two acquisitions. During 2018, we completed one acquisition and
reached agreement on another. Both are of operating plants with long-dated PPAs that will add
to our capacity and we expect will contribute to Project Adjusted EBITDA, extend our average
remaining contract life and improve longer-term cash flows. These two acquisitions totaled
$25.8 million, including the remaining $10.4 million for the South Carolina biomass plants that
will be paid upon closing in 2019.
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Notes
1
2
3
4
5
Thorndike, William N., Jr. The Outsiders: Eight Unconventional CEOs and Their Radically Rational
Blueprint for Success. Boston: Harvard Business Review Press, 2012.
Year-end 2018 consolidated debt of approximately $727 million excludes unamortized discounts
and deferred financing costs.
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.
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 Annex 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.
The Company’s guidance for 2019 Project Adjusted EBITDA is $175 million to $190 million, in
line with the 2018 result of $185 million. 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.
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Cautionary Note Regarding Forward-Looking Statements
To the extent any statements made in this letter 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 forward-looking information under Canadian securities law (collectively, ‘‘forward-looking
statements’’).
Certain statements in this letter may constitute ‘‘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 ‘‘may,’’ ‘‘will,’’ ‘‘should,’’ ‘‘project,’’ ‘‘continue,’’
‘‘believe,’’ ‘‘intend,’’ ‘‘anticipate,’’ ‘‘expect’’ or similar expressions that are predictions of or indicate
future events or trends and which do not relate solely to present or historical matters. Examples of
such statements in this letter include, but are not limited, to statements with respect to the following:
(cid:129) the Company’s estimate of the remaining principal on its term loan at maturity in April 2023;
(cid:129) the Company’s assessment of its credit profile and liquidity;
(cid:129) the Company’s view that its two mothballed Ontario plants may have option value should the
Ontario market improve at some point in the future;
(cid:129) the Company’s expectation that it will complete the decommissioning of the three plants in San
Diego late this year;
(cid:129) the Company’s expectation that its leverage ratio will decrease to approximately 4 times by
year-end 2019;
(cid:129) the Company’s plans to repay $86 million of consolidated debt in 2019;
(cid:129) the Company’s expectations with respect to 2019 Project Adjusted EBITDA and operating cash
flow;
(cid:129) the Company’s view that the Koma Kulshan hydro facility has economic life beyond the PPA
term;
(cid:129) the Company’s views with respect to the pending acquisition of the South Carolina biomass
plants, the stability of their cash flows and the upside potential from executing on optimization
initiatives;
(cid:129) the Company’s expectation that the Koma Kulshan and biomass acquisitions will extend average
remaining contract life and strengthen longer-term cash flows, and that the potential returns
represent an attractive use of capital;
(cid:129) the Company’s view that as its PPAs expire revenue will be determined by recontracting options
available at that time or the market price of power if recontracting is not feasible;
(cid:129) the Company’s view that in a power price environment that reflects a more favorable supply-
demand balance or a need for more dependable generation, its equity valuation would increase
significantly;
(cid:129) the Company’s view that it is well positioned for deflation;
(cid:129) the Company’s view that it made repurchases of common shares in 2018 because it considered
the trading price of those shares to be at a discount to its estimates of intrinsic value per share;
x
(cid:129) the Company’s estimate that the repurchase of preferred shares in 2018 yielded an after-tax
return of approximately 11%; and
(cid:129) the Company’s estimate of interest cost savings resulting from the 2018 re-pricings of the spread
on its credit facilities.
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. 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 letter and, except as expressly required by applicable law, the Company assumes no
obligation to update or revise them to reflect new events or circumstances.
Certain information in this letter may be considered as ‘‘financial outlook’’ within the meaning of
applicable securities legislation. The purpose of this financial outlook is to provide readers with
disclosure regarding the Company’s reasonable expectations as to the anticipated results of its proposed
business activities for the periods indicated. Readers are cautioned that the financial outlook may not
be appropriate for other purposes.
xi
ANNEX A
ATLANTIC POWER CORPORATION
RECONCILIATION OF NET INCOME (LOSS) (A GAAP MEASURE) TO PROJECT ADJUSTED
EBITDA FOR THE YEARS ENDED DECEMBER 31, 2018 AND DECEMBER 31, 2017
(UNAUDITED)
(in millions of U.S. dollars, except as otherwise stated)
Net income (loss) attributable to Atlantic Power Corporation . . . . . . . . . . . . . . . . . .
Net income attributable to preferred share dividends of a subsidiary company . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax (benefit) expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign exchange (gain) loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018
2017
$ 36.8
0.4
$ 37.2
0.2
37.4
23.9
52.7
(22.8)
(3.0)
($ 98.6)
5.6
($ 93.0)
(58.1)
(151.1)
23.6
64.2
16.3
(0.4)
Project income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 88.2
($ 47.4)
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in the fair value of derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 99.7
3.4
(2.2)
$133.2
19.2
(2.1)
— 187.1
(1.2)
(4.0)
Project Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$185.1
$288.8
xii
26APR201113105954
FOLLOWING IS THE COMPANY’S ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018
(This page has been left blank intentionally.)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2018
OR
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
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 No
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 No
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 No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of
Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not
be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
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
Emerging growth company
Accelerated Filer
Non-Accelerated Filer
Smaller reporting company
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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No
As of June 30, 2018, the aggregate market value of the voting and nonvoting common equity held by non-affiliates of the registrant was $239.3 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 27, 2019, 109,686,626 of the registrant’s Common Shares were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for its 2019 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.
4
18
38
39
39
39
40
42
44
75
79
79
79
80
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 investment of our discretionary cash in
a combination of organic and external growth projects, acquisitions, and repurchases of debt and equity
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; 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 power purchase agreements and our ability to renew or enter into new
PPAs on favorable terms or at all;
our ability to service our debt obligations or generate sufficient cash flow to pay preferred dividends;
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;
our indebtedness and financing arrangements and the terms, covenants and restrictions included in our
Credit Facilities;
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;
unstable capital and credit markets;
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;
the effects of weather, which affects demand for electricity and fuel as well as operating conditions;
• U.S., Canadian and/or global economic conditions and uncertainty;
•
•
•
•
•
•
•
•
•
risks beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of
war, natural disasters or other catastrophic events;
the adequacy of our insurance coverage;
the impact of significant energy, environmental and other regulations on our projects;
the impact of impairment of goodwill, long-lived assets or equity method investments;
the impact of failure to fully comply with Section 404 of the Sarbanes-Oxley Act of 2002;
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;
risks inherent in the use of derivative instruments;
2
•
•
•
•
labor disruptions;
the impact of hostile cyber intrusions;
the impact of our failure to comply with the U.S. Foreign Corrupt Practices Act and/or Canadian
Corruption of Foreign Public Officials Act; and
our ability to retain, motivate and recruit executives and other key employees.
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 is an independent power producer that owns power generation assets in nine 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 PPAs,
which seek to minimize exposure to changes in commodity prices. As of December 31, 2018, our portfolio consisted of
seventeen projects operating or under contract with an aggregate electric generating capacity of approximately 1,598
megawatts (“MW”) on a gross ownership basis and approximately 1,252 MW on a net ownership basis. Fourteen of the
projects are majority-owned by the Company. Two of our Ontario projects totaling 80 MW on a gross and net ownership
basis have not operated since the expiration of their contracts on December 31, 2017. In early February 2018, our three
plants in San Diego, totaling 112 MW on a gross and net ownership basis, ceased operations and will be
decommissioned, as discussed in Our Organization and Segments.
The following charts show, based on generation capacity in MW, the diversification of our portfolio by segment
and fuel type for our projects currently in operation:
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 June 30, 2019 to March 31, 2037,
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 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.
HISTORY OF OUR COMPANY
Atlantic Power Corporation is a corporation continued under the laws of British Columbia, Canada, which was
incorporated in 2004. We used the proceeds from our initial public offering on the Toronto Stock Exchange (“TSX”) in
November 2004 to acquire a 58% interest in Atlantic Power Holdings, LLC (which we refer to herein as “Atlantic
Holdings”) from two private equity funds managed by ArcLight Capital Partners, LLC (“ArcLight”) and from Caithness
Energy, LLC (“Caithness”). Until December 31, 2009, we were externally managed under an agreement with Atlantic
Power Management, LLC, an affiliate of ArcLight, when we agreed to pay ArcLight an aggregate of $15 million to
terminate its management agreement with us. In connection with the termination of the management agreement, we
4
hired all of the then-current employees of Atlantic Power Management and entered into employment agreements with its
three officers.
At the time of our initial public offering, our publicly traded security was an Income Participating Security
(“IPS”), which was comprised of one common share and a subordinated note. In November 2009, our shareholders
approved a conversion from the IPS structure to a traditional common share structure in which each IPS was exchanged
for one new common share and each old common share that did not form a part of an IPS was exchanged for
approximately 0.44 of a new common share. Our common shares trade on the TSX under the symbol “ATP”. On
July 23, 2010, we also began trading on the New York Stock Exchange (“NYSE”) under the symbol “AT”.
On November 5, 2011, we directly and indirectly acquired all of the issued and outstanding limited partnership
units of Capital Power Income L.P., which was renamed Atlantic Power Limited Partnership on February 1, 2012 (the
“Partnership”). The Partnership’s portfolio consisted of 19 wholly-owned power generation assets located in both
Canada and the United States, a 50.15% interest in a power generation asset in the state of Washington, and a 14.3%
common ownership interest in Primary Energy Recycling Holdings, LLC which was later sold in 2012. At the
acquisition date, the transaction increased the net generating capacity of our projects by 143% from 871 MW to
approximately 2,116 MW.
On June 26, 2015, we sold our 100% ownership interest in Meadow Creek Project Company, LLC (“Meadow
Creek”), 99% ownership in Canadian Hills Wind, LLC (“Canadian Hills”), 50% ownership interest in Rockland Wind
Farm, LLC (“Rockland”), 27.6% ownership interest in Idaho Wind Partners 1, LLC (“Idaho Wind”) and 12.5%
ownership interest in Goshen Phase II, LLC (“Goshen”) (collectively, the “Wind Projects”), totaling 521 MW net
ownership to TerraForm AP Acquisition Holdings, LLC (“TerraForm”), an affiliate of SunEdison, Inc.
OUR BUSINESS STRATEGY
General
Our business strategy is to increase the intrinsic value of the Company on a per-share basis. An important
element of that strategy is strengthening our balance sheet and financial flexibility by continuing to reduce our debt and
interest costs significantly. We also continue to evaluate our overhead and operating costs for further cost savings
opportunities. We use our depth of operational and commercial experience to enhance the operating, contractual and
financial performance of our current portfolio of projects, and to extend or renew expiring PPAs for our projects when it
is economically feasible to do so. In allocating discretionary capital we are guided by the price-to-value relationship and
the impact on intrinsic value per share. We rank the various potential uses – organic growth, external investments and
acquisitions, and repurchases of our debt and equity securities – on that basis. With respect to organic growth, we have
made optimization investments (to improve efficiency or reliability or increase capacity) in our existing projects that
have produced cash returns higher than those currently available externally. We may undertake additional investments to
repower certain facilities in conjunction with extensions of existing PPAs, if the returns are attractive. We believe that
we have a highly disciplined and opportunistic approach to external growth, with a focus on out-of-favor assets. We will
use discretionary cash for repurchases of our debt and equity securities only when the price-to-value level is compelling.
Extending PPAs following their expiration
PPAs in our portfolio have expiration dates ranging from June 30, 2019 to March 31, 2037. 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
5
and could be exposed to selling power at spot market prices. It is possible that subsequent PPAs or the spot markets 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—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.”
Organic growth
We plan to continue to enhance the operational and financial performance of our projects by improving their
operating efficiencies, output, reliability and operation and maintenance costs through investments to upgrade or
enhance existing equipment or plant configurations. We also seek to optimize commercial arrangements such as PPAs,
fuel supply and transportation contracts, steam sales agreements, operations and maintenance agreements and hedging
arrangements. To the extent we achieve PPA extensions or new contracts on economically feasible terms, and we have
sufficient cash flow or are able to obtain financing, we may expand or repower existing projects, or develop new long-
term contracted plants with industrial customers.
External Growth & Acquisitions
We pursue external growth opportunities consistent with our strategy to maximize the intrinsic value of the
Company on a per-share basis. Our acquisition strategy is focused on power generation assets in operation in the United
States and Canada, targeting out-of-favor assets with a compelling price-to-value relationship. We may also pursue the
greenfield development of new power generation projects when a favorable risk/reward balance exists.
OUR COMPETITIVE STRENGTHS
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 1,598 MW, and our net ownership interest in these projects is
approximately 1,252 MW at December 31, 2018. These projects are diversified by fuel type, electricity and
steam customers, technologies, project operators and geography. The majority are located in the U.S.
Eastern, Mid-Atlantic and Midwest regions, and the province of British Columbia.
• 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 fourteen of our
seventeen operating power generation projects, which represent approximately 62% of our portfolio’s total
net generating capacity. The remaining three generation projects are operated by third parties, which are
recognized leaders in the independent power business.
6
ASSET MANAGEMENT
Our asset management strategy is to manage our physical assets and commercial relationships to increase
shareholder value. We proactively seek scale opportunities and to establish best practices that result in EBITDA and
cash flow growth across all of our seventeen 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 three 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
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.
OUR ORGANIZATION AND SEGMENTS
The following tables outline by segment our portfolio of power generating assets in operation as of December
31, 2018, 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: East U.S., West U.S., Canada and Un-Allocated Corporate. The segment
classified as 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.
The sections below provide descriptions of our projects as they are aligned in our segment reporting structure
for financial reporting purposes.
East U.S. Segment
Our East U.S. segment accounted for 56.2%, 33.7% and 35.7% of consolidated revenue in 2018, 2017 and
2016, respectively, and total net generation capacity of 531 MW at December 31, 2018. Niagara Mohawk Power
Corporation accounted for 15.1% of total consolidated revenues and 26.8% of total revenues from the East U.S. segment
for the year ended December 31, 2018.
The table below provides the revenue and project income for the East U.S. segment. See Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations—Project Income (Loss) by Segment for
additional details on our project income (loss).
2018
2017
2016
East U.S. Segment
Revenue
($ in millions)
Project income (loss)
($ in millions)
$
158.7 $
152.5
134.5
70.9
(17.0)
31.2
7
Set forth below is a list of our East U.S. projects in operation at December 31, 2018:
Location Fuel
MW Interest
MW Primary Electric Purchasers
Gross Economic Net
Project
Orlando(1)
Piedmont
Morris (2)
Florida
Georgia
Illinois
Natural Gas
Biomass
Natural Gas
129
55
177
50.00 %
100.00 %
100.00 %
Cadillac
Chambers(1)
Michigan
New Jersey
Biomass
Coal
40
262
100.00 %
40.00 %
Kenilworth
Curtis Palmer
New Jersey
New York
Natural Gas
Hydro
29
60
100.00 %
100.00 %
65
55
100
77
40
89
16
29
60
Progress Energy Florida
Georgia Power
Merchant
Equistar Chemicals, LP (3)
Consumers Energy
Atlantic City Electric (5)
Chemours Co.
Merck & Co., Inc.
Niagara Mohawk Power Corporation
Power
Contract
Expiry
December 2023
September 2032
N/A
December 2034
June 2028
March 2024
March 2024
September 2020 (6)
December 2027 (7)
Customer
Credit
Rating
(S&P)
A-
A-
NR
BBB+ (4)
BBB+
BBB+
BB
AA
A-
(1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated
affiliates.
(2) Equistar has an option to purchase Morris that is exercisable in December 2020 and in December 2027.
(3) Equistar has the right under the PPA to take up to 77 MW, but on average has taken approximately 50 MW.
(4) Represents the credit rating of LyondellBasell, the parent company of Equistar Chemicals, as Equistar is not rated.
(5) 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.
(6) Merck has a one-year extension option that, if exercised, would extend the PPA expiration date to September 30,
2021.
(7) 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, 2018, the facility has generated 7,651 GWh under its PPA. Based on
cumulative generation to date, we expect the PPA to expire prior to December 2027.
West U.S. Segment
Our West U.S. segment accounted for 15.5%, 25.4% and 24.9% of consolidated revenue in 2018, 2017 and
2016, respectively, and total net generation capacity of 487 MW at December 31, 2018. Power Service Company of
Colorado accounted for 7.0% of total consolidated revenues and 45.7% of total revenues from the West U.S. segment for
the year ended December 31, 2018.
The table below provides the revenue and project income (loss) for the West U.S. segment. See Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Project Income (Loss) by
Segment for additional details on our project income (loss).
West U.S. Segment
2018
2017
2016
Revenue
($ in millions)
$
43.8 $
Project income (loss)
($ in millions)
0.9
(72.0)
11.8
108.9
101.3
8
Set forth below is a list of our West U.S. projects in operation at December 31, 2018:
Location Fuel
MW Interest
MW Primary Electric Purchasers
Gross Economic Net
Power
Contract
Expiry
Project
Oxnard
Manchief (2)
Frederickson(3)
California
Colorado
Washington
Natural Gas
Natural Gas
Natural Gas
49
300
250
100.00 %
100.00 %
50.15 %
49
300
50
45
30
13
Southern California Edison
Public Service Company of Colorado
Benton Co. PUD
Grays Harbor PUD
Franklin Co. PUD
Puget Sound Energy
May 2020 (1)
April 2022
August 2022
August 2022
August 2022
March 2037
Koma Kulshan
Washington
Hydro
13
100.00 %
(1) Oxnard’s steam sales agreement expires in February 2020.
Customer
Credit
Rating
(S&P)
BBB+
A-
AA-
A+
A+
BBB
(2) Public Service Company of Colorado has an option to purchase Manchief that is exercisable in May 2020 and in
May 2021.
(3) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated
affiliates.
In August 2018, we terminated discussions with the Navy regarding site control for Naval Station, Naval
Training Center (‘NTC”) and North Island. We are proceeding with plans to decommission all three sites in 2019, which
is a requirement of our land use agreements with the Navy. Pending a determination with the Navy regarding the scope
of work and receipt of bids from contractors, the final cost of the decommissioning may exceed our asset retirement
obligation of $5.0 million.
Canada Segment
Our Canada segment accounted for 27.9%, 39.1% and 40.7% of consolidated revenue in 2018, 2017 and 2016,
respectively, and total net generation capacity for operational projects of 237 MW at December 31, 2018. British
Columbia Hydro and Power Authority (“BC Hydro”) accounted for 12.5% of total consolidated revenues and 44.0% of
total revenues from the Canada segment for the year ended December 31, 2018.
The table below provides the revenue and project income (loss) for the Canada segment. See Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Project Income (Loss) by
Segment for additional details on our project income (loss).
Canada Segment
2018
2017
2016
Revenue
($ in millions)
$
78.9 $
Project income (loss)
($ in millions)
168.6
162.5
17.0
38.8
(35.7)
Set forth below is a list of our Canada projects in operation or under contract at December 31, 2018:
Project
Mamquam (1)
Moresby
Lake
Williams
Lake
Calstock
Nipigon
Tunis
Location
British Columbia
Fuel
Hydro
Gross Economic
MW Interest
50
100.00 %
Net
MW
50
British Columbia
Hydro
6
100.00 %
6
British Columbia
Ontario
Ontario
Ontario
Biomass
Biomass
Natural Gas
Natural Gas
66
35
40
37
100.00 %
100.00 %
100.00 %
100.00 %
66
35
40
37
Primary Electric Purchasers
BC Hydro
BC Hydro
BC Hydro
Ontario Electricity Financial Corporation
Independent Electricity System Operator
Independent Electricity System Operator
Power
Contract
Expiry
September 2027
Customer
Credit
Rating
(S&P)
AAA
August 2022
AAA
June 2019
June 2020
December 2022
October 2033
AAA
AA
AA
AA
(1) BC Hydro has an option to purchase Mamquam that is exercisable in November 2021 and every five-year
anniversary thereafter.
9
General
Historically, the North American electricity industry was characterized by vertically integrated monopolies.
During the late 1980s, several jurisdictions began a process of restructuring by moving away from vertically integrated
monopolies toward more competitive market models. Rapid growth in electricity demand, environmental concerns,
increasing electricity rates, technological advances and other concerns prompted government policies to encourage the
supply of electricity from independent power producers. More recently, the North American electricity industry has
become more diversified but faces the challenges of declining reserve margins and energy prices and uncertainty
resulting from environmental regulations.
According to the North American Electric Reliability Corporation’s (“NERC”) 2018 Long-Term Reliability
Assessment (“LTRA”), published in December 2018, the 10-year forecast compound annual growth rate of the peak
summer and winter electricity demand has leveled off, but remains historically low. The LTRA reference case shows a
compound annual growth rate of 0.6% for both the summer and winter seasons. This growth rate is consistent with the
2017 LTRA. However, the projected growth rate was 1.5% just a decade earlier. These growth rates are expected to
continue to decline due to the increase in energy efficiency and conservation programs as well as the continued growth
of distributed solar and other storage sources.
Despite recent and projected low demand growth, regions where we operate are projected to have reserve
margin shortfalls or reserve margins that are lower than NERC’s reference reserve margin level. According to the
LTRA, the North American electric power system is undergoing a significant transformation with ongoing retirements of
fossil-fired and nuclear capacity as well as growth in natural gas, wind, and solar resources. This shift is caused by
several drivers, such as existing and proposed federal, state, and provincial environmental regulations as well as low
natural gas prices, in addition to the ongoing integration of both distributed and utility-scale renewable resources.
Natural gas-fired generation surpassed coal as the predominant fuel source for electric generation and is the leading fuel
type for capacity additions.
Non-utility power generation
The electric power industry is one of the largest industries in the United States, generating annualized retail
electricity sales of approximately $370 billion through November 2018, based on information published by the Energy
Information Administration, an increase from $359 billion during the same period of 2017. 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
2018. 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.
Competition
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 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.
10
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 Regulation 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
Nine 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 eight 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. Eight of our projects are also
subject to reliability standards developed and enforced by 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.
11
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. Pursuant to the Clean Energy Act, BC Hydro is required
to submit a report to the BCUC every five years outlining how it intends to meet these objectives and provide updates on
its progress to date.
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;
12
• Consumer advocacy; and
• 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 fines. 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.
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. In the fall
of 2015, the Province sold off 15% of Hydro One in an IPO with an additional 38% sold through December 31, 2017. In
January of 2018, the Province sold a further 2.4% of the company’s outstanding common shares to 129 First Nations of
Ontario. The Province now owns approximately 48.9% of the company’s common shares, including the 1.5% owned by
Ontario Power Generation, a company wholly-owned by the Province.
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.
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
13
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.”
In January 2019, the provincial government initiated a consultation process in order to consider the merits of
shifting to a single annual natural gas rate which will include both delivery-related and commodity-related rates.
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 29, 2018, the governor of New Jersey
signed an executive order directing the state’s Department of Environmental Protection and the Board of Public Utilities
to take all necessary regulatory and administrative measures to ensure New Jersey’s timely return to full participation in
RGGI. We have project interests in two RGGI states, New York and New Jersey. New York provides cost mitigation for
independent power projects with certain types of power contracts. New Jersey, pending final legislation, is also expected
to provide similar cost mitigation. 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 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
14
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 has not been implemented, and more recently the Trump Administration has pursued
efforts to revoke it. In October 2017, the EPA issued a proposed rule to repeal the CPP for existing power plants; in
August 2018, the EPA issued its proposed Affordable Clean Energy Rule, which would establish emissions guidelines
for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants; and 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 the current legal challenges to the CPP or any legal challenges to future administrative actions.
Canada - Federal
In Canada, the federal government has implemented greenhouse gas reporting regulations and are 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.
Alberta, British Columbia and Québec already have compliant carbon pricing systems in place and are not expected
to be subject to 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. The federal backstop regime imposes a minimum Cdn$20/tonne of CO2e
(“tCO2e”) carbon price beginning on January 1, 2019, increasing by Cdn$10 increments each following year to 2022.
The validity of the federal backstop regime is being challenged on constitutional grounds by Ontario and
Saskatchewan, and Ontario also is working on its own output-based performance standards for large emitters (which appear
likely to be similar to and potentially compatible with the federal OBPS). The details of both the federal OBPS and the
Ontario output-based performance standards had not been settled at the beginning of 2019, notwithstanding that they are to be
effective from and after January 1, 2019. The federal government issued a “Notice of intent to make regulations under part 2
of the Greenhouse Gas Pollution Pricing Act” on December 20, 2018, and subsequently, on January 9, 2019, issued “The
Complete Text for Proposal for the Output-Based Pricing System Regulations” for public comment (which are due by
February 15, 2019). The implications of the federal OBPS for our operations in 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
15
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
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. 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, from January 1, 2019 our operations in
Nipigon and Tunis are subject to the federal OBPS and potentially also to the Ontario output-based performance
standard (both of which remain to be fully detailed). Under the federal “Notice Establishing Criteria Respecting
16
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 115,725 tonnes for 2016 in the case
of Nipigon), each is considered a covered facility and subject to the federal OBPS.
Assuming that the federal OBPS regulations remain as set out in the January 9, 2019 proposal (discussed in the
section on Canada - Federal), the Tunis and Nipigon projects will be 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. 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, the Trump Administration has announced the planned withdrawal of the U.S.
from the Paris Agreement. In light of the legislative, judicial and executive factors influencing regulatory action,
significant uncertainty exists as to how greenhouse gas restrictions in the U.S. will impact our facilities in the future.
EMPLOYEES
As of February 27, 2019, we had 230 employees, 166 in the United States and 64 in Canada. Of our Canadian
employees, 44 are covered by collective bargaining agreements, which will expire on December 19, 2020 and December
31, 2020. During 2018, we did not experience any labor stoppages or labor disputes at any of our facilities.
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AVAILABLE INFORMATION
We make available, free of charge, on our website, www.atlanticpower.com, our Annual Report on Form 10-K,
Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as soon as
reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Additionally, we make
available on our website and the System for Electronic Document Analysis and Retrieval at www.sedar.com, our
Canadian securities filings. The public may read and copy any materials we file with the SEC at the SEC’s Public
Reference Room at 100 F Street, NE, Washington, DC 20549. We are not a foreign private issuer, as defined in
Rule 3b-4 under the Exchange Act.
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 only as an inactive
textual reference and do not intend it to be an active link to our website.
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 Our Structure
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, 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. 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. 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.
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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, including on our preferred shares
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, or reacting to, 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
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 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 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 could 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.
Under our existing Credit Facilities, 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 to be materially different than expected. We may choose in the future to pursue an
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amendment to our existing Credit Facilities to provide for a transition mechanism or other reference rate in anticipation
of LIBOR’s discontinuation, but we can give no assurance that we will be able to reach agreement with our lenders on
any such amendment.
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;
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, 2018, our consolidated debt represented approximately 79% 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 96% 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, 2018, we had (i) no amount outstanding and $76.9 million issued in letters of credit under
our revolving credit facility, (ii) $102.4 million of outstanding convertible debentures, and (iii) $625.0 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.
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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 revolving credit facility,
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. In addition, any covenant breach or event of default could harm our credit rating 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, and could trigger
termination rights under certain contracts
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, restrict access to our revolving credit facility and/or trigger
termination rights or enhanced disclosure requirements under certain contracts to which we are a party. 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 revolving credit
facility, 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
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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 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
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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
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 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 under
the Credit Facilities, the Partnership will be required to offer each electing lender a prepayment of such lender’s term
loans 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.
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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.
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.
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 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
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.
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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 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.
Atlantic Power Preferred Equity Ltd. is subject to Canadian tax, as is Atlantic Power’s income from the Partnership
As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes. See “Risks
Related to Our Structure—We are subject to Canadian tax.” We are required to include in computing our taxable income
any income earned by the Partnership. In addition, 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. Atlantic Power
Preferred Equity Ltd. is liable to pay its applicable Canadian taxes.
Risks 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
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 June 30, 2019 and March 31, 2037. 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. 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 or long lived assets could have a material
adverse effect on our business, results of operations and financial condition.”
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Nine of our projects, representing 57% of our operating net MW and 51% of our 2018 Project Adjusted
EBITDA, have PPAs or other contractual arrangements that will expire within the next five years. These projects are
Williams Lake (2019), Oxnard (2020), Calstock (2020), Kenilworth (2020), Manchief (2022), Frederickson (2022),
Moresby Lake (2022), Nipigon (2022) and Orlando (2023).
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 2018, the largest customers of our
power generation projects, including projects recorded under the equity method of accounting, are Niagara Mohawk
Power Corporation, Equistar Chemicals L. P., BC Hydro, Georgia Power Company and IESO, which account for
approximately 15.1%, 12.6%, 12.5%, 10.9% and 10.8%, 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 Standard & Poor’s.
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;
fuel transportation capacity constraints;
• weather conditions;
•
•
•
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;
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•
•
•
•
•
•
•
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 power purchase agreement 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 Pennslyvania 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 profitability 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.
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
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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
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
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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 Revolving Credit Facility 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.
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.
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.
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 product. 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.
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 continue to raise discussions 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.
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Risks that are beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of
war, natural disasters 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. 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
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.
Our business faces significant operating hazards, natural disaster risks and other hazards such as fire and explosions
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. In addition, we are exposed to
natural disaster risks and other hazards such as fire and explosions. 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.
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, financial condition and future prospects.
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.
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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.
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.
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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
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 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
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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 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, 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.
Environmental laws and regulations have generally become more stringent over the long term; however, more
recently the Trump Administration has taken numerous actions to reduce U.S. federal regulatory burdens, particularly
for coal-fired power plants. In the United States, the Clean Air Act and related regulations and programs of the
Environmental Protection Agency extensively regulate the air emissions of sulfur dioxide, nitrogen oxides, mercury and
other compounds by power plants. The EPA’s Cross-State Air Pollution Rule (“CSAPR”), issued in 2011 and updated in
2017, requires 27 states and the District of Columbia to curb emissions of sulfur dioxide and nitrogen oxides from power
plants through participation in a cap and trade system or more aggressive state-by-state emissions limits. Other stringent
EPA air emission regulations include updates to national ambient air quality standards for sulfur dioxide, issued in 2010;
for fine particulate matter, issued in 2012; and for ozone, issued in 2015. However, in December 2018 the EPA proposed
revising the findings that supported its 2011 mercury and air toxics emissions standards for power plants (“MATS”). In
July 2018, the Trump Administration issued the first in a planned series of two final rules to significantly roll back the
EPA’s regulations governing disposal of coal ash in landfills and impoundments. The Trump Administration also has
been pursuing other initiatives that would revoke existing environmental requirements, largely focused on coal mining
and coal-fired power plants. We continue to assess the impact of these changes on our business.
Similar increasingly stringent environmental regulations also apply to our projects in British Columbia and
Ontario.
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.
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
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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, 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 our profitability. Concerning our projects in Ontario, the federal OBPS, from the
beginning of 2019, may have 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 our profitability, but note that there will be a federal election in Canada in 2019 and that the future of
the current federal carbon pricing regime for GHG emissions is now uncertain.
All of our subject generating facilities have complied on a timely basis with the new EPA and Ontario
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. 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.
34
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, 2018, 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 $0, $187.2 million and $85.9 million of goodwill, long-lived asset and equity method
investment impairments for the years ended December 31, 2018, 2017 and 2016, respectively. See Note 9 to the
consolidated financial statements included in this Annual Report on Form 10-K.
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 stock.
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 stock.
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
35
make other capital and operating expenditures. See “—Risk Related to Our Structure—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 have limited control over management decisions at certain projects
Three 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. Third-party operators operate three 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.
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
We may be unable to identify attractive acquisition candidates in the power industry in the future, and we may
not be able to make acquisitions on an accretive basis or at all, or be sure that such acquisitions, if any, will be
successfully integrated into our existing operations. In addition, 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.
Although electricity demand is expected to grow, such growth is projected to occur at a slow rate. While the
North American power industry is continuing to undergo consolidation and may present attractive investment
opportunities, the demand for and the value of power generation assets is likely to be impacted by future regulatory
policies as the industry continues to transition. This consolidation and transition may present attractive acquisition
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.
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.
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
us from managing our interests in these projects in the manner we see fit, and may have an adverse effect on our ability
36
to sell our interests in these projects at the prices we desire. See “—Risks Related to Our Structure—We cannot provide
any assurance regarding the outcome or impact on our business of any potential options we are considering.”
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 income (loss) (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 income (loss) (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.
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. These agreements expire periodically and 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.
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
37
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, 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.
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 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.
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. See “—Risks Related to our Structure—Our recent
management changes may impact our business plan.”
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
38
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.
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,
2018.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
39
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
PART II
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Share Repurchase Program
On December 31, 2018, we commenced a new 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. The NCIBs expire on December 30, 2019 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 10,623,464 common shares based on 10% of our public float as of December 17, 2018 and we
are limited to daily purchases of 10,300 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 U.S. Securities Exchange Act of 1934, 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. As of December 31, 2018, we have not made any repurchases under the new NCIBs.
This new NCIB replaced the prior NCIB that expired on December 28, 2018. Through December 31, 2018, we
repurchased and cancelled approximately 7.8 million common shares at a cost of $16.6 million. The following table
provides purchases of common equity securities by the Issuer and Affiliated Purchasers for the period of October 1, 2018
through December 31, 2018:
Purchase Period
10/1/2018 - 10/31/2018
11/1/2018 - 11/30/2018
12/1/2018 - 12/31/2018
Total
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
291,327 $
668,532 $
1,076,904 $
2,036,763
2.15
2.15
2.14
291,327
668,532
1,076,904 $
2,036,763
0 (1)
(1) This plan expired on December 28, 2018.
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 United States Securities
Exchange Act of 1934, 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.
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 109,686,626 on February 27, 2019.
40
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of December 31, 2018 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
2,634,801 $
359,936
2,994,737 $
—
—
—
—
179,968
179,968
(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.
Specifically, the number of securities to be issued upon exercise of outstanding awards reflects two-thirds of the
number of outstanding notional shares. 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 600,000.
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, 2013, through December 31, 2018, 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. Our common
shares trade on the NYSE under the symbol “AT” and the TSX under the symbol “ATP”.
The performance graph shown below is being furnished and compares each period assuming that a $100
investment was made on December 31, 2013, 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.
41
Comparison of Cumulative Total Return
AT
S&P
S&P / TSX
Dec-2013
Dec-2014
Dec-2015
Dec-2016
Dec-2017
Dec-2018
$
100.00 $
100.00
100.00
84.90 $
64.13 $
81.39 $
76.51 $
113.69
107.42
115.07
107.42
127.03
112.23
148.86
119.00
70.65
144.48
105.15
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, 2018 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, 2018.
42
(in millions of U.S. dollars, except as otherwise stated)
Project revenue
Project income (loss)
Income (loss) from continuing operations
Income (loss) from discontinued operations, net of tax
Net income (loss) attributable to Atlantic Power
Corporation
Basic earnings (loss) per share
Earnings (loss) per share from continuing
operations attributable to Atlantic Power Corporation
Earnings (loss) per share from discontinued operations,
net of tax
Net income (loss) attributable to Atlantic Power
Corporation
$
$
$
2018(a)
282.3 $
88.2
37.2
—
2015(a)(b)
Year Ended December 31,
2016(a)
399.2 $
10.1
(113.9)
—
2017(a)
431.0 $
(47.4)
(93.0)
—
2014(a)(b)(c)(d)
489.9
(38.9)
(153.2)
(29.0)
420.2 $
(41.4)
(84.1)
19.5
36.8
(98.6)
(122.4)
(62.4)
(177.4)
0.33 $
(0.86) $
(1.02) $
(0.76) $
(1.37)
—
—
—
0.25
(0.10)
0.33 $
(0.86) $
(1.02) $
(0.51) $
(1.47)
Diluted earnings (loss) per share attributable to Atlantic
Power Corporation (e)
Dividend declared per common share
Total assets
Total long-term liabilities
0.29 $
— $
(1.47)
$
$
0.29
$ 1,024.5 $ 1,158.8 $ 1,456.8 $ 1,671.2 $ 2,853.2
829.1 $ 1,020.0 $ 1,020.0 $ 1,656.6
$
(0.86) $
— $
(1.02) $
— $
(0.51) $
0.09 $
716.2 $
(a)
Includes $0, $187.2 million, $85.9 million, $127.8 million and $106.6 million of goodwill, long-lived asset and
equity method investment impairments for the years end December 31, 2018, 2017, 2016, 2015 and 2014,
respectively.
(b) Excludes the Wind Projects, which are classified as discontinued operations for the years ended December 31, 2015
and 2014.
(c) Excludes Greeley, which is classified as discontinued operations for the year ended December 31, 2014.
(d) The total assets exclude $62.8 million of deferred financing costs for the year ended December 31, 2014.
(e) Diluted earnings (loss) 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 Form 10-K for information relating to the
number of shares used in calculating basic and diluted earnings (loss) per share for the periods presented.
43
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) Our Strategy, Overview of 2018 Results and Recent Events
2) Consolidated Overview and Results of Operations
3) Project Operating Performance
4) Supplementary Non-GAAP Financial Information
5) Liquidity and Capital Resources
6) Critical Accounting Policies
Our Strategy, Overview of 2018 Results and Recent Events
We continue to be focused on the following priorities:
• Debt reduction: By significantly reducing our debt we believe that we have strengthened our balance sheet,
improved our financial flexibility and credit profile and meaningfully reduced our cash interest payments.
We expect to continue reducing debt over the next several years and improving our leverage ratio.
• Cost control: We have reduced our corporate overhead structure significantly and continue to seek
opportunities to further lower it.
• PPA renewals: We seek to leverage the strength of our operations, fuel and technological diversity and
location of our projects to renew or extend expiring PPAs where economically feasible, or make alternative
arrangements in what continues to be challenging market conditions.
• Capital allocation: We plan to be rational in allocating our capital to balance risk and reward, evaluating
competing uses such as organic growth, external investments or acquisitions and share repurchases with a
goal of achieving returns that are accretive to our intrinsic value per share.
• Optimizing our fleet: By making capital investments in or efficiency improvements to our existing projects
we are able to achieve cash returns that are higher than what is currently available in the external markets
and at lower risk. We also have implemented various initiatives that we expect will ensure the continued
safe and reliable operating performance of our projects while achieving modest cost savings.
• External growth: We take a creative, disciplined and value-oriented approach to external development or
acquisitions, focusing on out-of-favor generation assets with an attractive price-to-value relationship.
In 2018, we continued to make progress in strengthening the Company. Our key achievements in the execution
of our strategy during 2018 were:
• Debt reduction – During 2018, we made payments of $100.3 million to amortize our corporate and project-
level debt. Additionally, we were able to reprice the Term Loan Facilities twice during 2018, lowering the
rate from LIBOR plus 3.50% to LIBOR plus 2.75%. In 2017, we repriced these facilities twice from
LIBOR plus 5.0% to LIBOR plus 3.50%. The multiple repricings of the term loan facility are expected to
save (approximately) a cumulative $44 million of interest expense from repricing through maturity. We
also reshaped our maturity profile by issuing Cdn$115 million of convertible debentures due in 2025 and
using a portion of the proceeds to redeem the full $42.5 million of our Series C Debentures scheduled to
44
mature in June 2019 and a partial redemption of Cdn$56.2 million of our Series D Debentures maturing in
December 2019.
• Common and preferred share repurchases – We utilized $24.6 million of our discretionary capital to
repurchase and cancel common ($16.6 million) and preferred ($8.0 million) shares during 2018 at prices
that were attractive relative to our estimates of value.
• PPA renewals – In April 2018, a subsidiary of Merck & Co., Inc. exercised the first of its three successive
one-year extension options under the PPA for Kenilworth. In January 2019, Merck exercised the second
such option, extending the expiration date of our Kenilworth project’s PPA from September 30, 2019 to
September 30, 2020.
• Overhead cost reduction – We cut our corporate overhead expense from approximately $54 million in 2013
to $24 million for 2018, which represents a cumulative reduction from 2013 of approximately 57%. We
have maintained our corporate overhead in the $23 million range for the past three years.
• External growth – We made our first external acquisition in over five years with the purchase in July 2018
of the remaining 50% interest in our Koma Kulshan project, which brought our ownership to 100%. We
also signed an agreement to purchase two biomass facilities in South Carolina with an expected close late
in the third quarter or in the fourth quarter of 2019.
•
Investment in our fleet – During 2018 we invested $35.2 million in the portfolio in the form of project
capital expenditures and maintenance expenses, seeking to maintain the safety and operating efficiency of
our fleet.
Performance highlights
Project revenue
Project income (loss)
Net income (loss) attributable to Atlantic Power Corporation
Earnings (loss) per share attributable to Atlantic Power Corporation—basic
Earnings (loss) per share attributable to Atlantic Power Corporation—diluted
Project Adjusted EBITDA(1)
Year Ended December 31,
2017
2016
2018
$
$
$
$ 282.3 $ 431.0 $ 399.2
10.1
(47.4) $
(98.6) $ (122.4)
(1.02)
(0.86) $
(1.02)
(0.86)
$ 185.1 $ 288.8 $ 202.2
88.2 $
36.8 $
0.33 $
0.29
(1) See reconciliation and definition below under Supplementary Non-GAAP Financial Information.
Revenue decreased from $431.0 million in the year ended December 31, 2017 to $282.3 million in the year
ended December 31, 2018, a decrease of $148.7 million. The primary drivers of the increase are as follows:
•
San Diego projects – the Naval Station, North Island and NTC projects ceased operations in February
2018. This resulted in a $69.0 million decrease in project revenue;
• Enhanced dispatch contracts – the enhanced dispatch contracts with the IESO for Kapuskasing and North
Bay expired in December 2017, which resulted in a $54.4 million decrease in project revenue;
• OEFC settlement – we recorded $28.6 million of project revenue related to the OEFC settlement in the
comparable 2017 period at our North Bay, Kapuskasing and Tunis projects, which did not recur in 2018;
45
• Williams Lake – the project’s energy purchase agreement extension became effective in April 2018, which
provides lower pass-through of costs than the previous contract. The project also had lower dispatch than
the comparable 2017 period. These factors resulted in a $10.7 million decrease in project revenue; and
• Koma Kulshan Acquisition – We recognized a $7.2 million gain for the year ended December 31, 2018 as a
result of remeasuring our previous 50% equity interest in Koma Kulshan to fair value after acquiring the
remaining 50% and consolidating the project.
These decreases in project revenue were partially offset by:
• Morris – there was a $7.4 million increase in revenue at our Morris project due to higher capacity prices,
higher merchant dispatch and higher steam and ancillary services than 2017.
Consolidated project income was $88.2 million for the year ended December 31, 2018, an increase of
$135.6 million from the prior year project loss of $47.4 million. The primary drivers of the increase are as follows:
•
Impairment of goodwill, long-lived assets and equity investments – we recorded $187.1 million of
impairments in 2017 and none in 2018;
• Fuel expense – fuel expense decreased from $106.3 million in 2017 to $73.1 million in 2018 primarily due
to a $34.4 million decrease at the Naval Station, North Island and NTC projects, which ceased operations
in February 2018;
• Depreciation and amortization expense – depreciation and amortization expense decreased by $29.4
million from 2017 primarily due to decreases of $16.3 million and $13.5 million at our Kapuskasing and
North Bay projects, respectively, which were fully depreciated as of December 31, 2017 and a decrease of
$7.7 million at our San Diego projects due to accelerated depreciation beginning in the third quarter of
2017. These decreases were partially offset by $12.5 million of increased amortization of the PPA
intangible asset at our Nipigon project;
•
Interest expense – project-level interest expense decreased by $15.7 million from $17.5 million in 2017 to
$1.8 million in 2018 primarily due to the repayment of Piedmont’s non-recourse project-level debt, in full,
in 2017; and
• Equity in earnings of unconsolidated affiliates – project income increased $5.3 million at Orlando due to
higher capacity revenue than 2017 and $6.5 million at Frederickson due to maintenance outages in 2017.
These increases in project income were partially offset by a decrease in project income resulting from:
• Revenue – revenue decreased $148.7 million as discussed above.
A detailed discussion of project income (loss) by segment is provided in Consolidated Overview and Results of
Operations 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
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.
46
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 June 30, 2019 and March 31, 2037. 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 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.”
• 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 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 profitability 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 power purchase agreement 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 Our Business and Our Projects—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
and waste heat levels, 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 “Risk Factors—Risks Related to Our Business and Our Projects.”
• 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—
Risks Related to Our Business and Our Projects—The expiration or termination of PPAs could have a
material adverse impact on our business, results of operations and financial condition.” These projects will
47
be free of debt when their PPAs expire, which we expect to provide us with some flexibility to pursue the
most economic type of contract without restrictions that might be imposed by project-level debt.
• One of our projects has non-recourse project-level debt that can restrict the ability of the project to make
cash distributions. The project-level debt agreement contains a cash flow coverage ratio test that restricts
the project’s cash distributions if project cash flows do not exceed project-level debt service requirements
by a specified amount. Although this project is currently meeting its debt service requirements, we cannot
provide any assurances that it 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—Project-level debt” and
Item 1A. “Risk Factors—Risks Related to Our Structure—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 long-lived assets and 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. We recorded $0, $187.1 million ($101.1 million at consolidated projects and $86.0 million at projects accounted
for under the equity method of accounting) and $85.9 million of goodwill and long-lived asset impairments for the years
ended December 31, 2018, 2017 and 2016, 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 and long-lived asset
impairments.
Consolidated Overview and Results of Operations
We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. The segment
classified as 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
48
are not allocated to the operating segments when determining segment profit or loss. Project income (loss) is the primary
GAAP measure of our operating results and is discussed below by reportable segment.
2018 compared to 2017
The following tables and discussion summarize our consolidated results of operations and provide an analysis
by reportable segment:
Years Ended December 31,
2018
2017
$ change % change
$ 130.9 $ 148.9 $ (18.0)
(7.9)
(122.8)
(148.7)
97.9
53.5
282.3
105.8
176.3
431.0
73.1
85.0
83.7
241.8
106.3
87.8
113.1
307.2
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)
(33.2)
(2.8)
(29.4)
(65.4)
0.1
98.0
15.7
101.1
4.0
218.9
135.6
0.3
23.6
23.9
(11.5)
64.2
52.7
(39.1)
16.3
(22.8)
(2.6)
(0.4)
(3.0)
(52.9)
103.7
50.8
188.5
(151.1)
37.4
58.3
(58.1)
0.2
130.2
(93.0)
37.2
0.4
(5.2)
5.6
36.8 $ (98.6) $ 135.4
(12.1)%
(7.5)%
(69.7)%
(34.5)%
(31.2)%
(3.2)%
(26.0)%
(21.3)%
4.8 %
NM
(89.7)%
(100.0)%
NM
NM
NM
1.3 %
(17.9)%
NM
NM
(51.0)%
NM
(100.3)%
NM
(92.9)%
NM
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (loss):
Change in fair value of derivative instruments
Equity in earnings (loss) of unconsolidated affiliates
Interest, net
Impairment
Other income, net
Project income (loss)
Administrative and other expenses:
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
$
49
Project Income (Loss) by Segment
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Year Ended December 31, 2018
East U.S. West U.S. Canada
Un-Allocated Consolidated
Corporate
Total
13.5 $ 29.9 $
27.8
2.5
43.8
17.3
31.7
78.9
— $
—
0.9
0.9
$ 87.5 $
52.8
18.4
158.7
49.1
35.7
36.4
121.2
10.9
25.0
18.6
54.5
13.1
23.8
28.6
65.5
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
—
0.5
0.1
0.6
(1.0)
—
—
—
0.1
(0.9)
(0.6) $
Project other income (expense):
Change in fair value of derivative instruments
Equity in earnings of unconsolidated affiliates
Interest expense, net
Impairment
Other income, net
(0.4)
35.7
(1.9)
—
—
33.4
—
7.5
0.1
—
4.0
11.6
3.6
—
—
—
—
3.6
Project income (loss)
$ 70.9 $
0.9 $ 17.0 $
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 of unconsolidated affiliates
Interest expense, net
Impairment
Other income, net
Project (loss) income
East U.S.
Year Ended December 31, 2017
East U.S. West U.S. Canada
Un-Allocated Consolidated
Corporate
Total
$ 87.3 $
49.4
15.8
152.5
33.0 $ 28.6 $
45.6
30.3
108.9
10.8
129.2
168.6
46.4
34.5
35.2
116.1
44.8
26.0
25.6
96.4
15.1
27.6
51.9
94.6
6.3
(27.6)
(17.4)
(14.7)
—
(53.4)
—
(27.2)
—
(57.3)
—
(84.5)
$ (17.0) $ (72.0) $ 38.8 $
(6.1)
—
(0.1)
(29.1)
0.1
(35.2)
— $
—
1.0
1.0
—
(0.3)
0.4
0.1
148.9
105.8
176.3
431.0
106.3
87.8
113.1
307.2
1.9
—
—
—
—
1.9
2.8 $
2.1
(54.8)
(17.5)
(101.1)
0.1
(171.2)
(47.4)
Project income for 2018 increased $87.9 million from 2017 primarily due to:
•
increased project income of $48.2 million and $11.6 million at Chambers and Selkirk, respectively,
primarily due to impairments of our equity investments of $47.1 million and $10.6 million recorded for the
year ended December 31, 2017, respectively;
50
•
•
•
•
increased project income of $11.5 million at Curtis Palmer due primarily to a $14.7 million goodwill
impairment recorded in 2017, offset by a $3.2 million decrease in revenue from lower water flows than
2017;
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;
increased project income of $5.7 million at Morris primarily due to higher energy and capacity revenues
than 2017; and
increased project income of $5.3 million at Orlando primarily due to higher generation and a higher
capacity rate than 2017.
West U.S.
Project income for 2018 increased $72.9 million from 2017 primarily due to:
•
•
•
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 long-lived asset impairments recorded
in 2017, respectively. These projects ceased operations in February 2018;
decreased project loss of $34.8 million at Frederickson primarily due to a $28.3 million impairment of our
investment in the project recorded in 2017; and
increased project income of $6.6 million at Koma Kulshan primarily due to a $7.2 million purchase
accounting gain recognized from a step acquisition of the 50% remaining interest in Koma Kulshan in
2018.
These increases were partially offset by:
•
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.
Canada
Project income for 2018 decreased $21.8 million from 2017 primarily due to:
•
•
•
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 the comparable
period 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 the
comparable period in 2017, partially offset by a $16.3 million decrease in depreciation expense; and
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.
These decreases were partially offset by:
•
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 renewed energy purchase agreement extension that became effective in April 2018.
51
Un-Allocated 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.
Administrative and other expenses (income)
Administrative and other expenses (income) includes the income and expenses not attributable to our projects
and are allocated to the Un-allocated 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 senior secured credit facility.
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
tax rates and $1.1 million related to capital loss on intercompany notes.
52
2017 compared to 2016
The following tables and discussion summarize our consolidated results of operations and provides an analysis
by reportable segment:
Year ended December 31,
2017
2016
$ change % change
$ 148.9 $ 184.2 $ (35.3)
(36.1)
141.9
103.2
73.1
31.8
399.2
105.8
176.3
431.0
106.3
87.8
113.1
307.2
149.5
105.2
113.5
368.2
(43.2)
(17.4)
(0.4)
(61.0)
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)
5.6
37.9
35.9
(9.2)
(85.9)
0.4
(20.9)
10.1
(35.8)
(90.7)
(8.3)
(15.2)
(0.3)
(150.3)
(57.5)
22.6
106.0
13.9
(3.9)
138.6
(128.5)
(14.6)
(113.9)
8.5
1.0
(41.8)
2.4
3.5
(34.9)
(22.6)
(43.5)
20.9
(2.9)
23.8
$ (98.6) $ (122.4) $
(19.2)%
(25.4)%
NM
8.0 %
(28.9)%
(16.5)%
(0.4)%
(16.6)%
(94.5)%
NM
90.2 %
17.7 %
(75.0)%
NM
NM
4.4 %
(39.4)%
17.3 %
(89.7)%
(25.2)%
17.6 %
NM
(18.3)%
(34.1)%
(19.4)%
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other 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
Administrative and other expenses (income):
Administration
Interest expense, net
Foreign exchange loss
Other income, net
Loss from operations before income taxes
Income tax benefit
Net loss
Net income attributable to preferred shares of a subsidiary company
Net 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 loss of unconsolidated affiliates
Interest expense, net
Impairment
Other income, 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
Impairment
Other income, net
Project income (loss)
East U.S.
Year Ended December 31, 2017
East U.S. West U.S. Canada
Un-Allocated Consolidated
Corporate
Total
$ 87.3 $
49.4
15.8
152.5
33.0 $ 28.6 $
45.6
30.3
108.9
10.8
129.2
168.6
46.4
34.5
35.2
116.1
44.8
26.0
25.6
96.4
15.1
27.6
51.9
94.6
6.3
(27.6)
(17.4)
(14.7)
—
(53.4)
—
(27.2)
—
(57.3)
—
(84.5)
$ (17.0) $ (72.0) $ 38.8 $
(6.1)
—
(0.1)
(29.1)
0.1
(35.2)
— $
—
1.0
1.0
—
(0.3)
0.4
0.1
148.9
105.8
176.3
431.0
106.3
87.8
113.1
307.2
1.9
—
—
—
—
1.9
2.8 $
2.1
-54.8
(17.5)
(101.1)
0.1
(171.2)
(47.4)
Year Ended December 31, 2016
East U.S. West U.S. Canada
Un-Allocated Consolidated
Corporate
Total
$ 70.1 $
49.0
15.4
134.5
31.9 $ 82.2 $
45.6
23.8
101.3
47.3
33.0
162.5
45.3
41.3
34.4
121.0
36.9
26.4
29.1
92.4
67.3
36.4
49.5
153.2
9.2
33.0
(9.1)
(15.4)
—
17.7
$ 31.2 $
—
2.9
—
—
—
2.9
11.8 $ (35.7) $
25.5
—
—
(70.5)
—
(45.0)
— $
—
0.9
0.9
—
1.1
0.5
1.6
3.2
—
(0.1)
—
0.4
3.5
2.8 $
184.2
141.9
73.1
399.2
149.5
105.2
113.5
368.2
37.9
35.9
(9.2)
(85.9)
0.4
(20.9)
10.1
Project income for 2017 decreased $48.2 million from 2016 primarily due to:
•
decreased project income of $48.1 million and $11.3 million at Chambers and Selkirk, respectively,
primarily due to impairments of our equity investments of $47.1 million and $10.6 million recorded for the
year ended December 31, 2017, respectively; and
54
•
decreased project income of $7.5 million at Orlando primarily due to an $11.9 million decrease in the fair
value of natural gas swaps and lower revenue from decreased dispatch, partially offset by $6.8 million of
lower fuel expense resulting from the settlement of favorable fuel swaps.
These decreases were partially offset by:
•
•
increased project income of $13.8 million at Curtis Palmer due primarily to a $13.3 million increase in
revenue from higher water flows than 2016; and
increased project income of $5.0 million at Morris due primarily to $7.5 million of decreased maintenance
expenses resulting from the overhaul of two gas turbines and one steam turbine during 2016 and $4.0
million higher revenues due to less maintenance outages than 2016. These increases were partially offset
by $7.5 million of higher fuel expense.
West U.S.
Project income for 2017 decreased $83.8 million from 2016 primarily due to:
•
•
decreased project income of $22.6 million, $21.0 million and $12.0 million at Naval Station, North Island
and NTC primarily due to $22.5 million, $21.2 million and $13.5 million long-lived asset impairments
recorded for the year ended December 31, 2017, respectively; and
decreased project income of $30.1 million at Frederickson primarily due to a $28.3 million impairment of
our investment in the project recorded for the year ended December 31, 2017.
Canada
Project income for 2017 increased $74.5 million from 2016 primarily due to:
•
•
•
•
increased project income of $47.1 million at Mamquam due primarily to a $50.2 million goodwill
impairment recorded for the year ended December 31, 2016, partially offset by a $2.8 million decrease in
energy revenue due to lower water flows than 2016;
increased project income of $26.6 million at North Bay due primarily to a $10.2 million goodwill and long-
lived asset impairment recorded in the third quarter of 2016, $23.1 million of lower fuel expense in 2017
due to the expiration of an unfavorable fuel contract in December 2016, $3.7 million increase in revenue
received due to the OEFC settlement and $2.3 million of lower maintenance expense. These increases were
partially offset by a $13.6 million increased gain in the fair value of a fuel agreement accounted for as a
derivative in 2016;
increased project income of $24.8 million at Kapuskasing due primarily to $24.8 million of lower fuel
expense in 2017 due to the expiration of an unfavorable fuel contract in December 2016, $8.9 million
goodwill and long-lived asset impairment recorded in the third quarter of 2016 and $3.9 million of lower
maintenance expense. These increases were partially offset by a $13.6 million gain in the fair value of a
fuel agreement accounted for as a derivative in 2016; and
increased project income of $6.1 million at Tunis due primarily to the collection of the OEFC settlement.
These increases were partially offset by:
•
decreased project income of $27.0 million at Williams Lake primarily due to a $29.1 million long-lived
asset impairment recorded for the year ended December 31, 2017; and
55
•
decreased project income of $3.2 million at Nipigon due primarily to a $4.4 million decrease in the fair
value of fuel agreements accounted for as derivatives.
Un-Allocated Corporate
Total project income for 2017 did not change materially from 2016.
Administrative and other expenses (income)
Administrative and other expenses (income) includes the income and expenses not attributable to our projects
and are allocated to the Un-allocated 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 increased $1.0 million from 2016 primarily due to a $0.6 million increase in employee
compensation costs, $0.6 million of higher professional services costs and $0.2 million of lower rent expense.
Interest, net
Interest expense decreased $41.8 million from 2016 primarily due to $37.6 million of deferred financing cost
write-offs resulting from the extinguishment of the Senior Secured Term Loan Facilities and the repurchase and
cancellation of the Series A, B, and, in part, C convertible debentures during 2016 as well as lower outstanding debt
balances and a lower interest rate on the senior secured credit facilities for the year ended December 31, 2017.
Foreign exchange loss
Foreign exchange loss increased $2.4 million from 2016 primarily due to a $1.4 million increase in unrealized
loss in the revaluation of instruments denominated in Canadian dollars and $1.0 million of realized transaction losses.
The U.S. dollar to Canadian dollar exchange rate was 1.25 and 1.34 at December 31, 2017 and 2016, respectively, a
decrease of 6.6%. The average U.S. dollar to Canadian dollar exchange rate was 1.28 for the year ended December 31,
2017 and was 1.32 for the year ended December 31, 2016.
Other income, net
Other income, net decreased $3.5 million from the 2016 comparable period primarily due to a $3.7 million gain
recorded on the purchase and cancellation of convertible debentures during 2016.
Income tax benefit
Income tax benefit for the year ended December 31, 2017 was $58.1 million. Expected income tax benefit for
the same period, based on the Canadian enacted statutory rate of 26%, was $39.3 million. On December 22, 2017, the
Tax Cuts and Jobs Act of 2017 was signed into law making significant changes to the Internal Revenue Code. Changes
include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after
December 31, 2017, new limitations on the deduction of net business interest expense, and a new base erosion and anti-
abuse tax. After preliminary estimates based on guidance available as of the date of this filing, the interest expense
limitation and base erosion and anti-abuse tax is not expected to have a material impact to cash taxes in future tax years.
The primary item impacting the tax rate for the twelve months ended December 31, 2017 is the amount related to the
remeasurement of deferred tax assets and liabilities, based on the rates at which they are expected to reverse in the future
56
for $28.5 million. In addition, the rate was further impacted by $9.9 million related to goodwill impairment. These items
were offset by $34.6 million related to a net decrease to our valuation allowances, consisting primarily of decreases of
$34.1 million in the United States due to the remeasurement of deferred tax assets and a decrease of $0.5 million in
Canada related to income. In addition, the rate was further impacted by $20.1 million relating to operating in higher tax
rate jurisdictions, $2.4 million relating to foreign exchange and $0.1 million relating to other permanent differences.
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.
(in Net GWh)
Segment
East U.S.
West U.S.
Canada
Total
Generation
Year ended December 31,
2018
2017
2016
% change
2018 vs. 2017 2017 vs. 2016
% change
2,451.6 2,478.5 2,430.2
936.2 1,601.5 1,506.6
934.7 1,977.2
973.8
4,361.6 5,014.7 5,914.0
(1.1)%
(41.5)%
4.2 %
(13.0)%
2.0 %
6.3 %
(52.7)%
(15.2)%
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 West U.S. 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; and
decreased generation in the East U.S. segment primarily due to a 50.7 net GWh decrease in generation at
Curtis Palmer due to lower water flows than 2017.
These decreases were partially offset by:
•
increased generation in the Canada segment primarily due to an increase of 44.4 net GWh at Mamquam
due to a 2017 maintenance outage and higher water flows than 2017.
Year ended December 31, 2017 compared with Year ended December 31, 2016
Aggregate power generation for 2017 decreased 15.2% from 2016 primarily due to:
•
decreased generation in the Canada segment primarily due to a decrease of 928.6 net GWh on a combined
basis at Kapuskasing, Nipigon and North Bay, due to their suspended operation status under the enhanced
dispatch contracts.
57
This decrease was partially offset by:
•
•
increased generation in the East U.S. segment primarily due to a 107.6 net GWh increase in generation at
Curtis Palmer due to higher water flows than the comparable period in 2016 and a 68.8 net GWh increase
in generation at Morris due to a maintenance outage in 2016. These increases were partially offset by an
83.9 net GWh decrease in generation at Selkirk due to lower dispatch from low merchant power prices;
and
increased generation in the West U.S. segment primarily due to a 47.1 net GWh increase in generation at
Frederickson, and a 34.6 net GWh increase in generation at Manchief due to higher dispatch than 2016.
Availability
Segment
East U.S.
West U.S.
Canada
Weighted average
2018
2017
Year ended December 31,
% change
2018 vs. 2017 2017 vs. 2016
% change
2016
97.1 % 88.8 % 93.1 %
95.2 % 92.1 % 92.1 %
96.0 % 92.8 % 95.3 %
96.5 % 90.3 % 93.3 %
9.3 %
3.4 %
3.4 %
6.9 %
(4.6)%
— %
(2.6)%
(3.2)%
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 East U.S. segment primarily due to maintenance outages at Kenilworth and
Orlando in 2017 and a shorter maintenance outage at Piedmont in 2018 than in 2017;
increased availability in the West U.S. segment primarily due to maintenance outages at Frederickson in
the comparable 2017 period, partially offset by decreased availability at Manchief due to a maintenance
outage in the 2018 period; and
increased availability in the Canada segment primarily due a maintenance outage at Mamquam in 2017.
Year ended December 31, 2017 compared with Year ended December 31, 2016
Weighted average availability for 2017 decreased to 90.3% from 93.3% in 2016 primarily due to:
•
•
•
decreased availability in the East U.S. segment resulting from decreased availability at Kenilworth, which
underwent a turbine overhaul in 2017, and decreased availability at Orlando due to a forced maintenance
outage in 2017. These decreases were partially offset by increased availability at Morris, which underwent
a planned maintenance outage in the third quarter of 2016;
decreased availability in the West U.S. segment primarily due to a planned maintenance outage at
Frederickson, offset by increased availability at NTC, which underwent an outage in 2016; and
decreased availability in the Canada segment resulting from Williams Lake, primarily due to forced
maintenance outages.
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 (loss) income. A reconciliation of Net (loss) income to Project (loss) income 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 income (loss)
Income tax expense (benefit)
Income (loss) from operations before income taxes
Administration
Interest expense, net
Foreign exchange (gain) loss
Other 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
Other income, net
Project Adjusted EBITDA
Project Adjusted EBITDA by segment
East U.S.
West U.S.
Canada
Un-Allocated Corporate
Total
East U.S.
Year ended December 31,
2017
2018
37.2 $ (93.0) $ (113.9) $ 130.2 $
$ change
(58.1)
(151.1)
23.6
64.2
16.3
(0.4)
0.2
37.4
23.9
52.7
(22.8)
(3.0)
88.2 $ (47.4) $
2016
2018
2017
20.9
(43.5)
58.3
(14.6)
(22.6)
188.5
(128.5)
1.0
0.3
22.6
(41.8)
(11.5)
106.0
2.4
(39.1)
13.9
(3.9)
3.5
(2.6)
10.1 $ 135.6 $ (57.5)
$
$
99.7
3.4
(2.2)
—
(4.0)
133.2
19.2
(2.1)
187.1
(1.2)
133.5
10.9
(37.9)
85.9
(0.3)
(33.5)
(15.8)
(0.1)
(187.1)
(2.8)
(0.3)
8.3
35.8
101.2
(0.9)
86.6
$ 185.1 $ 288.8 $ 202.2 $ (103.7) $
120.8
21.9
41.9
0.5
112.5
49.1
125.8
1.4
92.4
51.2
58.8
(0.2)
8.3
(27.2)
(83.9)
(0.9)
$ 185.1 $ 288.8 $ 202.2 $ (103.7) $
20.1
(2.1)
67.0
1.6
86.6
The following table summarizes Project Adjusted EBITDA for our East U.S. segment for the periods indicated:
Year ended December 31,
% change
2018 vs. 2017 2017 vs. 2016
% change
2016
2017
2018
East U.S.
Project Adjusted EBITDA
$ 120.8 $ 112.5 $ 92.4
7 %
22 %
59
Year ended December 31, 2018 compared with Year ended December 31, 2017
Project Adjusted EBITDA for 2018 increased $8.3 million or 7% from 2017 primarily due to 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;
and
$2.8 million at Orlando due to higher availability and contractual capacity rates than 2017.
These increases were 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 2017.
Year ended December 31, 2017 compared with Year ended December 31, 2016
Project Adjusted EBITDA for 2017 increased $20.1 million or 22% from 2016 primarily due to increases in
Project Adjusted EBITDA of:
•
•
•
$12.6 million at Curtis Palmer due to $13.3 million of increased revenues from higher water flows than
2016;
$4.6 million at Orlando primarily due to lower fuel expense resulting from the settlements of favorable fuel
swaps; and
$4.0 million at Morris due to $7.5 million of decreased maintenance expenses and $4.0 million of higher
revenues resulting from the overhaul of two gas turbines and one steam turbine during 2016. These
increases were partially offset by $7.5 million higher fuel expense.
West U.S.
The following table summarizes Project Adjusted EBITDA for our West U.S. segment for the periods
indicated:
Year ended December 31,
% change
2018 vs 2017
2016
2017
% change
2017 vs 2016
2018
West U.S.
Project Adjusted EBITDA
$ 21.9 $ 49.1 $ 51.2
(55) %
(4)%
Year ended December 31, 2018 compared with Year ended December 31, 2017
Project Adjusted EBITDA for 2018 decreased by $27.2 million or 55% from 2017 primarily due to decreases in
Project Adjusted EBITDA of:
•
•
$9.3 million, $9.0 million and $5.7 million at Naval Station, North Island and NTC, respectively, which
ceased operations in February 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 an increase in Project Adjusted EBITDA of:
•
$3.0 million at Frederickson due to lower planned maintenance expense than 2017.
60
Year ended December 31, 2017 compared with Year ended December 31, 2016
Project Adjusted EBITDA for 2017 decreased by $2.1 million or 4% from 2016 primarily due to a decrease in
Project Adjusted EBITDA of:
•
$2.1 million at Frederickson primarily due to higher maintenance expense than 2016, partially offset by
higher revenue.
Canada
The following table summarizes Project Adjusted EBITDA for our Canada segment for the periods indicated:
Year Ended December 31,
% change
2018 vs. 2017 2017 vs. 2016
% change
2016
2017
2018
Canada
Project Adjusted EBITDA
$ 41.9 $ 125.8 $ 58.8
(67)%
114 %
Year ended December 31, 2018 compared with Year ended December 31, 2017
Project Adjusted EBITDA for 2018 decreased by $83.9 million or 67% 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;
$9.0 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
$8.4 million at Williams Lake due to lower gross margin under the short-term contract extension that
became effective in April 2018, partially offset by cost reductions.
These decreases were partially offset by increases in Project Adjusted EBITDA of:
•
•
$3.3 million at Mamquam due to higher water flows and lower maintenance expense relative to 2017; and
$2.3 million at Nipigon due to a contractual rate increase and lower payroll expense than 2017.
Year ended December 31, 2017 compared with Year ended December 31, 2016
Project Adjusted EBITDA for 2017 increased by $67.0 million from 2016 primarily due to increases in Project
Adjusted EBITDA of:
•
•
•
$60.6 million at Kapuskasing and North Bay primarily due to $21.8 million received from the OEFC
settlement. These projects were not operational under the terms of their enhanced dispatch contracts during
2017. Additionally, each project had unfavorable fuel contracts that expired in 2016. As a result of these
factors, gross margin increased $32.5 million and maintenance expense decreased $6.2 million in 2017;
$6.8 million at Tunis primarily due to the collection of the OEFC settlement; and
$2.8 million at Nipigon primarily due to $7.0 million of lower fuel expense due to non-operational status
under the terms of its enhanced dispatch contract, partially offset by a $4.4 million decrease in the fair
value of fuel swap agreements.
61
These increases were partially offset by a decrease in Project Adjusted EBITDA of:
•
$3.2 million at Mamquam, due to lower water flows than 2016 and forced outages in 2017.
Un-allocated Corporate
The following table summarizes Project Adjusted EBITDA for our Un-allocated Corporate segment for the
periods indicated:
Un-allocated Corporate
Project Adjusted EBITDA
Year Ended December 31,
2018
2017
2016
% change % change
2018 vs. 2017 2017 vs. 2016
$ 0.5 $ 1.4 $ (0.2)
(64)%
NM
Year ended December 31, 2018 compared with Year ended December 31, 2017
Project Adjusted EBITDA did not change materially from 2017.
Year ended December 31, 2017 compared with Year ended December 31, 2016
Project Adjusted EBITDA increased by $1.6 million from 2016 primarily due to lower administrative expenses
related to reductions in the workforce.
Consolidated Cash Flow
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
2017
2018
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;
62
• 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 senior secured credit facility, 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.
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 is expected to close late in the third quarter or in the fourth quarter of 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 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;
63
• 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.
2017 compared to 2016
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
2017
2016
Change
$ 169.2 $ 112.3 $ 56.9
(1.9)
(80.3)
(4.3)
(178.9)
(2.4)
(98.6)
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, 2017, the net increase in cash flows provided by operating activities of $56.9
million was primarily the result of the following:
• OEFC Settlement – we received approximately $26.6 million related to our settlement with the OEFC for
the year December 31, 2017;
•
Impact of lower fuel costs and enhanced dispatch contracts in Ontario – we recorded $33.9 million of
higher gross margin at North Bay, Kapuskasing and Nipigon as a result of the expiration of unfavorable gas
purchase agreements in December 2016, as well as operating under the enhanced dispatch contracts in
2017;
• Operations and maintenance – we incurred $17.4 million of lower operations and maintenance costs, as a
result of decreased maintenance expense at Morris and Williams Lake, which underwent outages in 2016,
and at North Bay and Kapuskasing, which did not operate during 2017 due to the terms of their enhanced
dispatch contracts; and
64
• Hydrological conditions at Curtis Palmer – higher water flows at our Curtis Palmer project had a $13.3
million impact on cash flows from operations.
These increases were partially offset by a decrease in net cash provided by operating activities that was
primarily the result of the following:
• Working capital – changes in working capital resulted in a $24.3 million decrease in cash flows from
operating activities as compared to 2016 primarily due to $10.5 million of timing in revenue receipts at our
Kapuskasing, Nipigon and North Bay and $3.4 million decrease in prepaids, supplies and other assets;
• Hydrological conditions and maintenance outage at Mamquam – lower water flows and a forced outage at
our Mamquam project had a $3.2 million impact on cash flows from operations; and
• Waste heat – lower waste heat at our Calstock project had a $2.6 million negative impact on cash flows
from operations.
Investing Activities
For the year ended December 31, 2017, the net increase in cash flows used in investing activities of $1.9
million was primarily the result of the following:
• Reimbursement of construction costs – we received a reimbursement of $4.8 million in capitalized costs
from the customer for a construction project at Morris in 2016.
These increases were partially offset by the following:
• Purchases of PP&E – investments in capitalized plant additions were $1.9 million lower than 2016; and
• Proceeds from sale of equity investment – we received $1.0 million from the sale of our 17.7% equity
interest in Selkirk Cogen L.P.
Financing Activities
For the year ended December 31, 2017, the net increase in cash flows used in financing activities of $80.6
million was primarily the result of the following:
• The Credit Facilities – we received $231.1 million of net proceeds from issuance of the senior secured term
loan in 2016 after repayment of the previous term loan;
• Corporate and project-level debt repayments – we made $69.4 million of higher principal payments than
2016 primarily due to the $54.6 million retirement of Piedmont’s non-recourse project-level debt, as well
as higher principal payments on our Term Loan; and
• Preferred share repurchases – we paid $3.1 million in 2017 to repurchase and cancel preferred shares.
These increases were partially offset by the following:
• Convertible debenture repayments – we paid $188.5 million to redeem and cancel convertible debentures
in 2016;
65
• Deferred financing costs – we incurred $16.2 million of deferred financing costs related to the refinancing
of the senior secured credit facilities in 2016; and
• Common share repurchases – we paid $0.2 million in 2017 to repurchase and cancel common shares as
compared to $19.5 million in 2016.
Liquidity and Capital Resources
Cash and cash equivalents
Restricted cash
Total
Revolving credit facility availability
Total liquidity
December 31,
2018
December 31,
2017
$
$
68.3 $
2.1
70.4
123.1
193.5 $
78.7
6.2
84.9
119.5
204.4
Our primary source of liquidity is distributions from our projects and availability under our Revolving Credit
Facility. 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 June 30, 2019 to March 31, 2037. 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 Our Structure—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.”
Moreover, 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. 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.
We expect to reinvest approximately $24.3 million in our portfolio in the form of project capital expenditures
and maintenance expenses in 2019. Such investments are generally paid at the project level. See “—Capital and
Maintenance Expenditures.” We also expect to pay the remaining $10.4 million of the purchase price for two biomass
plants in South Carolina when the transaction closes (expected to be) late in the third quarter or the fourth quarter of
2019. The Company plans to use its liquidity to redeem the remaining Cdn$24.7 million of 6.00% Series D Debentures
($18.1 million equivalent) at or before their December 2019 maturity date. Other than these items, we do not expect any
other material or unusual requirements for cash outflow in 2019 for capital expenditures or other required investments.
We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations
and meet obligations as they become due for at least the next 12 months from February 27, 2019.
66
Repurchases of Securities
On December 31, 2018, we commenced a new NCIB for each of our Series D and Series E Debentures, our
common shares and for each series of the preferred shares of APPEL, our wholly-owned subsidiary. Under the NCIBs,
our broker may purchase up to 10% of the public float of our convertible debentures and common shares and up to 10%
of the public float of APPEL’s preferred shares, determined as of December 17, 2018, up to the following limits:
Convertible Debenture
Convertible Debenture
Common Shares
Series 1 Preferred Shares
Series 2 Preferred Shares
Series 3 Preferred Shares
Maturity
Date
December 2019
January 2025
Interest
Rates
Limit on Purchase
(Principal Amount)
Total Limit
6.00 % Cdn$
6.00 % Cdn$
2,473,800
11,500,000
Limit on Purchase
(Number of Shares)
Total Limit (1)
10,623,464
427,500
233,109
148,311
(1) Represented 10% of the public float for the Common Shares and 10% of the public float for the Preferred Shares.
The NCIBs commenced on December 31, 2018 and will expire on December 30, 2019 or such earlier date as
the Company and/or APPEL complete their respective purchases pursuant to the NCIBs. In certain circumstances, we
may be required to suspend the NCIBs under applicable law. From December 31, 2018 through February 27, 2019, we
purchased the maximum limit of 427,500 shares of Series 1 Preferred Shares, 27,777 of Series 2 Preferred Shares and
the maximum limit of 148,311 Series 3 Preferred Shares at a total cost of Cdn$9.2 million. During the same period, we
also repurchased and cancelled 44,390 common 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 United States Securities
Exchange Act of 1934, 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.
Corporate Debt Service Obligations
The following table summarizes the maturities of our corporate debt at December 31, 2018:
Maturity
Date
Interest
Rates
Principal
Repayments 2019
Remaining
2020
2021
2022
2023
Thereafter
Senior secured term loan
facility(1)
MTNs
Convertible Debenture
Convertible Debenture
Total Corporate Debt
April 2023
June 2036
December 2019
January 2025
4.17% - 5.09% $
5.95%
6.00%
6.00%
450.0 $ 65.0 $ 105.0 $ 80.0 $ 75.0 $ 125.0 $
153.9
18.1
84.3
—
18.1
—
—
—
—
—
—
—
—
—
—
—
—
—
$
706.3 $ 83.1 $ 105.0 $ 80.0 $ 75.0 $ 125.0 $
—
153.9
—
84.3
238.2
(1) The Credit Facility contains a mandatory amortization feature determined by using the greater of (i) 50% of the cash
flow of APLP Holdings Limited Partnership (“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
67
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 Loans 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. The amortization profile in the table above is based on principal payments according
to the targeted principal amount described in (ii) above.
Credit Facilities
On April 13, 2016, APLP Holdings Limited Partnership (“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 Loans”) and $200 million in aggregate principal amount of senior secured
credit facilities (the “Revolver” and together with the Term Loans, the “Credit Facilities”). At December 31, 2018,
$450.0 million of the Term Loans is outstanding and letters of credit in an aggregate face amount of $76.9 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%. The LIBOR floor remains at 1.00%. We also extended the maturity date of the Revolver by one year through
April 2022. The Term Loans mature in April 2023.
The Term Loans include 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
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 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.
68
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 5.50:1.00 at December 2017 to 4.25:1.00 from June 30, 2020, and an
Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 3.00:1.00 at December 31, 2017 to 4.00:1.00
from June 30, 2022. 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 loans under the Credit Facilities, it will be required to offer
each electing lender a prepayment of such lender’s term loans 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 facilities 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
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 Loans 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.
Project-Level Debt Service Obligations
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
69
share of the non-recourse project-level debt balances at December 31, 2018. 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. 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.
Non-Recourse Debt
The range of interest rates presented represents the rates in effect at December 31, 2018. 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 2019 2020
2021 2022 2023
Thereafter
Consolidated Projects:
Cadillac
Total Consolidated Projects
Equity Method Projects:
Chambers(1)
Total Equity Method Projects
Total Project-Level Debt
August 2025 6.10 % - 6.34 % $
December 2019
and 2023
4.50 % - 5.00 %
$
21.0 $ 3.1 $ 3.1 $ 2.7 $ 3.3 $ 3.3 $
3.3
21.0
3.1
3.1
3.3
2.7
8.8 10.1 10.1
42.9
42.9
8.8 10.1 10.1
63.9 $ 8.3 $ 10.9 $ 11.5 $ 13.4 $ 13.4 $
5.2
5.2
7.8
7.8
5.5
5.5
0.9
0.9
6.4
(1)
In June 2014, Chambers refinanced its project debt and issued (i) Series A (tax exempt) Bonds due December 2023,
of which our proportionate share is $41.3 million, and (ii) Series B (taxable) Bonds due December 2019, of which
our proportionate share is $1.6 million. The above table does not include our $4.2 million proportionate share of
issuance premiums.
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 at the annual rate of Cdn$1.2125 per share. Beginning on June 30, 2012, the Series 1 Shares
were redeemable by the subsidiary company at Cdn$26.00 per share, declining by Cdn$0.25 each year to Cdn$25.00 per
share on or after June 30, 2016, plus, in each case, an amount equal to all accrued and unpaid dividends thereon.
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 pay fixed cumulative dividends of Cdn$1.75 per share per annum, as and when declared, for the initial five-year
period ending December 31, 2014. The dividend rate was reset on December 31, 2014 and will reset every five years
thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.18%. On
December 31, 2014 and on December 31 every five years thereafter, the Series 2 Shares were and will be redeemable by
the subsidiary company at Cdn$25.00 per share, plus an amount equal to all declared and unpaid dividends thereon to,
but excluding the date fixed for redemption. The holders of the Series 2 Shares had and will have the right to convert
their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the “Series 3 Shares”) of the subsidiary, subject to
certain conditions, on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 3
Shares will be entitled to receive quarterly floating rate cumulative 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%. On December 31, 2014, 1,661,906 of Series 2 shares were converted to Series 3 shares.
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
70
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 $8.3 million and $8.7 million on Series 1 Shares, Series 2
Shares and Series 3 Shares for the years ended December 31, 2018 and 2017, respectively.
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 expect to reinvest approximately $24.3 million in 2019 in our portfolio in the form of project capital
expenditures and maintenance expenses. 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 2019 level as a result of the
timing of more infrequent events such as steam turbine overhauls and/or gas turbine and hydroelectric turbine upgrades.
We invested approximately $35.2 million of project capital expenditures and maintenance expenses for the year
ended December 31, 2018. In all cases, scheduled maintenance outages during the year ended December 31, 2018
occurred at such times that did not adversely impact the facilities’ availability requirements under their respective PPAs.
Restricted Cash
At December 31, 2018, restricted cash totaled $2.1 million as compared to $6.2 million as of December 31,
2017.
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual obligations as of December 31, 2018:
Long-term debt including estimated interest(1)
Operating 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
$ 125.4 $ 251.1 $ 246.3 $
0.6
0.4
7.5
1.6
0.6
0.8
8.4
0.3
0.4
0.3
5.1
—
$ 135.5 $ 261.2 $ 252.1 $
368.4 $ 991.2
1.6
1.5
21.0
5.9
372.4 $ 1,021.2
—
—
—
4.0
(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, 2018 was 4.17% to
6.37%.
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
71
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, 2018, 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.
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 annually or 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
72
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 could have a material adverse
effect on our business, results of operations and financial condition”.
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. We also recorded
long-lived asset impairments of $3.8 million and $2.1 million, respectively, at our North Bay and Kapuskasing reporting
units in the year ended December 31, 2016. See Item 15 — Note 8, Goodwill and long-lived asset impairment 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
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 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
73
industry conditions, market events and circumstances as well as the overall financial performance of our reporting units.
For our 2018 test, we performed qualitative assessments at our Morris and Nipigon reporting units. We performed
quantitative tests these reporting units in the years ended December 31, 2017 and 2016.
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 test conducted at November 30, 2017.
We determine the fair value of our reporting units using an income approach with discounted cash flow
(“DCF”) models, 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 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 betas
used in calculating the WACC rate were obtained from reputable third party sources. We utilized the assistance of
valuation experts to perform quantitative impairment tests for several of our reporting units. The fair value that could be
realized in an actual transaction may differ from that used to evaluate the impairment of goodwill.
We did not record any goodwill impairments in 2018. We previously recorded a goodwill impairment of $14.7
million at our Curtis Palmer reporting unit in the year ended December 31, 2017. We also recorded goodwill
impairments of $50.2 million, $15.4 million, $6.7 million, $6.5 million and $1.2 million, respectively, at our Mamquam,
Curtis Palmer, Kapuskasing, North Bay and Moresby Lake reporting units in the year ended December 31, 2016. See
Item 15 — Note 9, Goodwill and long-lived asset impairment for discussion of these impairments.
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
74
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.
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, 2018, we have recorded a valuation
allowance of $139.7 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 for additional information.
75
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 profitability 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.
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 2022. These contracts are accounted for as derivative
financial instruments and are recorded in the consolidated balance sheet at fair value at December 31, 2018. 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 2022.
Nipigon operates under a long-term enhanced dispatch agreement through December 2022. Under the terms of
the agreement, the project resells its contracted firm fixed price gas at market prices and credits the proceeds to a savings
pool shared by Nipigon and the offtaker. As a result of selling the gas at market prices, Nipigon is exposed to changes in
the price of natural gas. A $1.00/GJ change in the price of natural gas would have a $1.2 million impact on Nipigon
based on planned 2019 natural gas sales.
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 Cadillac project does not have a long-term biomass fuel contract. A 10% per Ton change from our
budgeted wood waste cost at Cadillac would have an estimated $0.2 million total impact on forecasted cash distributions
in 2019 based on planned operations.
Our Piedmont project does not have a long-term biomass fuel contract. A 10% per Ton change from our
budgeted wood waste cost at Piedmont would have an estimated $1.2 million total impact on forecasted cash
distributions in 2019 based on planned operations.
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 2019. 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 2019 based on planned operations.
76
Our Williams Lake project does not have a long-term biomass fuel contract. A 10% per Ton change from our
budgeted wood waste cost at Williams Lake would have an estimated $0.5 million total impact on forecasted cash
distributions in 2019 based on planned operations.
Coal
Our 40%-owned Chambers project is exposed to changes in coal prices. For 2019, we forecasted an average
coal price of $98 per Ton. A 10% change from our forecasted price would impact cash distributions from Chambers by
an estimated $1.2 million for 2019 based on planned operations.
Electricity Commodity Market Risk
Our current and future cash flows are impacted by changes in electricity prices when our projects operate with
no PPA or at projects that operate with PPAs that are based on spot market pricing. Our most significant exposure to
market power prices is at the Chambers and Morris projects.
At our 40%-owned Chambers project, plant capacity is sold forward pursuant to the power purchase agreement
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 2019, projected cash distributions from Chambers would change by
approximately $0.7 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 2019, projected cash
distributions from Morris would change by approximately $0.6 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 senior secured term loans 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.
77
The following table contains the components of recorded foreign exchange (gain) loss for the years ended
December 31, 2018, 2017, and 2016:
Year Ended December 31,
2017
2016
2018
Unrealized foreign exchange (gain) loss:
Convertible debentures, corporate debt, and other
Foreign currency forwards
Realized foreign exchange loss (gain)
$
$
(22.2) $
0.1
(22.1)
(0.7)
(22.8) $
15.1 $
0.1
15.2
1.1
16.3 $
13.8
—
13.8
0.1
13.9
A 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar would have a $25.6
million impact on the carrying value of our corporate debt and convertible debentures denominated in Canadian dollars
at December 31, 2018.
Interest Rate Risk
Changes in interest rates impact cash payments that are required on our debt instruments as approximately 96%
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 $0.3 million at
December 31, 2018.
The Partnership
APLP Holdings has entered into several interest rate swap agreements to mitigate its exposure to changes in the
Adjusted Eurodollar Rate. At December 31, 2018, these agreements totaled $421.5 million notional amount of the
remaining $450.0 million aggregate principal amount of borrowings under the senior secured term loan facility. These
interest rate swap agreements expire at various dates through March 31, 2020. Borrowings under the Term Loan Facility
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 Facility for the non-swapped portion of the remaining principal amount. The weighted average
rate of these swap agreements is 1.27%, resulting in an all-in rate of approximately 4.02% for $421.5 million of the
Term Loan Facility. In January 2018, APLP Holdings entered into additional interest rate swap agreements. For the
period beginning September 30, 2018 through September 30, 2019, we mitigated exposure to changes in interest rates
for $100 million notional amount at a one-month LIBOR fixed rate of 2.18% and for the period beginning October 1,
2019 through December 31, 2020, for $200 million notional amount at a one-month LIBOR fixed rate of 2.42%.
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
78
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.
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, 2018 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, 2018 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, 2018 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 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, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over
financial reporting.
79
ITEM 9B. OTHER INFORMATION
None.
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.
EXHIBIT INDEX
Description
Plan of Arrangement of Atlantic Power Corporation, dated as of November 24, 2005
2.1
2.2 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
3.1 Articles of Continuance of Atlantic Power Corporation, dated as of June 29, 2010
4.1
4.2
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
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
81
Exhibit
No.
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
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
4.19 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
4.20
4.21 Advance Notice Policy, dated April 1, 2013
10.1 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
10.2
10.3 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
10.4 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.
Description
10.5 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
10.6+
10.7+ Addendum to Executive Employment Agreements of each of Terrence Ronan and Edward Hall, dated
August 30, 2013
10.8+ Deferred Share Unit Plan, dated as of April 24, 2007 of Atlantic Power Corporation
10.9+
10.10+
10.11+
10.12+ Amendment No. 1 to the Fifth Amended and Restated Long-Term Incentive Plan of the Company
Third Amended and Restated Long-Term Incentive Plan
Fourth Amended and Restated Long-Term Incentive Plan
Fifth Amended and Restated Long-Term Incentive Plan
10.13
10.14
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)
10.15 Agreement dated November 24, 2014, by and among Clinton Group and the Company
10.16+
10.17+
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
10.18 Membership Interest Purchase Agreement by and between Atlantic Power Transmission, Inc. and Terraform
AP Acquisition Holdings, LLC dated as of March 31, 2015
10.19 Guaranty Agreement by Atlantic Power Corporation in favor of Terraform AP Acquisition Holdings, LLC,
dated as of March 31, 2015
10.20 Agreement dated May 21, 2015, by and among Mangrove Partners and the Company
10.21 Amendment No.1 to Membership Interest Purchase Agreement, dated June 3, 2015
10.22+
Employment Agreement among the Company, Atlantic Power Services, LLC and Joseph E. Cofelice, dated
September 15, 2015
10.23 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
10.24
83
Description
Exhibit
No.
10.25 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
10.26
10.27 Amendment to Employment Agreement, by and among Atlantic Power Services, LLC, the Company and
Joseph Cofelice, dated as of February 27, 2018
10.28 Amendment No. 2 to the Fifth Amended and Restated Long-Term Incentive Plan of the Company
10.29*+ Sixth Amended and Restated Long-Term Incentive Plan
10.30*+ Amendment to Transition Equity Grant Participation Agreement between Atlantic Power Services, LLC and
James J. Moore, Jr., dated as of January 23, 2019
10.31*+ Form of Legacy Award Amendment
16.1
Letter from KPMG LLP, Chartered Accountants, to the Securities and Exchange Commission, dated
August 10, 2010
Subsidiaries of Atlantic Power Corporation
21.1*
23.1* Consent of KPMG LLP
31.1* Certification of Chief Executive Officer pursuant to Rule 13a- 14(a)/15d-14(a) under the Exchange Act
31.2* Certification of Chief Financial Officer pursuant to Rule 13a- 14(a)/15d-14(a) under the Exchange Act
32.1** 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
32.2** Certification of the Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906
101*
of the Sarbanes-Oxley Act of 2002
The following materials from our Annual Report on Form 10-K for the year ended December 31, 2018
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.
84
(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 28, 2019
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 28, 2019
(principal executive officer)
/s/ TERRENCE RONAN
Terrence Ronan
Chief Financial Officer (Duly Authorized
Officer and Principal Financial and Accounting Officer)
February 28, 2019
/s/ IRVING R. GERSTEIN
Irving R. Gerstein
Chairman of the Board
/s/ R. FOSTER DUNCAN
R. Foster Duncan
Director
/s/ KEVIN T. HOWELL
Kevin T. Howell
Director
/s/ DANIELLE S. MOTTOR
Danielle S. Mottor
Director
/s/ GILBERT S. PALTER
Gilbert S. Palter
Director
February 28, 2019
February 28, 2019
February 28, 2019
February 28, 2019
February 28, 2019
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 Income (Loss)
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-62
F-66
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, 2018 and 2017, and the related consolidated statements of operations, comprehensive
income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31,
2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in
the three-year period ended December 31, 2018, 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, 2018, based on criteria
established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations
of the Treadway Commission, and our report dated February 28, 2019 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 audit 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 28, 2019
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, 2018, 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, 2018, 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, 2018 and 2017, the related consolidated statements of
operations, comprehensive income (loss), shareholders' equity, and cash flows for each of the years in the three-year period ended
December 31, 2018, and the related notes and financial statement schedules I to II (collectively, the consolidated financial statements)
and our report dated February 28, 2019 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.
Definitions 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 28, 2019
F-3
ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of U.S. dollars)
December 31,
2018
2017
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Current portion of derivative instruments asset (Notes 14 and 15)
Inventory (Note 7)
Prepayments
Income taxes receivable
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)
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)
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)
Other long-term liabilities (Note 11)
Total liabilities
Equity
Common shares, no par value, unlimited authorized shares; 108,341,738 and 115,211,976
issued and outstanding at December 31, 2018 and December 31, 2017
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
$
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
6.2
78.7
6.2
52.7
2.7
17.7
6.9
1.0
3.1
169.0
602.3
163.7
191.2
21.3
2.8
8.5
$ 1,024.5 $ 1,158.8
$
2.5 $
2.3
20.2
68.1
4.5
18.1
0.2
115.9
540.7
75.7
15.4
9.0
21.2
49.2
5.0
832.1
2.2
0.3
25.5
99.5
4.4
—
1.0
132.9
616.3
105.4
19.9
11.7
24.1
45.3
6.4
962.0
1,260.9
(146.2)
(1,121.6)
(6.9)
199.3
192.4
1,274.8
(134.8)
(1,158.4)
(18.4)
215.2
196.8
$ 1,024.5 $ 1,158.8
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions of U.S. dollars, except per share amounts)
Year Ended December 31,
2017
2018
2016
$
130.9 $ 148.9 $ 184.2
141.9
105.8
73.1
176.3
399.2
431.0
97.9
53.5
282.3
73.1
85.0
83.7
241.8
106.3
87.8
113.1
307.2
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)
149.5
105.2
113.5
368.2
37.9
35.9
(9.2)
(85.9)
0.4
(20.9)
10.1
23.9
52.7
(22.8)
(3.0)
50.8
37.4
0.2
37.2
0.4
36.8 $
23.6
64.2
16.3
(0.4)
103.7
(151.1)
(58.1)
(93.0)
5.6
22.6
106.0
13.9
(3.9)
138.6
(128.5)
(14.6)
(113.9)
8.5
(98.6) $ (122.4)
0.33 $ (0.86) $
0.29
(0.86)
(1.02)
(1.02)
112.0
141.8
115.1
115.1
119.5
119.5
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 earnings (loss) of unconsolidated affiliates (Note 6)
Interest, net
Impairment (Notes 8 and 9)
Other income, net (Notes 3 and 11)
Project income (loss)
Administrative and other expenses:
Administration
Interest expense, net
Foreign exchange (gain) loss
Other income, net (Note 14)
Income (loss) from operations before income taxes
Income tax expense (benefit) (Note 16)
Net income (loss)
Net income attributable to preferred shares of a subsidiary company (Note 20)
Net income (loss) attributable to Atlantic Power Corporation
Net earnings (loss) per share attributable to Atlantic Power Corporation
shareholders: (Note 21)
Basic
Diluted
Weighted average number of common shares outstanding: (Note 21)
Basic
Diluted
$
$
See accompanying notes to consolidated financial statements.
F-5
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions of U.S. dollars)
Net income (loss)
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on hedging activities
Net amount reclassified to earnings
Net unrealized gain on derivatives
Defined benefit plan, net of tax
Foreign currency translation adjustments
Other comprehensive (loss) income, net of tax
Comprehensive income (loss)
Less: Comprehensive income attributable to preferred shares of a subsidiary
company
Comprehensive income (loss) attributable to Atlantic Power Corporation
$
$
2018
Year Ended December 31,
2017
(93.0) $ (113.9)
37.2 $
2016
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)
(0.2)
0.7
0.5
(0.5)
(9.2)
(9.2)
(123.1)
0.4
25.4 $
5.6
8.5
(84.9) $ (131.6)
$
See accompanying notes to consolidated financial statements.
F-6
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in millions of U.S. dollars)
December 31, 2015
Net (loss) income
Common shares issued for LTIP
Dividends declared on preferred shares of a
subsidiary company
Common share repurchases
Unrealized gain on hedging activities, net of tax of
$0.2 million
Foreign currency translation adjustments
Defined benefit plan, net of tax of $0.2 million
December 31, 2016
Net (loss) income
Common shares issued for LTIP
Dividends declared on preferred shares of a
subsidiary company
Common share repurchases
Preferred share repurchases
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
December 31, 2017
Net income
Common shares issued for LTIP
Dividends declared on preferred shares of a
subsidiary company
Common share repurchases
Preferred share repurchases
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
December 31, 2018
Common
Shares
(Shares)
Common
Shares
(Amount)
122.1 $ 1,290.6 $
—
0.5
—
(8.0)
—
1.8
—
(19.5)
Other
Accumulated
Preferred
Shares of a
Comprehensive Subsidiary
Company
Income (loss)
Total
Shareholders’
Equity
(139.3) $
—
—
221.3 $
8.5
—
435.2
(113.9)
1.8
Retained
Deficit
(937.4) $
(122.4)
—
—
—
—
—
(8.5)
—
—
—
—
—
—
—
114.6 $ 1,272.9 $ (1,059.8) $
—
2.1
(98.6)
—
—
—
—
—
0.7
0.5
(9.2)
(0.5)
(148.5) $
—
—
—
—
—
221.3 $
5.6
—
—
(0.1)
—
—
(0.2)
—
—
—
—
—
—
—
(8.6)
—
(3.1)
—
—
—
—
—
—
115.2 $ 1,274.8 $ (1,158.4) $
—
2.7
—
—
—
36.8
—
—
0.9
0.4
14.0
(0.7)
(134.8) $
—
—
—
—
—
215.2 $
0.4
—
—
(7.8)
—
—
(16.6)
—
—
—
—
—
—
—
(8.3)
—
(8.0)
—
—
—
—
—
—
108.3 $ 1,260.9 $ (1,121.6) $
—
—
—
0.5
(12.1)
0.2
(146.2) $
—
—
—
199.3 $
(8.5)
(19.5)
0.5
(9.2)
(0.5)
285.9
(93.0)
2.1
(8.6)
(0.2)
(3.1)
0.4
14.0
(0.7)
196.8
37.2
2.7
(8.3)
(16.6)
(8.0)
0.5
(12.1)
0.2
192.4
See accompanying notes to consolidated financial statements.
F-7
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of U.S. dollars)
Years Ended December 31,
2017
2016
2018
Cash provided by operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
$
37.2
$
(93.0)
$
(113.9)
Depreciation and amortization
(Gain) loss on disposal of fixed assets and inventory
Asset retirement obligations
Gain on purchase and cancellation of convertible debentures
Gain on step acquisition of equity investment
Share-based compensation
Long-lived asset and goodwill impairment
Equity in (earnings) loss from unconsolidated affiliates
Distributions from unconsolidated affiliates
Unrealized foreign exchange (gain) loss
Change in fair value of derivative instruments
Amortization of debt discount and deferred financing costs
Change in 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:
Proceeds from sale of assets and equity investments, net
Cash paid for acquisition, net of cash received
Reimbursement of costs for third party construction project
Deposit for acquisition
Proceeds from asset sales
Purchase of property, plant and equipment
Cash used in investing activities
Cash used in financing activities:
Proceeds from convertible debenture issuance
Proceeds from term loan facility, net of discount
Repayment of convertible debentures
Common share repurchases
Preferred share repurchases
Repayment of corporate and project-level debt
Cash payments for vested LTIP units withheld for taxes
Deferred financing costs
Dividends paid to preferred shareholders
Cash used in financing activities:
Net (decrease) increase 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
(Receivables) accruals for equipment sales and construction in progress
$
$
$
$
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
$
$
$
$
113.5
—
—
(3.7)
—
1.8
85.9
(35.9)
55.3
13.8
(37.9)
44.6
(17.5)
2.3
0.9
5.4
(0.2)
(2.1)
112.3
—
—
4.8
—
—
(7.2)
(2.4)
—
679.0
(188.5)
(19.5)
—
(544.4)
(0.5)
(16.2)
(8.5)
(98.6)
11.3
87.6
98.9
70.7
3.5
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 nine 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,
2018, our portfolio consisted of seventeen projects operating or under contract with an aggregate electric generating
capacity of approximately 1,598 megawatts (“MW”) on a gross ownership basis and approximately 1,252 MW on a net
ownership basis. Fourteen of the projects are majority-owned by the Company. Two of our Ontario projects totaling 80
MW on a gross and net ownership basis have not operated since the expiration of their contracts on December 31, 2017.
In early February 2018, our three plants in San Diego, totaling 112 MW on a gross and net ownership basis, ceased
operations and will be decommissioned.
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 355 Burrard Street, Suite 1900, Vancouver, British Columbia V6C 2G8 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 and cash equivalents that are maintained by the projects or corporate to support
payments for maintenance costs and meet project level and corporate contractual debt obligations. Restricted cash is
F-9
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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.
(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,
2018 and 2017, 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 $11.8 million and $11.7 million at December 31, 2018 and 2017, respectively. Interest expense from the
amortization of deferred finance costs for the years ended December 31, 2018, 2017, and 2016 was $5.1 million,
$6.3 million, and $40.8 million, respectively.
(f)
Inventory:
Inventory represents small parts and other consumables and fuel, 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)
Other intangible assets:
Other intangible assets include PPAs and fuel supply agreements at our projects acquired as part of business
combinations. PPAs are valued at the time of acquisition based on the contract prices under the PPAs compared to
projected market prices. Fuel supply agreements are valued at the time of acquisition based on the contract prices under
the fuel supply agreement compared to projected market prices. 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 annually or 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.
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. 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. 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
F-11
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 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.
(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 in the fourth quarter, or more frequently if
events or changes in circumstances indicate that the asset might be impaired.
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 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 utilized 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 betas used in calculating the WACC rate were obtained from reputable third party
sources. We utilized the assistance of valuation experts to perform the quantitative impairment test for our Curtis Palmer
reporting units. The fair value that could be realized in an actual transaction may differ from that used to evaluate the
impairment of goodwill.
The valuation of long-lived assets 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.
F-12
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
As a result, there can be no assurance that the estimates and assumptions made for purposes of a goodwill 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
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 such 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 (“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, net
Foreign exchange (gain) loss
NA
Foreign exchange (gain) loss
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 June 30, 2019 to March 31, 2037,
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 Canada segment. Waste heat is earned when it is generated and paid as a portion of monthly
energy and capacity billing.
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
Enhanced dispatch
contracts
Ancillary and
transmission services
Asset management
and operation,
operation and
maintenance
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.
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.
Finance income related to leases or arrangements accounted for as direct financing 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 income (loss) over the lease term.
For PPAs accounted for as operating leases, we recognize lease income consistent with the recognition of
energy revenue. When energy is delivered, we recognize lease income in energy revenue.
F-15
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(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.
(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”).
Vested notional units are expected to be redeemed one-third in cash and two-thirds in shares of our common stock.
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 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)
Pensions:
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 income (loss). In addition, we also recognize on an after-tax basis, as a component of
other comprehensive income (loss), gains and losses as well as all prior service costs that have not been included as part
F-16
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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.
(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. 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 2018
In May 2017, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance to address
diversity in practice and cost and complexity of applying the guidance relating to stock compensation when there is a
change to the terms or conditions of a share-based payment award. The guidance is effective for fiscal years beginning
after December 15, 2017, with early adoption permitted. We adopted this guidance on January 1, 2018 and it did not
F-17
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
have an impact on the consolidated financial statements.
In November 2016, the FASB issued authoritative guidance to address diversity in practice of presenting
changes in restricted cash on the statement of cash flows. The new guidance requires that a statement of cash flows
explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted
cash or restricted cash equivalents. We adopted this guidance on January 1, 2018 and it was applied retrospectively to
cash flows used in investing activities on the consolidated statements of cash flows for the years ended December 31,
2017 and 2016. As a result of adoption, cash flows used in investing activities were retrospectively decreased by $7.1
million and $1.9 million for the years ended December 31, 2017 and 2016, respectively.
In October 2016, the FASB issued authoritative guidance, which amends existing guidance related to the
recognition of current and deferred income taxes for intra-entity asset transfers. Under the new guidance, current and
deferred income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory,
are now recognized when the transfer occurs. We adopted this guidance on January 1, 2018 and it did not have an impact
on the consolidated financial statements.
In August 2016, the FASB issued authoritative guidance intended to clarify classification of specific cash flows
that have aspects of more than one class of cash flows. As a result of this new guidance, entities should be applying
specific GAAP in the following eight cash flow issues: Debt prepayment or debt extinguishment costs; settlement of
zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the
effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds
from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies;
distributions received from equity method investees; beneficial interests in securitization transactions; and separately
identifiable cash flows and application of the predominance principle. We adopted this guidance on January 1, 2018 and
it did not have an impact on the consolidated financial statements.
In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with
customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on
when the customer obtains control of the goods or services, rather than the current risks and rewards model of
recognition. The core principle of the new standard is that an entity recognizes revenue when it transfers goods or
services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or
services. We adopted this guidance on January 1, 2018 and it did not have an impact on the consolidated financial
statements. Accordingly, we did not record a transition adjustment. The standard also requires new disclosures that
include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows
from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the
costs to obtain or fulfill a contract. These disclosures can be found in Note 4 Revenue from contracts.
Accounting Standards Not Yet Adopted
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 will be 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 will require 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 expire before the initial application date will not require any accounting adjustment. This
guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods within
those fiscal years, with early adoption permitted. We expect to elect certain practical expedients permitted, including the
expedient that permits us to retain our existing lease assessment and classification. In July 2018, the FASB issued further
F-18
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 adjustments to the opening balance of
retained earnings in the period of adoption. We will elect this transition method. We are currently finalizing our adoption
process, which includes the evaluation of lease contracts compared to the new standard. While we are currently
completing our evaluation of the impact of the new guidance, we expect to record a right of use asset of approximately
$6.5 million, a lease liability of approximately $7.1 million and an adjustment to other assets of approximately $0.6
million in the consolidated balance sheets on January 1, 2019. We do not expect adoption to impact opening retained
earnings or our consolidated statements of operations.
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 is effective for fiscal years
beginning after December 15, 2018, with early adoption permitted. Adoption of this guidance will not have a material
impact on 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 is effective for fiscal years beginning after December 15, 2018. Adoption of this guidance will not have a
material impact on the 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.
3. Acquisitions and divestments
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 is
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
F-19
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 preliminary 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
Preliminary 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
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,
2018, 2017 and 2016.
(b)
South Carolina Biomass Plants
On September 20, 2018, we executed an agreement to acquire two biomass plants in South Carolina from EDF
Renewables for $13.0 million. Closing of the transaction is expected to occur late in the third quarter or in the fourth
quarter of 2019, subject to restructuring of the plants’ ownership structure by EDF Renewables after the end of relevant
tax credit recapture periods. We have paid $2.6 million of the purchase price, which will be held in escrow until the
F-20
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
closing date. The remainder of the purchase price will be paid at closing.
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. Under the terms of the PPAs, the plants receive energy payments for
energy produced. The fuel cost component of the energy revenues is based on a biomass market index. There is no
project-level debt at either plant.
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
Enhanced dispatch contracts
Ancillary and transmission services
Asset management and operation
Miscellaneous revenue
Year Ended December 31, 2018
East U.S.
West U.S.
Canada
Un-Allocated Consolidated
Corporate
Total
$
87.5 $
52.8
12.9
—
—
5.5
—
—
158.7
13.5 $
27.8
2.8
—
—
—
—
(0.3)
43.8
29.9 $
17.3
—
0.3
23.9
7.5
—
—
78.9
— $
—
—
—
—
—
0.9
—
0.9
130.9
97.9
15.7
0.3
23.9
13.0
0.9
(0.3)
282.3
F-21
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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
Contract balances
Year Ended December 31, 2017
Un-Allocated Consolidated
East U.S. West U.S. Canada Corporate
Total
$
87.3 $
49.4
11.1
—
—
—
4.7
—
152.5
33.0 $ 28.6 $
45.6
31.2
—
—
—
—
(0.9)
108.9
10.8
—
0.5
109.9
18.8
—
—
168.6
— $
—
—
—
—
—
1.0
—
1.0
148.9
105.8
42.3
0.5
109.9
18.8
5.7
(0.9)
431.0
The following table provides information about receivables, contract assets and contract liabilities from
contracts with customers.
Accounts receivables
Contract assets
Contract liabilities
December 31,
December 31,
2018
2017
$
35.7 $
—
0.1
52.7
—
1.0
Contract liabilities as of December 31, 2018 include a $0.1 million steam sale credit at San Diego plants.
Contract liabilities as of December 31, 2017 include recoverable wood fuel costs under the PPA and property tax at
Williams Lake, which is proportionally estimated, pending receipt of an actual tax bill. The total $1.0 million was
recognized as revenues from ancillary and transmission services in the first quarter of 2018.
F-22
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 loss by component
The changes in accumulated OCL by component are as follows:
Foreign currency translation
Balance at beginning of period
Other comprehensive loss:
Foreign currency translation adjustments(1)
Balance at end of period
Pension
Balance at beginning of period
Other comprehensive loss:
Curtailment gain
Tax expense
Total Other comprehensive income before reclassifications, net of tax
Total amount reclassified from accumulated other comprehensive income,
net of tax
Total other comprehensive income
Balance at end of period
Cash flow hedges
Balance at beginning of period
Other comprehensive income (loss):
Net change from periodic revaluations
Tax (expense) benefit
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 loss,
net of tax
Total other comprehensive income
Balance at end of period
$
Year Ended December 31,
2017
2018
2016
$ (134.3) $ (148.3)
$ (139.1)
(12.1)
14.0
$ (146.4) $ (134.3)
(9.2)
$ (148.3)
$
(1.6) $
(0.9)
$
(0.4)
—
—
—
0.2
0.2
(1.4) $
$
(1.6)
0.4
(1.2)
0.5
(0.7)
(1.6)
$
1.1 $
0.7
0.5
(0.1)
(0.2)
0.1
0.4
(0.1)
0.2
(0.1)
0.1
0.5
1.6 $
0.9
(0.4)
0.5
0.4
1.1
(0.7)
0.2
(0.5)
—
(0.5)
(0.9)
0.2
(0.3)
0.1
(0.2)
1.0
(0.3)
0.7
0.5
0.7
$
$
$
(1)
In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to
earnings (loss).
(2) This amount was included in interest expense, net on the accompanying consolidated statements of operations.
F-23
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
Koma Kulshan Associates (2)
Chambers Cogen, LP
Total
Percentage of
Ownership as of
December 31, 2018
Carrying value as of
December 31,
2018
50.2 % $ 72.0 $
50.0 %
— %
40.0 %
2017
77.3
7.0
4.9
74.5
$ 140.8 $ 163.7
4.5
—
64.3
(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 July 2018, we purchased the remaining 50% partnership interest in Koma and consolidated the project in our
financial statements. See Note 3 Acquisition 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)
Total earnings (loss) of unconsolidated affiliates
Distributions from equity method investments
Deficit in earnings of equity method investments, net of
distributions
$
2018
2016
6.9 $
Year Ended December 31,
2017
(27.9) $
25.6
0.7
(42.6)
(10.6)
(54.8)
(47.3)
30.1
0.6
5.6
—
43.2
(61.6)
2.2
27.8
0.8
5.5
(0.4)
35.9
(55.3)
$ (18.4) $ (102.1) $ (19.4)
(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 Acquisition and divestments.
In November 2017, we sold our 17.7% interest in Selkirk.
Distributions from equity method investments exceeded earnings (loss) of equity method investments for the
years ended December 31, 2018, 2017 and 2016, 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.
F-24
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following summarizes the financial position at December 31, 2018, 2017 and 2016, and operating results
for the years ended December 31, 2018, 2017 and 2016, respectively, for our proportional ownership interest in equity
method investments:
Assets
Current assets
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Non-current assets
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Liabilities
Current liabilities
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Non-current liabilities
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
2018
2017
2016
$
2.5 $
7.7
—
15.6
—
1.9 $
9.2
0.5
17.3
—
1.7
7.5
0.6
15.0
11.3
70.0
7.1
—
117.4
—
220.3 $
76.2
8.1
4.7
130.9
—
248.8 $
114.1
9.1
5.0
190.0
2.4
356.7
$
$
— $
10.3
—
9.2
—
0.5
—
—
59.5
—
79.5 $
$
0.4 $
10.3
0.1
3.7
—
0.4
—
0.2
70.0
—
85.1 $
0.1
9.2
0.1
3.8
0.6
0.5
—
0.5
73.6
1.5
89.9
(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 Acquisition and divestments.
In November 2017, we sold our 17.7% interest in Selkirk.
F-25
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)
Project expenses
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Project other expense
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Project income (loss)
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates (1)
Chambers Cogen, LP
Selkirk Cogen Partners, LP (2)
Equity in earnings (loss) of unconsolidated affiliates
2018
2017
2016
$ 21.0 $ 21.6 $ 20.7
54.6
1.9
44.7
7.9
129.8
55.0
1.8
43.8
1.8
124.0
60.2
1.2
43.3
—
125.7
14.1
30.1
0.6
36.1
—
80.9
21.0
29.4
1.1
37.5
2.8
91.8
—
—
—
(1.6)
—
(1.6)
(28.4)
—
—
(48.9)
(9.7)
(87.0)
18.5
26.9
1.1
37.4
8.2
92.1
—
—
—
(1.8)
—
(1.8)
6.9
30.1
0.6
5.6
—
2.2
27.7
0.8
5.5
(0.3)
$ 43.2 $ (54.8) $ 35.9
(27.8)
25.6
0.7
(42.6)
(10.7)
(1)
(2)
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 Acquisition and divestments.
In November 2017, we sold our 17.7% interest in Selkirk.
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 no
impairment tests were performed on equity method investments.
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.
F-26
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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
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
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 $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 Pennsylvania
New Jersey Maryland (“PJM”), the region where Chambers operates, 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.
F-27
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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.
7. Inventory
Inventory consists of the following:
Parts and other consumables
Fuel
Total inventory
8. Property, plant and equipment, net
December 31,
2018
$
$
9.6 $
6.2
15.8 $
2017
12.1
5.6
17.7
Property, plant and equipment, net consists of the following:
December 31, December 31,
Land
Office equipment, machinery and other
Leasehold improvements
Asset retirement obligation
Plant in service
$
Less accumulated depreciation
Total property, plant and equipment, net
$
2018
5.3 $
6.0
2.1
24.1
874.4
911.9
(362.4)
549.5 $
2017
5.5
6.0
2.2
28.4
942.5
984.6
(382.3)
602.3
Depreciable
Lives
3 - 10 years
7 - 15 years
1 - 43 years
1 - 45 years
Depreciation expense of $40.0 million, $83.3 million and $49.5 million, was recorded for the years ended
December 31, 2018, 2017 and 2016, respectively.
As described in Note 9, Goodwill and long-lived asset impairment, we recorded $67.6 million of long-lived
asset impairments to property, plant and equipment in the year ended December 31, 2017.
F-28
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
9. Goodwill and long-lived asset impairment
Goodwill Rollforward
The following table is a rollforward of goodwill for the years ended December 31, 2018 and 2017:
Reporting unit
Segment
2017
Impairment
December 31,
Translation
adjustment
December 31,
2018
Curtis Palmer
Morris
Nipigon
East U.S.
East U.S.
Canada
$
$
14.4 $
3.3
3.6
21.3 $
December 31,
— $
—
—
— $
— $
—
—
— $
14.4
3.3
3.6
21.3
Reporting unit
Segment
2016
Impairment
Translation
adjustment
December 31,
2017
Curtis Palmer
Morris
Nipigon
East U.S.
East U.S.
Canada
$
$
29.1 $
3.3
3.6
36.0 $
(14.7) $
—
—
(14.7) $
— $
—
—
— $
14.4
3.3
3.6
21.3
2018 – Annual test performed in fourth quarter
Goodwill
In the fourth quarter of 2018, we performed our annual goodwill impairment test as of November 30, 2018. All
reporting units with goodwill had fair values that exceeded their carrying values and accordingly, no goodwill
impairment was recorded. 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.
2018 – Event-driven test performed in fourth quarter
Williams Lake – Long-lived assets
Williams Lake operates under a PPA that expires 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
F-29
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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. Because of the judgmental aspect of estimating a potential contract extension and the near-term
expiration of our current contract, we will continue to update this analysis on a quarterly basis and could record a long-
lived asset impairment if circumstances indicate a contract extension is unlikely.
2017 – Annual test performed in fourth quarter
In the fourth quarter of 2017, we performed our annual goodwill impairment test as of November 30, 2017. Of
the 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.
Curtis Palmer - Goodwill
In applying the goodwill test, the Curtis Palmer reporting unit’s carrying value exceeded its estimated fair value
by $14.7 million at November 30, 2017. Accordingly, we recorded a $14.7 million goodwill impairment at Curtis Palmer
in 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.
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
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-
F-30
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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.
2017 – Event-driven test in the 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 use the Naval Station and North Island sites beyond February
2018. Following notification of the outcome of the Navy solicitation, we determined that it was unlikely that 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,
which represents 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.
2016 – Annual test performed in fourth quarter
In the fourth quarter of 2016, we performed our annual goodwill impairment test as of November 30, 2016. Of
the total remaining reporting units with goodwill recorded, Curtis Palmer ($29.1 million of goodwill at December 31,
2016) and Nipigon ($3.6 million of goodwill at December 31, 2016) passed step 1 of the two-step test. The total fair
value of these reporting units exceeded their carrying value by approximately $62.7 million or 45%. For our Morris
reporting unit, we performed a qualitative assessment and concluded that it was likely that the fair value significantly
exceeded the reporting unit’s carrying value. The Morris reporting unit has goodwill of $3.3 million and has a PPA with
significant remaining time before its expiration and is not significantly impacted by the decrease in the long-term
outlook for power prices.
F-31
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The Moresby Lake reporting units failed step 1 of the two-step test. Accordingly, we performed a step 2
analysis for Moresby Lake and, as a result, recorded a $1.2 million full impairment in the year ended December 31,
2016. Moresby Lake has substantial useful life beyond the expiration of its PPA in 2022. However, Moresby Lake’s fair
value is estimated using a discounted cash flow approach and is sensitive to changes in forward power prices. These
forward prices had declined significantly over the past several years. Moresby failed step 1 in our event-driven
impairment test at July 31, 2016, but recorded no impairment as its implied goodwill exceeded its recorded goodwill.
The further decline in forward power prices since our event-driven test resulted in the full impairment recorded at
November 30, 2016.
2016 – Event-driven test in the third quarter
In the third quarter of 2016, we performed an event-driven goodwill impairment test as of July 31, 2016. While
declining power prices had been observed over the past two years, we identified a significant decrease in the long-term
outlook for power prices in the regions where our reporting units operate in the third quarter of 2016. Because the
estimated future cash flows of our reporting units are sensitive to fluctuations in forward power prices and these prices
are the most impactful input in calculating a reporting unit’s fair value, we determined that it was appropriate to perform
an event-driven impairment test. For two of our reporting units (Morris and Nipigon) we performed a qualitative
assessment and concluded that it was likely that the fair values significantly exceed the carrying values. These reporting
units have aggregate goodwill of $6.9 million and have PPAs with significant remaining time before their expiration and
are not significantly impacted by the decrease in the long-term outlook for power prices.
The other five of the reporting units tested (Curtis Palmer, Mamquam, North Bay, Kapuskasing and Moresby
Lake) failed step 1 of our quantitative two-step test. Because five reporting units failed step 1 of the two-step goodwill
impairment test, we identified a triggering event and initiated a test of the recoverability of their long-lived assets. The
asset group for testing the long-lived assets for impairment is the same as the reporting unit for goodwill impairment
testing purposes. In order to test the recoverability of the assets in the asset groups, we compared the carrying amount of
the assets to estimated undiscounted future cash flows expected to be generated by the asset group. The carrying value of
each asset group includes its recorded property, plant equipment, intangible assets related to PPAs and goodwill. Of the
five asset groups tested, the North Bay and Kapuskasing asset groups (Canada segment) failed the recoverability test and
we recorded property, plant and equipment impairment charges aggregating $5.9 million for the periods ended
September 30, 2016. For these asset groups, we estimated their fair value utilizing an income approach based on market
participant assumptions. These assumptions include estimated cash flows under the remaining period of their respective
PPAs.
Subsequent to recording long-lived asset impairments, we performed the step 2 goodwill impairment test and
recorded a $50.2 million full impairment at the Mamquam reporting unit, a $15.4 million partial impairment at the Curtis
Palmer reporting unit, a $6.5 million full impairment at the North Bay reporting unit, a $6.7 million full impairment at
the Kapuskasing reporting unit and no impairment at the Moresby Lake reporting unit for a total goodwill impairment
charge of $78.8 million for the period ended September 30, 2016. At the time of their acquisition in November 2011, the
fair value of the assets acquired and liabilities assumed for the Mamquam and Curtis Palmer reporting units were valued
assuming a merchant basis for the period subsequent to the expiration of the projects’ original PPAs. The forecasted
energy revenue on a merchant basis, in the respective markets in which those plants operate, was higher than the energy
prices currently forecasted to be in effect subsequent to the expiration of the reporting unit’s PPA. Power prices, in the
respective markets in which those plants operate, have declined from 2011 and from the dates of our previous
impairment assessments due to several factors including decreased demand, lower oil prices and lower natural gas prices
resulting from an abundance of shale gas. Our forecasts for discounted cash flows also reflect a higher level of
uncertainty for re-contracting at prices than were previously forecasted in 2011. The decline in forward power prices for
British Columbia since our last goodwill impairment performed as of November 30, 2015, in particular, had a significant
impact on the estimated discounted cash flows of our Mamquam reporting unit and was the primary driver for its
F-32
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
recorded goodwill impairment. British Columbia’s peak demand outlook has declined primarily attributable to a
reduction in forecasted liquefaction build and need in the region and the associated loss of power demand. The resulting
drop in the peak demand reduces the amount of needed capacity and therefore the capacity prices also were reduced.
Furthermore, the PPA at the Curtis Palmer reporting unit expires at the earlier of December 2027 or the provision of
10,000 GWh of generation. Based on Curtis Palmer’s cumulative generation through the date of the goodwill
impairment test, we anticipate the PPA expiring before December 2027. As a result, the discounted cash flow model for
Curtis Palmer utilizes forward power prices for that period that are substantially lower than the prices under the current
PPA.
The long-lived asset and goodwill impairment charges were recorded in the third quarter of 2016 and not earlier
in the fiscal year because we did not identify any triggering events that would have required an event-driven impairment
assessment. Although declining power prices had been observed over the two years prior to the impairment, the
significant decrease in the long-term outlook for power prices in the regions where our reporting units operate identified
in the third quarter of 2016 had the most significant impact to the key inputs to our long-term forecasted cash flow
models. Additionally, the PPAs at our North Bay and Kapuskasing reporting units expire on December 31, 2017. As
these projects approach the expiration date, the remaining estimated contracted future cash flows decrease.
The following tables provide a summary of impairment charges by type for the years ended December 31,
2017:
Goodwill
Property, plant and equipment
Power purchase agreement
intangible assets
Total
Year Ended December 31, 2017
Curtis Palmer Williams Lake Naval Station North Island Naval Training Center Total
— $
$
— $
— $
14.7 $
—
28.5
12.1
17.0
— $ 14.7
67.6
10.0
—
14.7 $
0.6
29.1 $
10.4
22.5 $
4.2
21.2 $
$
3.6
18.8
13.6 $ 101.1
10. PPAs and other definite-lived intangible assets and liabilities
Other intangible assets and liabilities include PPAs, fuel supply agreements and capitalized development costs.
The following tables summarize the components of our intangible assets and other liabilities subject to
amortization at December 31, 2018 and 2017:
Assets
Gross balances, December 31, 2018
Less: accumulated amortization
Net carrying amounts, December 31, 2018
Other Intangible Assets, Net
Power Purchase
Agreements
$
$
362.7 $
(192.6)
170.1
$
Total
362.7
(192.6)
170.1
F-33
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Gross balances, December 31, 2017
Less: accumulated amortization
Net carrying amounts, December 31, 2017
Liabilities
Other Intangible Assets, Net
Development
Power Purchase
Agreements
$
476.3 $
(285.1)
191.2
$
$
Costs
13.0 $
(13.0)
—
$
Total
489.3
(298.1)
191.2
Power Purchase and Fuel Supply Agreement Liabilities, Net
Fuel Supply
Power Purchase
Agreements
Agreements
Total
Gross balances, December 31, 2018
Less: accumulated amortization
Net carrying amounts, December 31, 2018
$
$
(28.7)
14.0
(14.7)
$
(12.6) $
6.1
(6.5)
$
(41.3)
20.1
(21.2)
Gross balances, December 31, 2017
Less: accumulated amortization
Net carrying amounts, December 31, 2017
Power Purchase and Fuel Supply Agreement Liabilities, Net
Fuel Supply
Power Purchase
Agreements
Agreements
Total
$
$
(30.4) $
11.6
(18.8)
$
(12.6) $
7.3
(5.3)
$
(43.0)
18.9
(24.1)
The following table presents amortization expense of intangible assets for the years ended December 31, 2018,
2017 and 2016:
PPAs
Fuel supply agreements
Total amortization
2016
2018
2017
$ 43.4 $ 36.5 $ 63.3
(0.4)
$ 43.0 $ 36.1 $ 62.9
(0.4)
(0.4)
The following table presents estimated future amortization expense for the next five years:
Year Ended December 31,
2019
2020
2021
2022
2023
$
25.9
22.7
20.1
15.8
12.5
The weighted average remaining amortization period related to our intangible assets and liabilities was 9.7
years as of December 31, 2018.
F-34
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
11. Other long-term liabilities
Other long-term liabilities consist of the following at December 31:
Net pension liability
Accrued LTIP and director share units
Other
2018
2017
1.2
1.4
2.4
5.0 $
1.9
2.2
2.3
6.4
$
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
2018
45.3 $
4.3
1.8
(0.5)
(1.7)
49.2 $
2017
50.3
(6.5)
—
—
1.5
45.3
$
$
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 9, Goodwill and long-lived asset impairment 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 $3.5 million and
recorded a corresponding decommissioning loss in the consolidated statements of operations for the year ended
December 31, 2018. We expect to begin the decommissioning process in 2019 and will further evaluate the asset
retirement obligation when both the scope and cost are confirmed and record any changes in estimate as necessary.
F-35
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
12. Long-term debt
Long-term debt consists of the following:
Recourse Debt:
Senior secured term loan facility, due 2023(1)
Senior unsecured notes, due June 2036 (Cdn$210.0)
Non-Recourse Debt:
Epsilon Power Partners term facility, due 2019 (3)
Cadillac term loan, due 2025 (4)
Other long-term debt
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,
2018
2017
Interest Rate
$
450.0 $
154.0
540.0
167.4
LIBOR(2) plus
2.75 %
5.95 %
LIBOR plus 3.125 %
1.49 %
LIBOR plus
6.70 %
5.50 % -
—
21.0
—
(9.0)
(7.2)
(68.1)
540.7 $
7.2
24.0
0.1
(12.8)
(10.1)
(99.5)
616.3
$
Current Maturities:
Senior secured term loan facility, due 2023(1)
Epsilon Power Partners term facility, due 2019 (3)
Cadillac term loan, due 2025 (4)
Total current maturities
December 31, December 31,
2018
2017
Interest Rate
$
$
65.0 $
—
3.1
68.1 $
90.0
6.5
3.0
99.5
LIBOR(2) plus
LIBOR plus
LIBOR plus
2.75 %
3.125 %
1.49 %
(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 facility classified as current is based on
principal payments required to reduce the aggregate principal amount of Term Loans 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 $421.5 million of the $450 million outstanding aggregate borrowings under our Term Loan
facility at December 31, 2018. See Note 15, Accounting for derivative instruments and hedging activities for further
details. On October 31, 2018, the repricing of the senior secured term loan facility became effective, reducing the
interest rate to LIBOR plus 2.75% from 3.00% with no change to the 1.00% LIBOR floor.
(3)
In June 2018, we pre-paid the remaining $5.6 million principal amount originally due in 2018 and 2019.
(4) 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:
2019
2020
2021
2022
2023
Thereafter
Credit Facilities
$
$
68.1
108.1
82.7
78.3
128.3
159.5
625.0
On April 13, 2016, APLP Holdings Limited Partnership (“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 Loans”) and $200 million in aggregate principal amount of senior secured
credit facilities (the “Revolver” and together with the Term Loans, the “Credit Facilities”). At December 31, 2018,
$450.0 million of the Term Loans is outstanding and letters of credit in an aggregate face amount of $76.9 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%. We also extended the maturity date of the Revolver by one year through April 2022. The Term Loans mature in
April 2023.
The Term Loans include 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
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 Medium
Term Notes (“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
F-37
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 5.50:1.00 at December 2018 to 4.25:1.00 from June 30, 2020, and an
Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 3.00:1.00 at December 31, 2018 to 4.00:1.00
from June 30, 2022. At December 31, 2018, 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 loans under the Credit Facilities, it will be required to offer
each electing lender a prepayment of such lender’s term loans 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 facilities 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
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 Loans 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
F-38
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 ($153.9 million as of December 31, 2018) 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, 2018, 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, 2018, 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.
On October 13, 2017, we repaid the $54.6 million Piedmont term loan due August 2018, in full, with cash on
hand. In addition to the principal repayment, we paid $0.1 million of accrued interest, $9.4 million to terminate interest
rate swap agreements and wrote off $0.9 million of deferred financing costs. The swap termination costs and deferred
financing costs write down was recorded as interest expense in the year ended December 31, 2017.
13. Convertible debentures
The following table provides details related to outstanding convertible debentures:
December 31, December 31,
2018
2017
6.00% Debentures due January 2025 (Series E) (Cdn $115.0 million) $
5.75% Debentures due June 2019 (Series C)
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
$
84.3 $
—
—
42.5
18.1
(4.6)
(4.0)
93.8 $
64.5
(1.6)
—
105.4
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.
F-39
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 D Debentures
At December 31, 2018, we had $18.1 million (Cdn$24.7 million) principal amount outstanding 6.00%
Debentures due December 2019 (the “Series D Debentures”). We pay interest semi-annually on the last day of June and
December of each year for the Series D Debentures. They are convertible into our common shares at an initial
conversion rate of 68.9655 common shares per Cdn$1,000 principal amount, representing a conversion price of
Cdn$14.50 per common share. On March 3, 2018, we redeemed Cdn$56.2 million principal amount of the Series D
Debentures with a portion of the proceeds from the Series E Debentures Offering.
Series C Debentures
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.
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 was $1.2 million as of December 31, 2018. The portion
of the proceeds allocated to the separated derivative also created a discount of $4.7 million, which will be amortized to
F-40
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
interest expense over the maturity period of the Series E Debentures. For additional information, see Note 15,
Accounting for derivative instruments and hedging activities.
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,
2018
2017
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
$ 68.3 $
68.3 $ 78.7 $
2.1
4.2
0.3
4.5
15.4
625.0
102.4
2.1
4.2
0.3
4.5
15.4
607.6
101.8
6.2
2.7
2.8
4.4
19.9
738.7
107.0
Fair Value
78.7
6.2
2.7
2.8
4.4
19.9
749.3
108.1
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, 2018 and December 31, 2017. Financial assets and
liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
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
Level 1
December 31, 2018
Level 3
Level 2
Total
$ 68.3 $
2.1
—
$ 70.4 $
— $
—
4.5
4.5 $
— $ 68.3
—
2.1
4.5
—
— $ 74.9
$
$
— $ 18.7 $
— $ 18.7 $
1.2 $ 19.9
1.2 $ 19.9
December 31, 2017
Level 1
Level 2
Level 3 Total
$ 78.7 $
6.2
—
— $ — $ 78.7
6.2
—
—
5.5
—
5.5
$ 84.9 $ 5.5 $ — $ 90.4
$
$
— $ 24.3 $ — $ 24.3
— $ 24.3 $ — $ 24.3
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, 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. As of December 31, 2017, the credit
valuation adjustments resulted in a $2.2 million net increase in fair value, which consists of a $0.2 million pre-tax gain in
other comprehensive income and a $2.0 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, 2018, 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:
Balance of liability at inception (January 2018)
Total unrealized gain
Currency transaction gain
Ending balance of liability at December 31, 2018
15. Accounting for derivative instruments and hedging activities
Fair value
Measurement
Using Significant
Unobservable
Inputs (Level 3)
Year ended
December 31, 2018
$
$
4.7
(3.2)
(0.3)
1.2
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 income (loss), until the hedged
transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately
recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the
fair value are immediately recognized in earnings (loss). 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 of 6,500 Gj of natural gas per day is sold at the spot market price. This contract
is not accounted for as a derivative.
We have also entered into various natural gas sales and purchase agreements for approximately 700,000
MMBtu to effectively mitigate seasonal fluctuation of future natural gas price at Morris from January 2019 through
February 2019. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated
balance sheet at fair value at December 31, 2018. Changes in the fair market value of these contracts 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 2019 through 2022. These contracts are accounted for as derivative financial instruments and are recorded
in the consolidated balance sheet at fair value at December 31, 2018. Changes in the fair market value of these contracts
are recorded in the consolidated statement of operations.
Interest rate swaps
Atlantic Power Limited Partnership Holdings (“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, 2018, these
agreements totaled $421.5 million notional amount of the remaining $450.0 million aggregate principal amount of
borrowings under the senior secured term loan facility (“Term Loan Facility”). These interest rate swap agreements
expire at various dates through March 31, 2020. Borrowings under the $700.0 million Term Loan Facility 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 Facility for the non-swapped portion of the remaining principal amount. The weighted average rate of
these swap agreements is 1.27%, resulting in an all-in rate of approximately 4.02% for $421.5 million of the Term Loan
Facility. In January 2018, APLP Holdings entered into additional interest rate swap agreements. For the period
beginning September 30, 2018 through September 30, 2019, we mitigated exposure to changes in interest rates for $100
million notional amount at a one-month LIBOR fixed rate of 2.18% and for the period beginning October 1, 2019
through December 31, 2020, for $200 million notional amount at a one-month LIBOR fixed rate of 2.42%.
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 income (loss).
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. Principal and
interest payments for our senior secured term loans as well as our U.S. dollar-denominated convertible debentures 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, 2018, 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, 2018 and December 31, 2017:
Natural gas swaps
Gas purchase agreements
Interest rate swaps
Foreign currency forward contracts
Natural Gas (Mmbtu)
Natural Gas (Gigajoules)
Interest (US$)
Dollars (Cdn$)
16.3
9.0
616.6
—
9.9
9.9
412.6
25.0
Units
December 31, December 31,
2018
2017
Fair value of derivative instruments
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, 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
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
Foreign currency forward contracts current
Total derivative instruments not designated as cash flow hedges
Total derivative instruments
$
Accumulated other comprehensive income
December 31, 2017
Derivative
Assets
Derivative
Liabilities
$
— $
—
—
0.6
1.5
2.1
2.7
2.8
—
—
—
—
—
5.5
5.5 $
—
—
0.8
0.2
2.9
18.2
0.1
22.2
24.3
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, 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
Settlements expected to be recognized from OCI in expense in the
next 12 months, net of $0.2 million of tax
Year Ended December 31, 2017
Accumulated OCI balance at January 1, 2017
Change in fair value of cash flow hedges
Realized from OCI during the period
Accumulated OCI balance at December 31, 2017
Year Ended December 31, 2016
Accumulated OCI balance at January 1, 2016
Change in fair value of cash flow hedges
Realized from OCI during the period
Accumulated OCI balance at December 31, 2016
Interest Rate
Swaps
Interest Rate
Swaps
Interest Rate
Swaps
1.1
0.4
0.1
1.6
0.5
0.7
(0.1)
0.5
1.1
0.2
(0.2)
0.7
0.7
$
$
$
$
$
$
$
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
2016
2017
$ 4.1 $
0.3
(3.3)
7.5 $ 48.5
4.9
0.4
3.9
0.9
The following table summarizes the unrealized gain (loss) resulting from changes in the fair value of derivative
financial instruments that are not designated as cash flow hedges:
Classification of (loss) gain
recognized in income
Year ended December 31,
2016
2017
2018
Natural gas swaps
Gas purchase agreements
Interest rate swaps
Convertible debenture conversion option
Foreign currency forwards
16. Income tax expense
Change in fair value of derivatives $ (0.5) $ (1.8) $ 9.0
22.8
Change in fair value of derivatives
6.1
Change in fair value of derivatives
37.9
—
—
Other income, net
Foreign exchange (loss) gain
(5.0)
8.9
2.1
—
3.7
(1.0)
2.2
(1.2)
$ — $ 0.1 $
The following table summarizes the current and deferred portions of the net income tax expense (benefit):
Year Ended December 31
2017
2016
2018
4.1 $
2.9
3.8 $
(3.6)
(17.5)
0.2 $ (58.1) $ (14.6)
(62.2)
Current income tax expense
Deferred income tax benefit
Total income tax expense (benefit), net
$
$
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, 2018, 2017 and 2016, respectively, to the provision for income taxes in the
consolidated statements of operations:
Income (loss) before income taxes
Computed income taxes at 27% Canadian statutory rate
Decreases resulting from:
Operating 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 loss on intercompany notes
Impairments
Capital loss recognized on tax restructuring
Other
Income tax expense (benefit)
Effective income tax rate
$
$
Year ended December 31,
2017
2016
$ (151.1) $ (128.5)
(39.3)
(33.4)
2018
37.4
10.1
0.1
10.2
(6.7)
3.5
(20.1)
(59.4)
(34.6)
(94.0)
0.5
—
(3.3)
—
(1.1)
—
—
0.6
(3.3)
0.2 $
1 %
0.2
(2.4)
(1.5)
28.5
(0.1)
9.9
—
1.3
35.9
(58.1) $
38 %
(2.9)
(36.3)
10.8
(25.5)
(0.4)
6.9
(1.5)
—
(0.2)
22.3
(18.0)
1.8
10.9
(14.6)
11 %
The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and
deferred tax liabilities at December 31, 2018 and 2017 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
Valuation allowance
Deferred tax liabilities:
Intangible assets
Property, plant and equipment
Total deferred tax liabilities
Net deferred tax liability
F-48
2018
2017
$ 163.3 $ 157.7
35.4
—
3.0
1.4
2.8
4.0
1.1
2.2
207.6
(151.4)
56.2
34.4
10.9
0.5
1.4
2.9
3.2
1.5
—
218.1
(139.7)
78.4
(27.9)
(30.0)
(40.0)
(57.4)
(87.4)
(67.9)
(9.0) $ (11.7)
$
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table summarizes the net deferred tax position as of December 31, 2018 and 2017:
Long-term deferred liability
Net deferred tax liability
2018
2017
$
$
(9.0) $ (11.7)
(9.0) $ (11.7)
As of December 31, 2018, we have recorded a valuation allowance of $139.7 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.
Tax benefits related to uncertain tax positions taken or expected to be taken on a tax return are recorded when
such benefits meet a more likely than not threshold. Otherwise, these tax benefits are recorded when a tax position has
been effectively settled, which means that the statute of limitations has expired or the appropriate taxing authority has
completed their examination even though the statute of limitations remains open. Interest and penalties related to
uncertain tax positions are recognized as part of the provision for income taxes and are accrued beginning in the period
that such interest and penalties would be applicable under relevant tax law until such time that the related tax benefits are
recognized. As of December 31, 2018, we have not recorded any tax benefits related to uncertain tax positions.
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 was signed into law, making significant changes to
the U.S. Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"). The changes include, but are not
limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017,
which were reflected in our 2017 year-end financials, limitation on the deduction of net business interest expense, and
base erosion and anti-abuse tax. Based on estimates as of the date of this filing, we will not be subject to the base erosion
and anti-abuse tax. Our interest expense deduction may be limited, but it will not have a material impact on cash taxes.
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)
As of December 31, 2018, we had the following net operating loss carryforwards that are scheduled to expire in
the following years:
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
$
$
4.0
69.1
70.2
25.8
13.4
24.6
145.5
164.4
17.0
35.9
8.4
9.1
587.4
17. Equity compensation plans
Long-term incentive plan (“LTIP”)
The following table summarizes the changes in outstanding LTIP notional units during the years ended
December 31, 2018, 2017 and 2016:
Outstanding at December 31, 2015
Granted
Vested and redeemed
Forfeitures
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
Units
1,298,401
1,594,954
(784,806)
(7,431)
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 $
Grant Date
Weighted-Average
Fair Value per Unit
2.88
1.81
2.83
2.71
2.08
2.38
2.22
2.32
2.22
2.02
2.22
2.09
2.09
The total grant date fair value of all outstanding notional units under the LTIP was $8.3 million, $6.4 million
and $4.4 million for the years ended December 31, 2018, 2017 and 2016. The weighted average remaining vesting term
for outstanding notional units was 1.8 years at December 31, 2018. Approximately $4.1 million of total unrecognized
compensation expense is expected to be recognized over the term of the outstanding LTIP units. Compensation expense
related to LTIP was $3.6 million, $3.4 million and $2.8 million for the years ended December 31, 2018, 2017 and 2016,
respectively. Cash payments made for vested notional units were $0.9 million, $0.7 million and $0.5 million for the
years ended December 31, 2018, 2017 and 2016, respectively.
F-50
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Transition Equity Participation Agreement
We also have 539,904 transition notional shares outstanding at December 31, 2018 under the Transition Equity
Participation Agreement with James J. Moore, Jr. Fifty percent (269,952) of the transition notional shares granted vested
on January 22, 2019, the four-year anniversary of the date of grant and the remaining portion will vest on or any time
after the two-year anniversary of the grant if the weighted average Canadian dollar closing price of our common shares
on the TSX for 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%.
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 $0.3 million to the pension plan in 2019.
The net annual periodic pension cost related to the pension plan for the years ended December 31, 2018, 2017
and 2016 includes the following components:
Service cost benefits earned
Interest cost on benefit obligation
Expected return on plan assets
Net period benefit cost
2018
$
2017
2016
0.3 $
0.5
(0.7)
0.1 $
0.5 $
0.6
(0.9)
0.2 $
0.7
0.7
(0.9)
0.5
$
F-51
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
A comparison of the pension benefit obligation and related plan assets for the pension plan at December 31 is as
follows:
2018
2017
Project benefit obligation at January 1
Service cost
Interest cost
Actuarial loss (gain)
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)
1.4
(0.1)
0.8
—
1.3
(13.2)
$ (15.8) $ (17.4)
(0.5)
(0.6)
(0.9)
(0.1)
0.2
4.5
(1.0)
(15.8)
16.1
1.1
1.3
0.1
(0.2)
(5.4)
0.9
13.9
(1.9)
13.9 $
(0.4)
0.4
0.1
(0.8)
—
(1.2)
12.0
(1.2) $
$
$
Non-current liabilities
2018
2017
$
1.2 $
1.9
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 loss
2018
2017
$
1.4 $
1.6
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
$
2018
13.2 $
12.2
12.0
2017
15.8
14.4
13.9
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 $12.0 million and $13.9 million for the years ended December 31, 2018 and 2017,
respectively.
F-52
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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
2018
2017
4.0 %
2.0 %
3.5 %
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
2018 2017
2016
3.5 %
5.8 %
2.0 %
4.0 %
5.8 %
2.0 %
4.3 %
5.8 %
3.0 %
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, 2018, 2017 and 2016, were based on the CIA / Natcan curve, which was designed by the Canadian
Institute of Actuaries and Natcan Investment Management to provide a means for sponsors of Canadian plans to value
the liabilities of their postretirement benefit plans. The CIA / Natcan 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 provincial AA credit risk.
The CIA / Natcan 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.
F-53
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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
International fixed income
2018
2017
29 %
14 %
13 %
41 %
3 %
— %
100 %
30 %
14 %
14 %
39 %
— %
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$:
2019
2020
2021
2022
2023
2024-2028
Defined Contribution Plans
2018
Cdn$
0.4
0.4
0.5
0.6
0.7
4.4
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 $1.4 million,
$1.2 million, and $1.4 million for the years ended December 31, 2018, 2017 and 2016, respectively.
19. Common shares
Our common shares have no par value and unlimited authorization. We had 108,341,738 and 115,211,976
common shares issued and outstanding at December 31, 2018 and December 31, 2017, respectively.
Stock Repurchase Program
On December 31, 2018, we commenced new NCIBs for 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. The new NCIBs expire on December 30, 2019. Under the new NCIBs, we may purchase up to a total of
10,623,464 common shares based on 10% of our public float as of December 17, 2018 and we are limited to daily
purchases of 10,300 common shares per day with certain exceptions including block purchases and purchases on other
approved exchanges. All purchases made under the new 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 U.S. Securities Exchange Act of 1934, 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.
F-54
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
During the year ended December 31, 2018, we repurchased and canceled 7,772,971 common shares at a total
cost of approximately $16.6 million. In the year ended December 31, 2017, we repurchased and canceled 93,391
common shares at a total cost of approximately $0.2 million.
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 United States Securities
Exchange Act of 1934, 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.
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 at the annual rate of Cdn$1.2125 per share. Beginning on June 30, 2012, the Series 1 Shares
were redeemable by the subsidiary company at Cdn$26.00 per share, declining by Cdn$0.25 each year to Cdn$25.00 per
share on or after June 30, 2016, plus, in each case, an amount equal to all accrued and unpaid dividends thereon.
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 pay fixed cumulative dividends of Cdn$1.75 per share per annum, as and when declared, for the initial five-year
period ending December 31, 2014. The dividend rate was reset on December 31, 2014 and will reset every five years
thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.18%. On
December 31, 2014 and on December 31 every five years thereafter, the Series 2 Shares were and will be redeemable by
the subsidiary company at Cdn$25.00 per share, plus an amount equal to all declared and unpaid dividends thereon to,
but excluding the date fixed for redemption. The holders of the Series 2 Shares had and will have the right to convert
their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the” Series 3 Shares”) of the subsidiary, subject to
certain conditions, on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 3
Shares will be entitled to receive quarterly floating rate cumulative 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%. On December 31, 2014, 1,661,906 of Series 2 shares were converted to Series 3 shares.
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.
F-55
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 $8.3 million, $8.7
million and $8.5 million for the years ended December 31, 2018, 2017 and 2016, respectively. In 2018, we repurchased
and cancelled 475,000 of the Series 1 Shares at Cdn$15.27 per share for Cdn$7.3 million. We also purchased and
cancelled 5,000 and 164,790 of the Series 2 and 3 Shares at Cdn$17.99 and Cdn$17.89 per share for Cdn$0.1 million
and Cdn$2.9 million, respectively for a total cost of $8.0 million. A $7.9 million gain on the redemption was recorded as
a component of income attributable to preferred shares of a subsidiary company in the year ended December 31, 2018.
From December 31, 2018 through February 27, 2019, we purchased the maximum limit of 427,500 shares of Series 1
Preferred Shares, 27,777 of Series 2 Preferred Shares and the maximum limit of 148,311 Series 3 Preferred Shares at a
total cost of Cdn$9.2 million.
21. Basic and diluted earnings (loss) per share
Basic earnings (loss) per share is calculated by dividing net income (loss) 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 earnings
(loss) per share is computed in a manner consistent with that of basic earnings (loss) 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 earnings (loss) 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 earnings (loss) per share. However, these instruments are included in the
denominator, when dilutive, for purposes of computing diluted earnings (loss) per share under the treasury stock method.
The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share
calculation for the years ended December 31, 2018, 2017 and 2016:
Basic
Numerator:
Income (loss) attributable to Atlantic Power Corporation
Denominator:
Weighted average basic shares outstanding
Basic earnings (loss) per share attributable to Atlantic Power Corporation
Diluted
Numerator:
Net income (loss) attributable to Atlantic Power Corporation
Add: convertible debenture interest expense
Denominator:
Weighted average basic shares outstanding
Convertible debentures
Share-based compensation
Diluted earnings (loss) per share attributable to Atlantic Power Corporation
2018
2017
2016
$
36.8 $
(98.6) $ (122.4)
112.0
$
0.33 $
115.1
(0.86) $
119.5
(1.02)
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)
(122.4)
—
(122.4)
119.5
—
—
119.5
(1.02)
F-56
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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
2018
2017
2016
—
—
—
1.6
8.1
9.7
1.4
13.1
14.5
We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. We analyze the
performance of our operating segments based on Project Adjusted EBITDA which 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 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 income (loss).
A reconciliation of Project Adjusted EBITDA to net income (loss) is included in the tables below:
East U.S. West U.S. Canada
Un-Allocated
Corporate
Consolidated
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 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)
$ 158.7 $
585.3
17.7
1.3
43.8 $ 78.9 $
176.0
—
0.1
182.3
3.6
0.1
$ 120.8 $
21.9 $ 41.9 $
0.4
46.1
3.4
—
70.9
—
—
—
—
70.9
—
$ 70.9 $
—
25.0
—
(4.0)
0.9
—
—
—
—
0.9
—
0.9 $ 17.0 $
(3.6)
28.5
—
—
17.0
—
—
—
—
17.0
—
F-57
0.9 $
80.9
—
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
1,024.5
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
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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
Project (loss) income
Administration
Interest expense, net
Foreign exchange loss
Other income, net
Net (loss) income before income taxes
Income tax benefit
Net (loss) income
Year Ended December 31, 2016
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 expense
Project income (loss)
Administration
Interest, net
Foreign exchange loss
Other income, net
Net income (loss) before income taxes
Income tax benefit
Net income (loss)
East U.S. West U.S. Canada
Un-Allocated
Corporate
Consolidated
$ 152.5 $ 108.9 $
168.6 $
1.0 $
431.0
632.4
17.7
4.6
189.9
—
0.1
239.6
3.6
0.8
96.9
—
—
1,158.8
21.3
5.5
$ 112.5 $
(6.3)
45.2
19.2
72.4
(1.0)
(17.0)
—
—
—
—
(17.0)
—
49.1 $
—
35.5
—
85.6
—
(72.0)
—
—
—
—
(72.0)
—
125.8 $
6.1
51.9
—
29.1
(0.1)
38.8
—
—
—
—
38.8
—
$ (17.0) $ (72.0) $ 38.8 $
1.4 $
(1.9)
0.6
—
—
(0.1)
2.8
23.6
64.2
16.3
(0.4)
(100.9) $
(58.1)
(42.8) $
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)
East U.S.
West U.S. Canada
Un-Allocated
Corporate Consolidated
291.8
3.6
0.9
(25.5)
49.5
—
70.5
—
134.5 $ 101.3 $ 162.5 $
754.2
32.4
6.2
313.6
—
—
92.4 $ 51.2 $ 58.8 $
—
(9.2)
39.4
44.1
—
10.9
—
15.4
—
—
31.2 $ 11.8 $ (35.7) $
—
—
—
—
11.8
—
31.2 $ 11.8 $ (35.7) $
—
—
—
—
(35.7)
—
—
—
—
—
31.2
—
0.9 $
97.2
—
0.1
(0.2) $
(3.2)
0.5
—
—
(0.3)
2.8
22.6
106.0
13.9
(3.9)
(135.8)
(14.6)
(121.2) $
399.2
1,456.8
36.0
7.2
202.2
(37.9)
133.5
10.9
85.9
(0.3)
10.1
22.6
106.0
13.9
(3.9)
(128.5)
(14.6)
(113.9)
$
$
$
F-58
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The table below provides information, by country, about our consolidated operations for each of the years
ended December 31, 2018, 2017 and 2016 and Property, Plant & Equipment as of December 31, 2018 and 2017,
respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which
they are located.
2018
Revenue
2017
Property, Plant and
Equipment, net of
accumulated
depreciation
2016
2018
2017
United States
Canada
Total
$ 203.4 $ 262.4 $ 236.7 $ 396.5 $ 426.2
176.1
$ 282.3 $ 431.0 $ 399.2 $ 549.5 $ 602.3
153.0
162.5
168.6
78.9
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. OEFC, San Diego Gas & Electric,
and BC Hydro provided 29.2%, 11.5%, and 10.9%, respectively, of total consolidated revenues for the year ended
December 31, 2016. IESO and OEFC purchase electricity from the Calstock, Nipigon and Tunis projects and previously
purchased electricity from our North Bay and Kapuskasing projects in the Canada segment. San Diego Gas & Electric
previously purchased electricity from the Naval Station, Naval Training Center, and North Island projects in the West
U.S. segment, Niagara Mohawk purchases electricity from the Curtis Palmer project in the East U.S. segment, and BC
Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the Canada segment.
23. Commitments and contingencies
Commitments
Operating Lease Commitments
We lease our office properties and equipment under operating leases expiring on various dates through 2024.
Certain operating lease agreements over their lease term include provisions for scheduled rent increases. We recognize
the effects of these scheduled rent increases on a straight-line basis over the lease term. We also have leased office
properties for which we have entered into sub-lease agreements with tenants. The table below nets future rental income
from these sub-lease agreements against the future rental expense obligations for the company. Lease expense under
operating leases was $0.4 million, $0.5 million and $0.6 million for the years ended December 31, 2018, 2017, and 2016,
respectively. Future minimum lease commitments under operating leases for the years ending after December 31, 2018,
are as follows:
2019
2020
2021
2022
2023
Thereafter
$
$
0.6
0.3
0.3
0.3
0.1
—
1.6
F-59
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Management Service Commitments
Our Manchief project is operated by a third party under a contract that expires in April 2022. As of
December 31, 2018, our commitments under this agreement are estimated as follows:
2019
2020
2021
2022
2023
Thereafter
$
$
0.4
0.4
0.4
0.2
0.1
—
1.5
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, 2018, our commitments under such outstanding
agreements are estimated as follows:
2019
2020
2021
2022
2023
Thereafter
Acquisition Commitment
$
$
7.5
4.2
4.2
5.1
—
—
21.0
On September 20, 2018, we executed an agreement to acquire two biomass plants in South Carolina from EDF
Renewables for $13.0 million. Closing of the transaction is expected to occur late in the third quarter or in the fourth
quarter of 2019, subject to restructuring of the plants’ ownership structure by EDF Renewables after the end of relevant
tax credit recapture periods. We have paid $2.6 million of the purchase price, which will be held in escrow until the
closing date. The remainder of the purchase price will be paid at closing. If we do not proceed with the transaction close
due to circumstances related to Atlantic Power, we will forfeit the $2.6 million held in escrow to EDF Renewables.
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.
F-60
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Contingencies
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,
2018.
24. Unaudited selected quarterly financial data
Unaudited selected quarterly financial data are as follows:
Project revenue
Project income
Net income (loss)
Net income (loss) attributable to Atlantic Power
Corporation
Quarter Ended
2018
December 31, September 30,
$
70.7 $
20.1
26.7
June 30,
March 31, Total
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
Project revenue
Project (loss) income
Net loss
Net loss attributable to Atlantic Power Corporation
Quarter Ended
2017
December 31, September 30,
$
100.0 $
(39.7)
(38.9)
(41.1)
June 30,
March 31, Total
108.6 $ 124.0 $
(20.9)
(33.7)
(32.9)
(12.1)
(19.8)
(21.9)
98.4 $ 431.0
(47.4)
25.3
(93.0)
(0.6)
(98.6)
(2.7)
Loss per share attributable to Atlantic Power Corporation $
Weighted average number of common shares
outstanding-basic
Diluted loss per share attributable to Atlantic Power
Corporation
Weighted average number of common shares
outstanding-diluted
$
(0.36) $
(0.29) $ (0.19) $ (0.02) $ (0.86)
115.2
115.3
115.2
114.8
115.1
(0.36) $
(0.29) $ (0.19) $ (0.02) $ (0.86)
115.2
115.3
115.2
114.8
115.1
F-61
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,
2018
2017
$
$
$
$
$
$
42.4
3.3
45.7
51.6
97.3
3.4
1.2
18.1
22.7
80.4
1.1
104.2
41.8
1.8
43.6
46.6
90.2
1.7
—
—
1.7
105.5
1.3
108.5
(6.9)
97.3
$
(18.3)
90.2
$
F-62
ATLANTIC POWER CORPORATION
SCHEDULE I—CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)
(in millions of U.S. dollars)
Year Ended December 31,
2017
2018
2016
Administrative and other expenses:
Administrative expense
Interest expense, net
Foreign exchange (gain) loss
Other (income) expense
Loss from parent company
$
5.0 $
5.4 $
13.5
(9.4)
(3.1)
(6.0)
11.6
4.0
0.2
(21.2)
5.9
7.3
10.6
(3.6)
(20.2)
Equity earnings (loss) of subsidiaries, net of income tax benefit
43.2
(71.8)
(93.7)
Net income (loss)
$
37.2 $
(93.0) $
(113.9)
See accompanying notes to condensed financial statements.
F-63
ATLANTIC POWER CORPORATION
SCHEDULE I—CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)
(in millions of U.S. dollars)
Years Ended December 31,
2017
2018
2016
Cash provided by operating activities:
Net income (loss)
Adjustments to reconcile net loss to net cash provided by operating activities:
Non-cash (earning) losses from subsidiaries, net of taxes
Dividends received from subsidiaries
Unrealized foreign exchange (gain) loss
Gain on purchase and cancellation of convertible debentures
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) provided by investing activities:
Advances to / from investments in subsidiaries
Cash paid for acquisition
Deposit for acquisition
Cash (used in) provided by investing activities
Cash used in financing activities:
Common share repurchases
Repayment of convertible debentures
Deferred financing costs
Proceeds from convertible debenture issuance
Payments received from intercompany note
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
$
37.2 $
(93.0) $
(113.9)
(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)
71.8
67.9
4.0
—
—
—
(1.1)
1.4
0.5
51.5
(57.8)
—
—
(57.8)
(16.6)
(88.1)
(5.1)
92.2
—
(0.2)
(17.8)
0.6
41.8
42.4 $
(0.2)
—
—
—
—
(0.9)
(1.1)
(7.4)
49.2
41.8 $
93.7
33.6
10.6
(4.7)
—
—
11.5
6.0
(1.1)
35.7
216.7
—
—
216.7
(19.5)
(187.5)
—
—
1.5
(9.2)
(214.7)
37.7
11.5
49.2
4.7 $
6.2 $
48.3
$
$
See accompanying notes to condensed financial statements
F-64
SCHEDULE I—NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)
ATLANTIC POWER CORPORATION
1. Nature of business
(in millions of U.S. dollars)
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, 2018, total Atlantic Power Corporation
shareholders’ deficit was $6.9 million and approximately $5.5 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 80% of our consolidated net assets, thus requiring this Schedule I, “Condensed Financial Information of the
Registrant.” Accordingly, the balance sheets as of December 31, 2018 and 2017, and the statements of operations and
cash flows for the years ended December 31, 2018, 2017 and 2016, 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, 2018, 2017 and 2016, 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, 2018 and is not prohibited from making dividends to the Parent
Company. The consolidated equity of APLP Holdings was approximately $62.7 million at December 31, 2018 and
includes the subsidiaries with restricted net assets of $5.5 million at December 31, 2018 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 $39.0 million, $67.9 million and $33.6 million in 2018, 2017 and
2016, respectively, from its consolidated and unconsolidated subsidiaries.
F-65
ATLANTIC POWER CORPORATION
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 and 2016
(in millions of U.S. dollars)
Balance at Charged to
Beginning of Costs and
Expenses
Period
Balance at
Charged to
Other Accounts Deductions End of Period
Income tax valuation allowance, deducted from
deferred tax assets:
Year ended December 31, 2018
Year ended December 31, 2017
Year ended December 31, 2016
$
151.4 $ (11.7) $
186.0
175.2
(34.6)
10.8
— $
—
—
— $
—
—
139.7
151.4
186.0
F-66
Exhibit 31.1
I, James J. Moore, Jr., certify that:
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 Rule 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 account 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 28, 2019
/s/ JAMES J. MOORE, JR.
James J. Moore, Jr.
President and Chief Executive Officer
Exhibit 31.2
I, Terrence Ronan, certify that:
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 account 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 28, 2019
/s/ TERRENCE RONAN
Terrence Ronan
Chief Financial Officer (Duly Authorized Officer and
Principal Financial and Accounting 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 December 31, 2018 (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 28, 2019
/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, 2018 (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 28, 2019
/s/ TERRENCE RONAN
Terrence Ronan
Chief Financial Officer (Duly Authorized Officer and
Principal Financial and Accounting Officer)
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 19, 2019.
14SEP201110485170