14SEP201110485170
2016
Annual Report
Report to Shareholders
Dear Shareholder,
Since we communicated our fourth quarter and year-end 2016 results in early March, there have
been some significant positive developments:
OEFC revenue adjustment. We now have an estimate of the revenues we expect to receive as a
result of the Global Adjustment litigation against the Ontario Electricity Financial Corporation
(OEFC), the customer for our power plants in Ontario. We were not a party to this litigation but we
have a standstill agreement with the OEFC that protects our right to make a claim for our three
affected plants. The total of payments received in the first quarter of 2017, a lump sum payment
expected to be received shortly, and higher payments on two of the plants in the remainder of 2017 is
approximately Cdn$36 million or US$27 million. This amount will add significantly to our year-end
2016 parent company cash balance of approximately $60 million.
Repricing of term loan and revolver. Earlier this month, we successfully executed a repricing of
our senior secured term loan, which had an outstanding balance of $615 million as of March 31, and
our $200 million corporate revolving credit facility, both of which were originally issued in April 2016.
We were able to reduce the spread by 75 basis points to LIBOR plus 425 basis points. This is expected
to generate cumulative savings of approximately $17 million, net of transaction fees, through the
maturity dates of the term loan and the revolver.
Piedmont. We have made significant progress in completing a required amendment to Piedmont’s
Title V air permit. Once this matter is resolved, we expect to conclude our evaluation of whether to
pursue a sale of this plant, or continue to own it and either refinance the project debt, which has an
August 2018 maturity, or pay it down using our liquidity. If we were to sell Piedmont, we expect it
would generate net proceeds in excess of the project debt repayment that would add to the cash totals
I cited above. We are under no pressure to sell any assets absent compelling terms, so we will take a
disciplined approach to evaluating these options.
This year’s letter is divided into three sections: first, a discussion of how we think about the
business; second, a summary of our 2016 results; and third, a review of the progress we have made in
our corporate turnaround efforts in 2015 and 2016. The first section is very similar to my prepared
remarks for our fourth quarter and year-end conference call, when I said we had decided to provide
the commentary early rather than holding it a month for this Annual Report (see the Investors page of
our website under ‘‘Presentations’’ for the complete text of these remarks).
HOW WE THINK ABOUT THE BUSINESS
In managing this business and making capital allocation decisions, we try to think and act like a
family that has 100% of its net worth invested in the business and is in it for the long haul. We are not
focused on quarterly results. We are not focused on GAAP earnings. We don’t try to promote the
shares and we don’t focus on how to ‘‘surface value’’ or otherwise move the share price. We don’t try
to time the market to get the highest short-term outcome, and we don’t try to maximize upside by
taking on undue risk. We are focused on the free cash flow generated by our business. We are focused
on building intrinsic value per share. Our belief is that if we run the business like owners and build
value, the share price will reflect this value over time.
Now we understand, and so should you, that this is a tough business. Power generation is a capital-
intensive, cyclical, commodity-priced, and heavily government-regulated activity (I told you we aren’t
promotional). The way we (members of the management team) have made money in the energy
business since 1982 and in power since 1986 has been to be mindful of the cyclical nature of the
business and to use the market’s near-term overreactions to our advantage when investing, buying or
selling assets or businesses. During the course of my career, I have been involved in the sale of
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independent power producer (IPP) businesses three times, the sale of a quarter of the assets of a
business twice, and been involved in one of the largest spin-offs in the international power business.
Today the shares of U.S. IPPs trade near historic lows. Atlantic Power stock (NYSE) hit an
all-time low in December 2015, but traded up 27% in 2016 while the shares of the three largest U.S.
IPPs traded up 6%, down 21% and down 37%. Relative performance in a terrible market is cold
comfort to owners. The stock closed at $2.71 the day before I joined the Company (in January 2015),
so I have nothing to brag about. After two years of intense restructuring, painful cost-cutting, and
substantial delevering, the result is a lower share price.
Although we certainly acknowledge the lack of progress on the share price, our focus is on
improving the business fundamentals, not on short-term movements in share price. Our response to a
low share price is to stay focused on these fundamentals, not to actively market the shares. We believe
if we can manage frugally, allocate capital rationally, and do the best we can with the cards we are
dealt, we will have opportunities to be rewarded by the share price ultimately reflecting intrinsic value,
or by a private buyer seeing the value disconnect. We are not interested in talking the shares up to
avoid outcomes that would shorten our tenure in our jobs (as much as we like the work). Ideally
shareholders will share our orientation. If shareholders are focused on quarterly results or GAAP
numbers, they are likely to be disappointed with their holding in Atlantic Power. If shareholders are
long-term oriented and patient investors who look to the underlying business fundamentals, while they
might be disappointed, they at least will be playing the same game as management. They might be
disappointed due to the poor sector economics of the moment being more prolonged than anticipated
(recall the old Buffett saying that when a management with a reputation for brilliance tackles a
business with a reputation for bad economics, it is the reputation of the business that remains intact).
They also might be disappointed because management is not brilliant. However, I’m sure they will find
that management is focused on shareholders and tries to communicate as transparently as the law
allows.
In February of last year, when the stock was at $1.68 (which was not much above the all-time
closing low of $1.60), we announced the elimination of our common stock dividend in order to boost
our liquidity for higher value-added purposes, including repurchasing debt and common shares. Since
we announced that decision, the Company has bought and canceled approximately 8.1 million shares at
an average price of $2.42 per share. The $19.6 million we have invested in repurchases represents
nearly two years of the previous dividend payment. We made this investment because the shares were
trading at a meaningful discount to our estimates of intrinsic value per share. If we can buy shares at
estimated returns that are higher than the returns available from external growth we want to do so,
even though we are shrinking the balance sheet rather than growing the absolute size of the business.
We try to take a balanced approach in deciding whether to allocate excess liquidity to reducing
debt (to further derisk the Company) or to repurchasing shares at a discount (to increase the value per
share for remaining shareholders). The limiting factor on our share purchases is that we are committed
to reducing leverage. In the type of business I described earlier, one needs to be prudent regarding the
use of debt. The nearly $20 million of share repurchases in 2016 is very modest in comparison with
approximately $533 million of debt repurchases or redemptions over the 2015-2016 period. If we didn’t
believe it was prudent to continue delevering the balance sheet, we would be buying shares more
aggressively.
In addition to the share repurchases made by the Company, since joining Atlantic Power two years
ago I have made a personal investment in the Company by buying 350,000 shares at an average price of
$2.47 per share. As a group, management and directors have bought a total of nearly 1.5 million shares
at an average price of $2.32 and a high price of $3.24. These purchases were based on the belief that
the shares represented a good price-to-value investment. If we believe the shares are trading above
intrinsic value, we will not buy them for the Company, nor would insiders buy for themselves unless
they were doing so to meet an ownership guideline.
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We use our intrinsic value framework to determine the overall value of the business, which helps
to inform our capital allocation decisions. We do not publish our estimates. To do so might encourage
investors to rely too much on what are rough estimates within a wide range that are subject to much
variability. Our intrinsic value estimates are highly sensitive to the discount rate we assume and the
forecasts of future power prices that we use to estimate the cash flows that our plants may generate in
the period after their Power Purchase Agreements (PPAs) expire. These assumptions and forecasts also
affect the estimated terminal value of our hydro facilities, which is another component of our intrinsic
value.
These forecasts of power prices, or forward power curves, are very volatile, and are driven by the
supply of and demand for power, both of which are heavily dependent on government policies and
regulations, along with macroeconomic factors. Natural gas prices and hostile public policy are driving
coal and nuclear plant retirements on the supply side. Public policy, including state-level renewable
energy portfolio standards and federal tax incentives, has driven the growth of intermittent sources of
power (wind and solar). Although these sources are intended to reduce carbon emissions, they also
lower the value of, increase the costs of operating, and make less efficient the natural gas plants that
are still necessary to generate power when the intermittent sources do not. The intermittent sources
don’t replace the need for gas plants, but they do reduce the run time of gas plants. Although these
dynamics have made natural gas plants less profitable (and therefore less valuable), the low levels of
interest rates have encouraged investment funds and others to continue building these plants into an
oversupplied market in the hope that retirements (primarily of coal and nuclear plants) will outpace
capacity additions.
Today there is a large disparity between share prices of U.S. IPPs and prices for the underlying
power assets, particularly those backed by PPAs with a long remaining life. Our experience has been
that when the markets are pessimistic, they assume that conventional power plants are no longer
needed and they price them accordingly. When markets are optimistic, particularly on wind and solar,
they become exuberant and these assets are priced accordingly. We are buying in the former market
(for shares) and selling in the latter market (for assets). We might be wrong on both counts. Our
estimates of intrinsic value could be wrong. Power prices might go lower and stay lower for longer than
we anticipate. Low interest rates might last longer than people think, and the returns on contracted
assets (these days, generally intermittent sources) can be compelling in such an environment.
Given the current depressed state of the power markets, and the potential for this to continue for
an indeterminate length of time, one might ask whether we should consider selling the Company. As
noted before, during the course of my career, I have been involved in six transactions where a large
portion or all of the IPP business has been sold or spun-off. There are a couple of reasons that we
have not tried to sell the business since we ran a strategic process in 2014. First, we have much lower
debt and overhead cost levels and a significantly improved debt maturity profile as compared to three
years ago. Although power prices are significantly lower than a few years ago, which affects the
recontracting outlook for our plants, our hydro assets have significant value beyond their PPA terms by
virtue of their low marginal costs and long remaining lives. Our balance sheet and cash flow provide a
base from which we can grow, either by doing projects for industrial customers or by taking advantage
of other opportunities that the volatile energy sector has a history of providing from time to time to
those with a contrarian bent and dry powder. Second, IPP shares currently trade at much lower
multiples than those for assets backed by PPAs. When power prices are down 40 to 50% and IPP
shares are trading near all-time lows, it is not an opportune time to obtain fair value (much less a
premium) on a sale of the entire business.
Instead, in the past two years, we sold our five wind plants (at 13 times estimated cash
distributions) and mothballed four other plants (with no guarantee they will return to operation,
although our expectation is that they will at some point). In addition, we are contemplating the sale of
another plant, so from 28 plants two years ago we may be at 18 or 19 in operation by the end of this
year. The end result of these steps has been reduced debt, lower operating costs and increased cash
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flow available for higher-return purposes, including debt and equity repurchases. The actions we’ve
taken with respect to individual plants are not an indication that we are preparing for a sale of the
entire Company. I’m merely making the point that the management team has a long track record of
selling assets and businesses when prices are compelling compared to the value to be realized from
holding or growing the business.
In short, while this time might be different or the tough environment might last longer than a
typical cycle, we believe we can extract more value for shareholders by continuing to run our business
than by selling the Company. Right now the math indicates to us that we ought to stay the course,
which means a focus on costs, debt reduction, rational capital allocation, entrepreneurial but disciplined
growth efforts, and buying shares with cash excess to what we need to reduce debt to further improve
our leverage ratios. We can’t be certain we will make the right calls all the time, but you can be certain
that we constantly ask ourselves, ‘‘What would we do if we had 100% of our families’ net worth
invested in this business?’’
Different Scenarios and How They Affect the Value of Atlantic Power
Let me lay out a range of scenarios for the future and how we think they might affect the value of
Atlantic Power.
Lower for Longer:
This is a cyclical business and our experience has been that making money requires being
countercyclical in capital allocation. It might be different this time. Conventional power assets are not
favored, at least not from a policy perspective in many states. The continued build-out of intermittent
sources of power driven by state policies and federal tax subsidies may continue to diminish the value
of conventional power plants for a longer period than economic sense would dictate.
In such a case, an owner of such assets has two choices—sell, or hunker down in order to survive
to a time in the future when, for example, the treatment of natural gas plants becomes more favorable
or when the volatility in the markets provides a full price for the assets.
Thinking like owners with a long-term orientation means we have focused on protecting the
downside first. Our total debt, including our share of debt at equity-owned projects, has been reduced
by nearly a billion dollars since year-end 2013. Our corporate overhead has been reduced by nearly
60% from $54 million in 2013 to $23 million in 2016. Our annual interest expense has been reduced by
$60 million over the same period. Our credit ratings have improved. We have extended our debt
maturities. As of the end of March 2017, we have liquidity of approximately $214 million, consisting of
$91 million of unrestricted cash (including $65 million at the parent) and $122 million of available
borrowing capacity under our revolver.
All of this debt and cost reduction has been painful. We closed offices and laid off employees. We
moved the headquarters from the financial district in downtown Boston to the suburbs in Dedham,
Massachusetts. Having come through two years of restructuring, we now have the financial strength to
avoid fire sales of assets. We believe we are well positioned to address our debt maturities through
2019, and we expect to have repaid more than 80% of our term loan by its maturity in 2023.
Although we have reduced debt and overhead costs by a considerable amount already, we are still
grinding away on corporate general and administrative expense (G&A, or overhead) and plant
operation and maintenance expense (O&M). The plant O&M is a challenge as our plants are smaller
on average than those of the larger IPP companies. Our smaller, mostly older and geographically
scattered fleet makes O&M cost benchmarks more difficult to achieve versus larger, newer, and less
dispersed fleets. But on corporate G&A, we think we are very efficient in terms of G&A dollars per
plant. Again, on a per megawatt (MW) basis it is more challenging. We have 23 plants with an average
capacity of approximately 90 MW and if we increased the average plant size to 350 MW, there would
be little in the way of increased corporate overhead required to handle larger-sized plants. As a
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percentage of revenue, our G&A costs have been driven down from 8.6% in 2013 to less than 6%
today. We have reduced our revenue by 36% in the course of the asset sales noted above, which
normally would provide negative operating leverage, but we have been so aggressive on costs that they
have come down by 58%, more than the 36% reduction in revenue.
In terms of PPA renewals, this hard-won financial stability has allowed us to be patient rather than
being pressured to execute renewals on any terms. We appreciate that investors want to know the likely
outcome of PPA renewals, but these require patience and discipline on our part to try to achieve the
best outcome possible in a market where power prices have fallen to very low levels relative to both
historical and new build prices. Our Morris PPA renewal was a good outcome for the Company and is
modestly accretive to EBITDA versus the prior PPA terms, while providing our customer with good
terms and benefits. That was a win/win. As our Executive Vice President of Commercial Development
Joe Cofelice pointed out in our fourth quarter and year-end conference call materials, our Ontario
renegotiation was a creative effort by the commercial team to respond to the supply and demand
situation in that province, while lowering gas costs for customers and greenhouse gas costs for the
Company. That result produced benefits for all parties. In San Diego, the run rate for any new PPA
will be quite a bit lower than that under the previous arrangement, reflecting current market
conditions. However, assuming we are able to reach new agreements with the U.S. Navy (which we
cannot predict), we would expect that if we are successful in executing a new PPA in San Diego, it will
provide us the ability to make incremental capital investments at returns well in excess of what we
could realize from other uses of capital, either externally or internally. Also, any PPA extension can
serve to bridge us to a time when supply and demand shift in our favor.
In the short term, we have focused on mitigating our downside risk through aggressive debt and
cost management, which also buys us time to be patient on PPA renewals and asset sales. If the power
markets remain low, we can mitigate the impact on our cash flow from expiring PPAs through cost
reductions. For example, in 2016 we had $60 million of Project Adjusted EBITDA1 from projects with
PPAs that are scheduled to expire through 2020. We believe we can offset approximately half of that
potential reduction in cash flow from cost and interest expense reductions in a worst-case scenario in
which none of these PPAs is renewed. We expect to continue to pay down debt in this scenario. We
would end up with lower EBITDA but also with lower leverage at an acceptable level for this business.
In addition, we still would have good value in the post-PPA periods for our hydro and other
strategically well positioned assets, as Joe Cofelice outlined on our March conference call. This is a
long-slog scenario. It is not our base case. The point is that despite a challenging PPA environment, we
believe that our work on debt and costs has positioned us to endure an extended down cycle. Looking
at it like owners of a family business, we believe we have removed the risk of falling over a cliff and
now we have the ability to protect our legacy assets.
Base Case:
In the Base Case scenario, we assume power curves that are higher than current levels but lower
than they were just a year ago. We don’t assume that all of our gas and biomass plants are recontracted
when their PPAs expire, and we assume a significant reduction in EBITDA from those that are
recontracted. For example, we do not assume that any of our assets in Ontario are recontracted, and
we assume a significant EBITDA reduction from our San Diego projects if they are recontracted. We
also make assumptions with respect to the terminal values of our assets at a point well into the future.
The most significant component of our terminal value is our hydro facilities, which we expect will have
strong cash flow after their PPAs expire. Based on transaction multiples for other hydro assets and their
long remaining lives, these plants have significant long-term value.
In this Base Case scenario, our estimate of intrinsic value is higher than in the Lower for Longer
scenario above. In both scenarios, our estimates of intrinsic value are higher than our share price is
today.
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Reflation:
As I noted above, a move in the forward curves shifts the intrinsic value of the Company
significantly because of the impact on estimated cash flows post-PPA and estimated terminal values for
the hydro facilities. Thus, a significant increase in power prices above our Base Case assumption would
add significant value to our Base Case estimate of intrinsic value, which is already above our current
share price. We don’t control power prices, so the key upside driver to the Base Case is largely outside
our control. We can protect against downsides to the best of our ability but we cannot assure higher
prices for power going forward.
Our job has been to insure that we can endure a Lower for Longer scenario and to be around to
profit from a Reflation scenario should it occur, while maximizing the intrinsic value of our shares by
aggressive cost and debt management in the Base Case.
External Growth Strategy
We have been reticent on external growth for the past two years for four reasons. First, we needed
to focus on mitigating downside risks. Second, we thought the internal or organic uses of capital had
higher returns than what was available externally due to where the markets were pricing assets. This
was an owner-oriented decision to maximize the per share value of the business rather than trying to
grow in terms of absolute size. It was the result of trying to be as rational as possible about capital
allocation and market prices. Third, our financial and human resources had to be focused on
restructuring. Lastly, we have been investing in power markets for more than three decades and our
experience is that this is a sector with tough economics for buy-and-hold investors. We try to sit on the
sidelines until we see compelling opportunities based on conservative return estimates in areas within
our circle of competence. Charlie Munger calls this ‘‘sit on your ass’’ investing. Do nothing with your
capital until the odds are definitely in your favor rather than attempting to be in the market all the
time. When you find a good opportunity that you understand, then move quickly and decisively. This
isn’t the ideal profile for an investment fund seeking institutional investors. Given the small size and
underfollowed nature of Atlantic Power, we have the luxury of being patient, i.e., even if we made lots
of promises, they would be greeted with skepticism anyhow.
In the past as a management team we have invested in qualifying facilities (QFs), merchant
combined-cycle gas turbines (CCGTs), wind, biomass, solar, and energy services businesses. Although
growth in wind and solar installations in North America has been dramatic, the financial results have
been mixed. Meanwhile, U.S. utilities are being buffeted by public policy on things like rooftop solar
and extremely weak or declining electric demand growth for their remaining customers. The IPP model
of selling to utilities under long-term PPAs is battered, if not broken.
Morris was our first significant PPA renewal in several years. The run rate EBITDA contribution
under the PPA extension with our industrial customer is more attractive than what we have seen from
utilities. Understand, though, that the existing PPAs provide for a return of and on our capital to
finance construction. Interest rates were much higher when they were signed. From a customer
standpoint, our original investment in the plants has been recovered, and therefore the cost of power
from our plants should be lower on a renewal. However, for some of our plants, an extension of the
PPA will require that we make incremental investment in the plant. We will require good returns on
this incremental investment or we won’t do these deals.
The larger point is that in the United States, the high penetration rate of intermittent power
sources has kept retail rates (end-user prices) high at the same time that wholesale power prices have
declined by 40% or so in some cases. Therefore, we have shifted our focus toward the industrial
markets. We are working with industrial customers at our existing facilities to provide them low-cost,
reliable, clean power. We also have begun to seek new plant opportunities with other industrial
customers. We think this makes sense based on the current structure of the power markets, and it is a
market segment that is well within our core competencies. Additionally, the investments are of a size
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that will attract less interest from the large IPP players, but which can move the needle for Atlantic
Power. We have begun to allocate some of our people in this direction, and as we proceed we may add
some development expense that would be very modest in 2017. We will be putting in mostly sweat
equity at this point. Depending on how things evolve, we ought to be able to give a more specific
update at the end of the year.
When we worked together previously, Joe Cofelice and I were able to capture $160 million of
value from private transactions by growing off a much smaller capital and resource base than we have
at Atlantic Power. This isn’t a forecast, but the point is that here we have adequate resources and
experience to grow this business. If we are successful, we then would have a fourth case, Growth, to go
along with the other cases. It is too early to make any promises on this front but we are very
enthusiastic about this effort.
Let me conclude this part of the letter with my thoughts on what keeps us up at night and what
might go right.
What Might Go Wrong
Experienced investors often ask managements what might go wrong or what keeps them up at
night. With two boys away at school now, I naively assumed there would be fewer nights worrying
about them, but I have learned there are more sleepless nights when you can’t hug them before
heading off to bed. But this is not the answer investors are seeking.
Our greatest concern is the Lower for Longer scenario discussed above. Low gas prices, high
subsidies for intermittent sources of power pressuring the value of conventional and more reliable
power sources, lack of public policy support for gas plants necessary to keep costs to consumers at
reasonable levels, and the utility business model (to date the major customer for our business) under
attack from similar forces all have caused power prices to fall significantly. Simultaneously, low interest
rates have reduced buyer discount rates, allowing them to pay high prices for assets backed by
longer-term PPAs (typically intermittent sources of power).
At some point higher consumer and industrial rates are likely to cause a shift to more balanced
public policy, but as Maggie Thatcher said, ‘‘Nothing is more obstinate than a fashionable consensus.’’
At Atlantic Power, we are very focused on being good stewards of the environment. In my opinion,
public policy should recognize natural gas as a major source of clean energy that can be provided at
low cost—a balancing of competing needs that is not generally achieved by intermittent sources of
power. Instead, public policy in North America and Europe is highly supportive of continuing to add
intermittent sources of power while not adequately compensating the more flexible power sources
necessary to support the grid.
In addition to a low power price and low interest rate environment, we may be in a deflationary
manufacturing environment. Large amounts of debt in the United States and globally have a
deflationary impact (I majored in history, not economics, so take this with a grain of salt). Companies
such as General Electric and IBM are delivering advances in information technology to the plant level
that reduce costs. Much of the reduction in solar costs is driven by overcapacity in China, where
market forces are less capable of allocating resources. Advances in gas, wind, nuclear, and solar
technologies as well as fracking technology are all driving costs down. Low interest rates are abetting
capacity additions in already oversupplied markets. Companies do not like to reduce their size, so
supply reductions tend to come much more slowly than the forecasts would have you believe. Making
decisions on the expectation that energy producers will act rationally on capacity additions and
retirements oftentimes leads to very expensive mistakes.
However, even in this Lower for Longer scenario, we expect to be able to repay our debt maturing
in 2019 (convertible debentures) and 2023 (term loan). If power prices do not rebound during this
period, we would have materially lower Project Adjusted EBITDA, although the impact on our
operating cash flow would be less because of reductions in interest expense and corporate overheads.
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We would have much lower debt (consisting of the medium term notes maturing in 2036 and a very
modest amount of project debt). Most of the EBITDA would be from the remaining PPAs and our
hydro plants, while uncontracted gas plants would have option value.
We do not believe our shares are discounting any meaningful recovery in power prices, much
success in extending PPAs, or any success on the growth front. Instead, they appear to be discounting
the Lower for Longer case, or perhaps worse. This is why the Company repurchased nearly $20 million
of shares last year.
What Might Go Right
To elaborate a bit on the scenarios laid out earlier, there is a reasonable chance that coal and
nuclear retirements, a shift in public policy, changes in supply and demand dynamics, or normal market
volatility will provide us with opportunities to add to our Base Case valuation with improved results on
PPA extensions (more extensions, or extensions on better terms) or asset hedges. In addition, based on
our history of successfully growing IPP businesses, we think we can once again create significant value
this way. If we get either outcome, our estimate of intrinsic value, which is already above the current
share price, is likely to increase. If we get both outcomes, we would expect to see material upside to
the value of our business.
At some point our shares might trade above intrinsic value. We have noted that we are a buyer at
current prices, as they are below our estimates of intrinsic value. If our shares were trading at a
premium to our estimates, we would stop buying them and reallocate the cash to debt reduction and
growth initiatives. That share price might not fully value the upside cases discussed in this paragraph,
but they might be sufficiently valued relative to market conditions such that we would consider risk
reduction via debt repurchases as a better use of capital. The point is that we are focused on intrinsic
value per share. At the price range in which the shares have traded since I joined the Company two
years ago, we have viewed them as undervalued, but at another price we would cease repurchase and
allocate capital to other uses, and at a still higher price we would issue shares to support growth or to
further strengthen the balance sheet. Whether we are a buyer or a seller of assets or securities is
dependent on formulating our best estimates of intrinsic value and taking a disciplined approach on
price-to-value.
REVIEW OF 2016 OPERATING AND FINANCIAL RESULTS
Our plants performed well in 2016. We achieved average fleet availability of 93%, slightly lower
than the 95% level of 2015, with the decrease primarily attributable to an extensive planned
maintenance outage at our Morris plant. We also continued to prioritize the safety of our operations
personnel and our plants. Our 2016 total recordable incident rate was well below the industry average
for power generation companies.
We reported Project Adjusted EBITDA of $202.2 million, which was $6.7 million lower than the
2015 level of $208.9 million. The decrease was attributable to the Morris outage, lower water flows at
our Curtis Palmer hydro facility, and a decrease at our Ontario plants that was the result of several
factors, including lower waste heat. In addition, there was a modest negative impact on EBITDA from
the stronger U.S. dollar, but this was non-cash. These negative factors were partially offset by an
increase at our Manchief plant, which had a scheduled gas turbine maintenance outage in 2015, and an
increase at our Mamquam hydro facility, which had higher water flows in 2016.
Project Adjusted EBITDA results were approximately $3 million below the lower end of our 2016
guidance range of $205 to $215 million, primarily because of the lower water flows at Curtis Palmer
and lower waste heat (both of which are typically budgeted at average levels) and severance expense at
three of our Ontario plants that was incurred due to revised contractual and operating arrangements
that became effective at year-end 2016.
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Cash provided by operating activities of $111.8 million increased $24.4 million from the 2015 level
of $87.4 million. The increase was primarily attributable to lower cash interest payments resulting from
debt reduction in 2015 and 2016, a favorable change in other operating balances and a reduction in
corporate overhead expense. These positive factors were partially offset by lower Project Adjusted
EBITDA and the loss of $21.9 million of operating cash flow from the Wind businesses, which we sold
in June 2015.
Approximately $96.5 million, or 86%, of our cash provided by operating activities in 2016 was used
to pay down our term loan and amortize project-level debt.
PROGRESS REVIEW—TURNAROUND EFFORTS
In last year’s letter I discussed our progress in three important areas: reducing our overhead costs,
lowering our interest expense, and making smart decisions on capital allocation. We made further
progress in 2016, as follows:
Overhead cost reduction. Last year, I said that we expected to reduce overhead costs another
$5 million in 2016, but we exceeded this target by $4 million. Total overhead costs declined by
$9 million, or 28%, to $23 million in 2016 from $32 million in 2015. Since 2013, we have reduced these
costs by $31 million, or 58%.
Successful refinancing.
In April 2016, we refinanced our $448 million term loan facility and
$210 million revolving credit facility. Despite difficult market conditions, we were able to increase the
size of the term loan to $700 million and gain flexibility on the terms of the $200 million corporate
revolver. The newer facilities have later maturity dates, thereby improving our debt maturity profile. As
discussed at the beginning of this letter, in April 2017 we closed on a repricing of this term loan and
revolver that will result in approximately $17 million of interest cost savings, net of transaction fees,
over the remaining lives of both facilities.
Debt reduction. Using the excess proceeds from the term loan refinancing, we redeemed both
series of 2017 convertible debentures at par in May 2016 and reduced the amount outstanding of our
2019 convertible debentures. Net of the refinancing, we reduced consolidated debt approximately
$22 million in 2016. Since 2013, we have reduced debt by approximately $880 million as a result of debt
amortization, discretionary debt repurchases, and asset sales. Our consolidated leverage ratio has
improved from 9.5 times at year-end 2013 to 5.6 times at year-end 2016. In our year-end 2016 financial
results release, we committed to repaying another $150 million or more of debt this year, which would
further improve our leverage ratio to approximately 4 times at year-end 2017.
Reduction in cash interest payments. The cumulative reduction in debt since 2013 has reduced
our annual cash interest payments by $60 million, or approximately 46%. Combined with overhead cost
reductions of $31 million, we have freed up $91 million of annual cash flow against an EBITDA of
slightly more than $200 million.
Ontario contract revisions.
In late 2016, we reached agreement with the OEFC, the customer for
our North Bay, Kapuskasing and Nipigon plants in Ontario on revised contractual arrangements for
these plants for 2017 (and in the case of Nipigon, continuing for most of 2018). Because the plants are
not currently needed to supply power, we have put them in a non-operational status. We expect these
actions to have a positive impact on our financial results in 2017 while also generating cost savings for
customers and achieving goals important to the Province.
Maintenance and optimization initiatives.
In 2016, we continued our program of making
attractive optimization investments in our fleet, completing a major scheduled outage at our Morris
plant, during which we upgraded two of the three gas turbines to increase output and improve
efficiency, and added fast-start capability to an auxiliary boiler. We also completed a spillway upgrade
to our Curtis Palmer facility to better manage ice in the water flows during the winter. From 2013
ix
through 2016, we invested $25 million in such optimization initiatives. These investments generated a
cash return of approximately $8 million, or 30%, in 2016, and a cumulative cash return of $19.5 million
since 2013. We expect the $8 million return to increase to $12 million in 2017.
Share repurchases. Based on our view that the share price represented a significant discount to
our estimates of intrinsic value per share, we allocated $19.6 million to share repurchases in 2016,
repurchasing and canceling approximately 8.1 million common shares (6.6% of shares outstanding) at
an average price of $2.42 per share.
Revised insider ownership policies. Management and directors purchased approximately
0.3 million shares at an average price of $2.32 per share in 2016, and since I joined the Company in
January 2015, insider purchases have totaled nearly 1.5 million shares at an average price of $2.32 per
share. The Company recently modified its share ownership policy to increase ownership requirements
of directors and officers and extended its application to include non-officer managers at the senior vice
president level.
In summary, let me reiterate what I said at the end of last year’s letter. We have done a lot of
work to maximize the value of our business across a market cycle by reducing interest payments and
overhead costs. We have put together a strong management team focused on building long-term value,
as it has in the past. We are focused on being as rational as possible and creating value through a
series of smart, smaller decisions punctuated by the occasional bold move. Thank you for your
investment in Atlantic Power Corporation, and thank you for your continued support. We look forward
to meeting those of you attending the Annual Meeting in Toronto on June 20 of this year.
21APR201521422407
James J. Moore, Jr.
President and Chief Executive Officer
April 28, 2017
1
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 loss on a consolidated basis is provided in
Annex A on page xiii.
x
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 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,’’ ‘‘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:
• the Company expects to generate cumulative interest savings, net of transaction fees, of
approximately $17 million through the maturity dates of the term loan and revolver;
• once the required amendment to Piedmont’s Title V air permit is resolved, the Company expects
to conclude its evaluation of whether to pursue a sale of this plant, or continue to own it and
either refinance the project debt, or pay it down using its liquidity;
• the Company expects that it would generate net proceeds in excess of the project debt
repayment that would add to the cash totals cited, if it were to sell Piedmont;
• the Company believes that its hydro assets have significant value beyond their PPA terms by
virtue of their low marginal costs and long remaining lives;
• the Company expects to have repaid more than 80% of its term loan by its maturity in 2023;
• in a worst-case scenario, in which none of the PPAs is renewed, the Company believes that it
can offset approximately half of the potential reduction in cash flow from cost and interest
expense reductions, and, in such a scenario, the Company would continue to pay down debt and
end up with lower EBITDA but also with lower leverage at an acceptable level for the business;
• the Company believes that its work on debt has positioned it to endure an extended down cycle;
• the Company estimates that its intrinsic value is higher than its share price today;
• even in the ‘‘Lower for Longer’’ scenario, the Company expects to be able to repay its debt
maturing in 2019 (convertible debentures) and 2023 (term loan);
• the Company has committed to repaying $150 million or more of debt in 2017, which would
improve its leverage ratio to approximately 4 times at year end 2017;
• the Company expects that its Ontario contract revisions will have a positive impact on its
financial results in 2017 while also generating cost savings for customers and achieving goals
important to the Province; and
• the Company expects its investments in its fleet to generate a $12 million cash return in 2017.
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 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. These factors include, without limitation, the
xi
outcome or impact of the Company’s business strategy to increase the intrinsic value of the Company
on a per-share basis through disciplined management of its balance sheet and cost structure and
investment of its discretionary cash in a combination of organic and external growth projects,
acquisitions, and repurchases of debt and equity securities; the Company’s ability to enter into new
PPAs on favorable terms or at all after the expiration of existing agreements, and the outcome or
impact on the Company’s business of any such actions. Although the forward-looking statements
contained in this letter 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. The Company’s ability to achieve its longer-term
goals, including those described in this letter, is based on significant assumptions relating to and
including, among other things, the general conditions of the markets in which it operates, revenues,
internal and external growth opportunities, and general financial market and interest rate conditions.
The Company’s actual results may differ, possibly materially and adversely, from these goals.
xii
ANNEX A
ATLANTIC POWER CORPORATION
RECONCILIATION OF NET LOSS (A GAAP MEASURE) TO PROJECT ADJUSTED EBITDA FOR
THE YEARS ENDED DECEMBER 31, 2016 AND DECEMBER 31, 2015 (UNAUDITED)
(in millions of U.S. dollars, except as otherwise stated)
2016
2015
Net loss attributable to Atlantic Power Corporation . . . . . . . . . . . . . . . . . . . . . . . .
Net income attributable to preferred share dividends of a subsidiary company . . . . .
Net loss attributable to noncontrolling interests . . . . . . . . . . . . . . . . . . . . . . . . . . .
($122.4)
8.5
—
($ 62.4)
8.8
(11.0)
Net loss
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss (income) from discontinued operations, net of tax . . . . . . . . . . . . . . . . . . .
($113.9)
—
($ 64.6)
(19.5)
Net loss from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss from continuing operations before income taxes . . . . . . . . . . . . . . . . . . . . . . .
Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign exchange loss (gain) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(113.9)
(14.6)
(128.5)
22.6
106.0
13.9
(3.9)
(84.1)
(30.4)
(114.5)
29.4
107.1
(60.3)
(3.1)
Project income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 10.1
($ 41.4)
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in the fair value of derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (income) expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 133.5
10.9
(37.9)
85.9
(0.3)
$ 130.1
9.8
(15.4)
127.8
(2.0)
Project Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 202.2
$ 208.9
xiii
(This page has been left blank intentionally.)
26APR201113105954
FOLLOWING IS THE COMPANY’S ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2016
(This page has been left blank intentionally.)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(cid:95)
(cid:134)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2016
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 220
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 (cid:134) No (cid:95)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:134) No (cid:95)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes (cid:95) No (cid:134)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be
submitted and posted 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 and post such files). (cid:95) Yes (cid:134) 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. (cid:134)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the
definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer (cid:134)
Accelerated Filer (cid:95)
Non-Accelerated Filer (cid:134)
(Do not check if a
smaller reporting company)
Smaller reporting company (cid:134)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:134) No (cid:95)
As of June 30, 2016, the aggregate market value of the voting and nonvoting common equity held by non-affiliates of the registrant was $295.5 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 28, 2017, 114,649,888 of the registrant’s Common Shares were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for its 2017 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
17
39
40
40
40
41
44
46
83
86
86
86
88
88
88
88
89
89
90
94
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 New Credit Facilities (as defined herein) and
other indebtedness;
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.
These risks include, without limitation:
•
the expiration or termination of power purchase agreements (“PPAs”) and our ability to renew or enter into
new PPAs on favorable terms or at all;
1
•
•
•
•
•
•
•
•
•
•
•
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 New
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 or long-lived assets;
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;
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
2
•
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 owns and operates a diverse fleet of power generation assets in the United States and Canada.
Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term
PPAs, which seek to minimize exposure to changes in commodity prices. As of December 31, 2016, our power
generation projects had an aggregate gross electric generation capacity of approximately 2,138 megawatts (“MW”) in
which our aggregate ownership interest is approximately 1,500 MW. Our current portfolio consists of interests in
twenty-three power generation projects across nine states in the United States and two provinces in Canada. Nineteen of
the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337 MW on a net ownership
basis. The remaining four projects, all in Ontario, are not operational, three due to revised contractual arrangements with
the offtaker and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence
between November 2017 and June 2019. Eighteen of our projects are majority-owned.
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 December 31, 2017 (the PPAs for
our Kapuskasing and North Bay projects, which are not currently in operation) to December 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 majority of our natural gas, coal and biomass power generation projects have long-term fuel supply
agreements, typically accompanied by fuel transportation arrangements. In most cases, the term of the fuel supply and
transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales
agreements provide for the indexing or pass-through of fuel costs to our 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.
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 Colorado
Energy Management (“CEM”) and Power Plant Management Services (“PPMS”). 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
4
November 2004 to acquire a 58% interest in Atlantic Power Holdings, LLC (now Atlantic Power Holdings, Inc., 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 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 through disciplined
management of our balance sheet and our cost structure and investment of our discretionary cash in a combination of
organic and external growth projects, acquisitions, and repurchases of our debt and equity securities. In evaluating these
potential investments we are guided by the price-to-value relationship. With respect to organic growth, we have been
making optimization investments 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. We evaluate external growth opportunities on a regular basis, and have a highly disciplined
and opportunistic approach. We will use discretionary cash for repurchases of our debt and equity securities only when
the price-to-value level is compelling, with a goal of increasing intrinsic value per share while also improving the
Company’s financial flexibility and strengthening its balance sheet. We use our depth of asset management experience to
enhance the operating, contractual and financial performance of our current portfolio of projects.
In 2016, we successfully executed on several key initiatives. As a result of prior-year consolidation of our
corporate operations to a single location, a continued focus on prudent cost cutting and reductions in our workforce, we
lowered our corporate overhead expenses from $54 million in 2013 to $23 million in 2016. In April 2016, we refinanced
our term Loan Facilities in order to provide greater financial flexibility, fund the repurchase and cancellation of our
convertible debentures with near-term maturities and improve our debt maturity profile. We continued to amortize our
corporate and project-level debt with approximately $97 million of principal payments and decreased our cash interest
payments from $100 million in 2015 to $71 million in 2016.
5
We have also made significant internal investments in order to increase intrinsic value per share. We invested
approximately $25 million in our existing fleet in 2013 through 2016 and realized a cash return on these investments of
approximately $7.8 million in 2016, which is expected to grow to approximately $12 million in 2017. In 2016, we
purchased and cancelled approximately 8 million common shares at a cost of $19.5 million with our discretionary capital
with a goal of capturing value arising from favorable price-to-value opportunities in the market.
Extending PPAs following their expiration
PPAs in our portfolio have expiration dates ranging from December 31, 2017 to December 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. Our projects may not be able to secure a new
agreement and could be exposed to selling power at spot market prices. It is possible that subsequent PPAs or the spot
markets may not be available at prices that permit the operation of the project on a profitable basis. 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.” 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.
Organic growth
We intend to look for opportunities to enhance the operational and financial performance of our projects
through:
•
•
•
achievement of improved operating efficiencies, output, reliability and operation and maintenance costs
through the upgrade or enhancement of existing equipment or plant configurations;
optimization of commercial arrangements such as PPAs, fuel supply and transportation contracts, steam
sales agreements, operations and maintenance agreements and hedging arrangements; and
to the extent we have sufficient cash flow or are able to obtain financing, the expansion or redevelopment
of existing projects, or development of new long-term contracted plants with industrial customers.
Acquisition and investment strategy
To the extent we pursue acquisitions, we intend to expand our operations by making accretive acquisitions with
a focus on power generation facilities in the United States and Canada. We may also work with experienced
development companies to acquire additional late stage development projects. There is also a very active secondary
market for the purchase and sale of existing projects.
Development and construction
We have invested and may invest in the future in energy-related projects primarily in the electric power
industry, including investments in late stage development projects or companies where the prospects for creating
long-term cash flows are attractive. We may also to seek new plant opportunities with other industrial customers. We
believe this approach makes sense based on the current structure of the power markets and it is a market segment that is
within our core competencies.
6
OUR COMPETITIVE STRENGTHS
We have the following competitive strengths:
• Diversified projects. Our power generation projects in operation have an aggregate gross electric
generation capacity of approximately 1,975 MW, and our net ownership interest in these projects is
approximately 1,337 MW. These projects are diversified by fuel type, electricity and steam customers,
technologies, project operators and geography. The majority are located in California, the U.S.
Mid-Atlantic, New York 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 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
nineteen operating power generation projects, which represent 64% of our portfolio’s total generating
capacity. The remaining five generation projects are operated by third parties, which are recognized leaders
in the independent power business.
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 nineteen operating plants. Our asset management group works to ensure that our
projects receive appropriate preventative and corrective maintenance and incur capital expenditures to provide for their
safety, efficiency, availability, flexibility, longevity, and growth in EBITDA contribution. We also proactively look for
opportunities to optimize power purchase, fuel supply, long-term service and other agreements to deliver strong and
predictable financial performance. The teams at each of the businesses have extensive experience in managing, operating
and maintaining the assets.
For operations and maintenance services at the five projects in our portfolio which we do not operate, we
partner with experienced operators in the independent power business. Examples of our third-party operators include
CEM and PPMS, 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 February
28, 2017, including our interest in each facility. We believe our portfolio is well diversified in terms of electricity and
steam buyers, 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. We revised our
reportable business segments in the second quarter of 2015 as a result of significant asset sales and in order to align with
changes in management’s structure, resource allocation and performance assessment in making decisions regarding our
7
operations. Our financial results for the year ended December 31, 2014 have been presented to reflect these changes in
operating segments. These changes reflect our current operating focus. 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.
See Note 22 to the consolidated financial statements for information on revenue from external customers,
Project Adjusted EBITDA (a non-GAAP measure), total assets by segment and revenue and total assets by geography.
East U.S. Segment
Our East U.S. segment accounted for 33.7%, 35.7% and 34.1% of consolidated revenue in 2016, 2015 and
2014, respectively, and total net generation capacity of 592 MW at December 31, 2016. Niagara Mohawk Power
Corporation, Equistar Chemicals, LP and Georgia Power Company each accounted for 8% of total consolidated
revenues, respectively, and 24%, 23% and 23% of total revenues from the East U.S. segment, respectively, for the year
ended December 31, 2016.
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).
East U.S. Segment
Project income
($ in millions)
Revenue
($ in millions)
$
134.5 $
150.0
167.1
31.2
38.7
8.7
2016
2015
2014
Set forth below is a list of our East U.S. projects in operation:
Gross Economic Net
Project
Orlando(1)
Piedmont
Morris
Cadillac
Chambers(1)
Location
Florida
Georgia
Illinois
Fuel
Natural Gas
Biomass
Natural Gas
Michigan
New Jersey
Biomass
Coal
Kenilworth
Curtis Palmer(4)
Selkirk(1)
New Jersey
New York
New York
Natural Gas
Hydro
Natural Gas
MW Interest
129
55
177
40
262
29
60
345
50.00 %
100.00 %
100.00 %
100.00 %
40.00 %
100.00 %
100.00 %
17.70 %
MW
65
55
120
57
40
89
16
29
60
61
Primary Electric Purchasers
Progress Energy Florida
Georgia Power
Merchant
Equistar Chemicals, LP(2)
Consumers Energy
Atlantic City Electric (3)
Chemours Co.
Merck & Co., Inc.
Niagara Mohawk Power Corporation
Merchant
Power
Contract
Expiry
December 2023
December 2032
N/A
December 2034
December 2028
December 2024
December 2024
September 2018
December 2027
N/A
Customer
Credit
Rating
(S&P)
A-
A-
NR
BBB+
BBB
BBB+
BB-
AA
A-
NR
(1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated
affiliates.
(2) Represents the credit rating of LyondellBasell, the parent company of Equistar Chemicals, as Equistar is not rated.
(3) The base PPA with Atlantic City Electric (“ACE”) makes up the majority of 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.
(4) 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, 2016, the facility has generated 6,956 GWh under its PPA. Based on
cumulative generation to date, we expect the PPA to expire prior to December 2027.
8
West U.S. Segment
Our West U.S. segment accounted for 25.4%, 24.9% and 25.2% of consolidated revenue in 2016, 2015 and
2014, respectively, and total net generation capacity of 592 MW at December 31, 2016. San Diego Gas & Electric
provided for 11% of total consolidated revenues and 43% of total revenues from the West U.S. segment for the year
ended December 31, 2016.
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
Project income (loss)
Revenue
($ in millions)
$
101.3 $
104.6
123.6
($ in millions)
11.8
7.6
(27.6)
2016
2015
2014
Set forth below is a list of our West U.S. projects in operation:
Gross Economic Net
Location
California
Fuel
Natural Gas
MW Interest
100.00 %
MW
47
Primary Electric Purchasers
San Diego Gas & Electric(1)
Project
Naval Station
Naval Training
Center
North Island
Oxnard
Manchief
Frederickson(2)
California
California
California
Colorado
Washington
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
47
25
40
49
300
250
100.00 %
100.00 %
100.00 %
100.00 %
50.15 %
25
40
49
300
50
45
30
6
San Diego Gas & Electric(1)
San Diego Gas & Electric(1)
Southern California Edison
Public Service Company of Colorado
Benton Co. PUD
Grays Harbor PUD
Franklin Co. PUD
Puget Sound Energy
December 2019
December 2019
May 2020
April 2022
August 2022
August 2022
August 2022
December 2037
Customer
Credit
Rating
Power
Contract
Expiry
December 2019
(S&P)
A
A
A
BBB+
A-
AA-
A+
A+
BBB
Koma Kulshan(2)
Washington
Hydro
13
49.80 %
(1) Our land use license agreements with the U.S. Navy expire on February 8, 2018. Our PPAs with San Diego Gas &
Electric expire on December 31, 2019. If we are unable to extend our land use license agreements through the end of
our PPAs, we will not be able to operate these plants beyond February 8, 2018 and could be subject to potential
liabilities under our PPAs. For a description of the status of these agreements and related renegotiations, see Item
1A. Risk Factors - The expiration or termination of our PPAs could have a material adverse impact on our
business, results of operation and financial condition.
(2) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated
affiliates.
Canada Segment
Our Canada segment accounted for 40.7%, 39.2% and 40.5% of consolidated revenue in 2016, 2015 and 2014,
respectively, and total net generation capacity for operational projects of 193 MW at December 31, 2016. Ontario
Electric Financial Corporation (“OEFC”) and British Columbia Hydro and Power Authority (“BC Hydro”) provided for
29% and 12% of total consolidated revenues, respectively, and 72% and 28% of total revenues from the Canada
segment, respectively, for the year ended December 31, 2016.
9
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
2016
2015
2014
Set forth below is a list of our Canada projects in operation:
Project (loss) income
Revenue
($ in millions)
$
162.5 $
164.7
198.3
($ in millions)
(35.7)
(85.7)
(10.5)
Gross Economic
MW Interest
Net
MW Primary Electric Purchasers
Project
Mamquam
Moresby Lake
Williams Lake
Calstock
Kapuskasing
Nipigon
North Bay
Tunis
Location
British Columbia
British Columbia
British Columbia
Ontario
Ontario
Ontario
Ontario
Ontario
Fuel
Hydro
Hydro
Biomass
Biomass
Natural Gas
Natural Gas
Natural Gas
Natural Gas
50
6
66
35
40
40
40
40
100.00 %
100.00 %
100.00 %
100.00 %
100.00 %
100.00 %
100.00 %
100.00 %
50
6
66
35
40
40
40
40
BC Hydro
BC Hydro
BC Hydro
OEFC
OEFC
OEFC
OEFC
IESO
Power
Contract
Expiry
September 2027
August 2022
March 2018
June 2020
December 2017(1)
December 2022(2)
December 2017(1)
(3)
Customer
Credit
Rating
(S&P)
AAA
AAA
AAA
AA
AA
AA
AA
AA
(1)
(2)
(3)
In December 2016, we entered into agreements to terminate our PPAs originally scheduled to expire on December
31, 2017. Additionally, we entered into Enhanced Dispatch Contracts with the Independent Electricity System
Operator (“IESO”), which provide a fixed monthly payment to the plants until December 31, 2017. The contracts
have no delivery obligations and allow us to retain operating flexibility. Based on our assessment of
the Ontario power market, including the estimated impact on plant economics, we do not expect to operate the
plants during the term of the Enhanced Dispatch Contracts or subsequent to their expiration.
In December 2016, we entered into an Enhanced Dispatch Contract with IESO. The Enhanced Dispatch Contract
for Nipigon provides fixed monthly payments to that plant through October 31, 2018. During that period, the plant's
PPA with the OEFC will be suspended. At the conclusion of that period, the arrangement will revert to the existing
terms of the PPA. We do not expect Nipigon to be operational through October 31, 2018.
In December 2014, we entered into an agreement with the Ontario Power Authority and its successor, the IESO for
the future operations of the Tunis facility. Subject to meeting certain technical requirements, Tunis will operate
under a 15-year agreement with the IESO commencing between November 2017 and June 2019. The new
agreement provides the Tunis project with a fixed monthly payment which escalates annually according to a pre-
defined formula while allowing it to earn additional energy revenues for those periods during which it operates. For
a further description of the status of these agreements and related renegotiations, see Item 1A. Risk Factors - The
expiration or termination of our PPAs could have a material adverse impact on our business, results of operation
and financial condition.
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”) 2016 Long-Term Reliability
Assessment (“LTRA”), published in January 2017, the 10-year forecast compound annual growth rate of the peak
summer and winter electricity demand has trended downward to the lowest rates on record. The LTRA reference case
shows a compound annual growth rate of 0.73% and 0.72% for the summer and winter seasons, respectively. This is a
10
decline from 0.99% and 0.92%, respectively, in the 2015 LTRA. The declining growth rates are expected to continue
with the increase in energy efficiency and conservation programs as well as the continued growth of distributed solar and
other storage sources.
Despite low projected demand growth, reserve margins are trending down. 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 this year as the predominant fuel source for electric generation and is the leading fuel type for capacity
additions.
Non-utility power generation
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. Our 23 power generation projects are non-utility electric generating facilities in the North
American electrical power generation industry, 19 of which are currently in operation. The electric power industry is one
of the largest industries in the United States, generating retail electricity sales of approximately $351 billion though
November 2016, based on information published by the Energy Information Administration. A growing 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
2016. 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.
Competition
The power generation industry is characterized by intense competition, and we compete with utilities, industrial
companies, yield companies and other independent power producers. Historically low crude and natural gas prices as
well as decreased demand 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.
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.
11
Generating projects
United States
Thirteen of our power generating projects are QFs under the Public Utility Regulatory Policies Act of 1978, as
amended (“PURPA”), and FERC regulations. A QF falls into one or both of two primary classes, both of which would
facilitate one of PURPA’s goals to more efficiently use fossil fuels to generate electricity than typical utility plants. The
first class of QFs includes energy producers that generate power using renewable energy sources such as wind, solar,
geothermal, hydro, biomass or waste fuels. The second class of QFs includes cogeneration facilities, which must meet
specific fossil fuel efficiency requirements by producing both electricity and steam versus electricity only.
The generating projects with QF status and which 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. All of our projects are also subject
to reliability standards developed and enforced by the North American Electric Reliability Corporation (“NERC”).
NERC is a not-for-profit regulatory authority whose mission is to assure the reliability and security of the bulk power
system in North America.
Pursuant to its authority, NERC has issued, and the FERC has approved, a series of mandatory reliability
standards. Users, owners and operators of the bulk power system can be penalized significantly for failing to comply
with the FERC-approved reliability standards. We have designated our Manager of Operational and Regulatory
Compliance to oversee compliance with reliability standards and an outside law firm specializing in this area advises us
on FERC and NERC compliance, including annual compliance training for relevant employees.
British Columbia, Canada
The vast majority of British Columbia’s power is generated or procured by BC Hydro. BC Hydro 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) and is 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 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.
12
The BCUC has adopted the standards developed by NERC as being applicable to, among others, all generators
of electricity in British Columbia, including independent power producers. In addition, the BCUC has adopted a number
of other standards, including the Western Electricity Coordinating Council (“WECC”) standards. As a practical matter,
WECC typically administers standards compliance on the BCUC’s behalf.
The Clean Energy Act (the “Clean Energy Act”), which became law in 2010, sets out British Columbia’s
energy objectives. This 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.
The Government of British Columbia released in April 2016 the Clean Energy Production in B.C.: An inter-Agency
Guidebook for Project Development, which is consistent with the Clean Energy Act and favors clean and renewable
energy sources such as waterpower, windpower and ocean energy generation. BC Hydro is required to meet these
objectives and submit reports to the BCUC updating on its progress.
Other provincial regulators in British Columbia having authority over independent power producers include the
British Columbia Safety Authority, the Ministry of Environment and the Integrated Land Management Bureau.
Ontario, Canada
In Ontario, the Ontario Energy Board (“OEB”) is an administrative tribunal with overall responsibility for the
regulation and supervision of the natural gas and electricity industries in Ontario and with the authority to grant or
renew, and set the terms for, licenses with respect to electricity generation facilities, including our projects.
No person is permitted to own or operate large or medium-scale electricity generation facilities in Ontario
without a license from the OEB.
The OEB’s general functions include:
• Determination of the rates charged for regulated services in the electricity sector;
• Licensing of market participants;
•
Inspections, particularly with respect to compelling production of records and information;
• Market monitoring and reporting, including on anti-competitive practice;
• Consumer advocacy; and
• 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 IESO, Hydro One, the Electrical Safety Authority (“ESA”) and OEFC.
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
13
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. IESO is accountable to NERC and
NPCC for compliance with NERC and NPCC reliability standards. While 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 is changing 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. Although we are not
presently party to any such contracts, we may seek to enter into such contracts if and when the opportunity arises.
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 Independent Electricity System Operator, or “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 and
plans to sell up to 60% in the future year.
The Green Energy Act became law in Ontario in 2009 for renewable electricity generation technologies,
including via a feed-in tariff program. This Act states that the Government of Ontario is, among other things, committed
to fostering the growth of renewable energy projects, to removing barriers to and promoting opportunities for renewable
energy projects and to promoting a green economy. From 2009 to 2013, power purchase contracts in respect of large-
scale energy projects were awarded under a feed-in-tariff program. The Government of Ontario has announced that
going forward, power purchase contracts for large-scale projects will be awarded through a request for qualifications
(RFQ)/request for proposals (RFP) process.
Carbon emissions
In the United States, during the past several years government action addressing carbon emissions has been
focused on the regional and state level. 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. In February 2013, RGGI released an updated model rule that
reduced the regional CO2 budget beginning in 2014, with further reductions each year from 2015 to 2020. The one RGGI
state where we have project interests, New York, also provides cost mitigation for independent power projects with
certain types of power contracts. 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 and SB 1368. Under AB 32 (the Global Warming
Solutions Act), 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 reduce state wide emissions of greenhouse gases to 1990 levels
by 2020. 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.
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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 for 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, such as our North Island project.
The U.S. Environmental Protection Agency (the “EPA”) has taken several recent 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,
which was required beginning in 2011, and its issuance in May 2010 of its final Prevention of Significant Deterioration
and Title V Greenhouse Gas Tailoring Rule, which under a phased-in approach requires large industrial facilities,
including power plants, to obtain permits to emit, and to use best available control technology to curb emissions of,
greenhouse gases. In addition, in August 2015, the EPA issued its final rule regulating carbon emissions from existing
electric generating units, which is referred to as the Clean Power Plan. Implementation of the Clean Power Plan
(emission reductions for existing coal and natural gas-fired power plants would be implemented by the states, or by the
EPA in any states that fail to act by specified deadlines) was scheduled to begin in September 2016. However, on
February 9, 2016, the United States Supreme Court ruled that the EPA could not begin implementation of the Clean
Power Plan while the rule is being challenged by 29 states and various corporations and industry groups in the United
States Courts of Appeals for the District of Columbia. A Court of Appeals decision is likely in the first half of 2017,
after which it is likely that the case will be considered by the Supreme Court. While President Trump has indicated an
interest in revoking Obama era climate regulations, it remains unclear at this time if the new U.S. presidential
administration will implement, modify or repeal the regulations described above.
In Canada, the federal government and the provincial governments of British Columbia and Ontario have
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 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, under which all Canadian jurisdictions are to have carbon pricing in place by 2018. Under the
federal approach, the provinces and territories can put a direct price on carbon pollution or they can adopt a cap-and-
trade system. While the direct price on carbon pollution has been stated by the federal government to begin at a
minimum of $10 per tonne in 2018 and rise by $10 a year to reach $50 per tonne in 2022, the details remain to be
determined. The requirements for provinces and territories choosing a cap-and-trade system also remain to be
determined; however, it seems likely that the existing cap-and-trade program in Ontario will satisfy the federal
requirements.
The Government of British Columbia has enacted a number of significant pieces of climate action legislation
that frame British Columbia’s approach to reducing greenhouse gas emissions with the goal of supporting its
participation in the emerging low-carbon economy.
One key piece of legislation is the Greenhouse Gas Reduction Targets Act (“GGRTA”), which came into force
in 2008 and sets legislated targets for the reduction of greenhouse gas emissions in British Columbia. Using 2007 as a
base year, GGRTA (along with related Ministerial Orders) requires that emissions must be reduced by a minimum of
18% by 2016, 33% by 2020 and 80% by 2050. Also required in connection with GGRTA are (from 2010 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.
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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.
Ontario has a new Quantification, Reporting, and Verification of Greenhouse Gas Emissions Regulation O.
Reg. 143/16 under the Climate Change Mitigation and Low-carbon Economy Act, 2016 (the “Ontario Cap and Trade
Act”) which applies after January 1, 2017. Ontario’s reporting rules require a report for all facilities which release
10,000 Tonnes CO2eq or more per year to be made using Environment Canada’s Single Window System. For 2014 (the
last year for which emission reports had been published at the beginning of 2017), each of the four natural gas powered
generating facilities in Ontario reported emissions in excess of 90,000 Tonnes of CO2eq (over 450,000 Tonnes of CO2eq
in total) on the federal registry.
In December 2015, Ontario, Manitoba and Quebec signed a Memorandum of Understanding signaling their
intentions to share information and link their cap-and-trade programs, which effort is expected to strengthen and expand
the coverage of the Western Climate Initiative.
In Ontario, facilities with annual GHG emissions of 25,000 tonnes or more are generally required by law to
participate in the Ontario cap-and-trade regime. However, under The Cap and Trade Program Regulation O. Reg.
144/16 (the “Cap and Trade Program”), facilities which primarily generate electricity using natural gas from a local
distributor are excluded from the mandatory registration requirements under the Ontario Cap and Trade Act and
participate in the Ontario Cap and Trade Program through the payment of the carbon price charged by the local natural
gas distributor on natural gas delivered after the end of 2016. While the details of arrangements for the recovery of these
additional costs had not yet been fully settled at the beginning of 2017, the IESO has stated generally that “the electricity
sector will see the cost of carbon reflected in the wholesale electricity price when natural gas-fired resources are on the
margin” and it is generally expected that most, if not all, of the incremental carbon price paid by generators to local
natural gas distributors will be recoverable by the generators under the applicable PPAs, which will have the effect of
making electricity generated from natural gas increasingly incrementally expensive over time.
Additionally, 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. Additionally, 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.
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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 GHG 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 beginning in 2023 (Article 4) and a transparency
commitment requiring a participating countries to disclose in full their progress (Article 13).
Both Canada and the United States have ratified the Paris Agreement, and it may result in additional regulations
to reduce carbon emissions in coming years. The NDC submitted by Canada included a 2030 target of 30% below 2005
levels, and the NDC submitted by the United States calls for reducing its net GHG emissions by 26-28% below 2005
levels by 2025. President Trump stated during the presidential campaign that he would withdraw the United States from
the Paris Agreement, but it remains unclear whether this will occur.
EMPLOYEES
As of February 28, 2017, we had 277 employees, 186 in the United States and 91 in Canada. Of our Canadian
employees, 35 and 24 are covered by collective bargaining agreements which will expire on December 20, 2017 and
December 31, 2018, respectively. During 2016, we did not experience any labor stoppages or labor disputes at any of our
facilities.
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. The public may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports,
proxy and information statements, and other information regarding issuers that file electronically with the SEC at
www.sec.gov. 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
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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. In particular, the $42.6 million aggregate principal
amount of our 5.75% convertible unsecured subordinated debentures is due June 2019 and the Cdn$81.0 million
aggregate principal amount of our 6.00% convertible unsecured subordinated debentures is due December 2019. 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.
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 New Credit Facilities, or through preferred dividends, may result in us not
retaining a sufficient amount of cash to finance growth and reinvestment opportunities, including 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 New 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. Currently,
because we no longer qualify as a “well-known seasoned issuer,” which previously enabled us to, among other things,
file automatically effective shelf registration statements, even if we were able to access the capital markets, any attempt
to do so could be more expensive or subject to significant delays. 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.
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Our New 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 New 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 New 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 New Credit Facilities include a requirement that Atlantic Power Limited Partnership
(the “Partnership”) and its subsidiaries maintain certain leverage and interest coverage ratios (each, as defined in the
credit agreement governing the New Credit Facilities (the “Credit Agreement”)). The New 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.
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:
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•
•
•
•
•
•
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, 2016, our consolidated long-term debt represented approximately 77% 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 78% of our debt, including our share of the project-level debt
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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, 2016, we had (i) no amount outstanding and $81.5 million issued in letters of credit under
our revolving credit facility, (ii) $102.9 million of outstanding convertible debentures, and (iii) $893.6 million of
outstanding New 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, with the exception of Piedmont, 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. Currently we do not expect
our Piedmont project to meet its debt service coverage ratio covenants or to make distributions before 2018 at the
earliest, due to higher than forecasted maintenance and fuel expenses than initially expected.
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 New 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 New 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
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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
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, or repay outstanding principal amounts under existing debt by issuing common shares. 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. We also have the option to convert our convertible debentures to common shares at their
respective maturity dates. 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. Currently, because we no longer qualify as a “well-known seasoned issuer,”
which previously enabled us to, among other things, file automatically effective shelf registration statements, even if we
were able to access the capital markets, any attempt to do so could be more expensive or subject to significant delays.
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.”
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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:
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general industry, economic and capital market conditions;
the availability of bank credit;
investor confidence;
our financial condition, performance and prospects as well as companies in our industry or similar
financial circumstances; and
changes in tax and securities laws which are conducive to raising capital.
Should future access to capital not be available to us, either as a result of market conditions or our financial
condition, we may not be able to service our debt obligations or finance internal or external growth opportunities, any of
which would adversely affect our business, results of operations and financial condition.
We have guaranteed the performance of some of our subsidiaries, which may result in substantial costs in the event
of non-performance
We have issued certain guarantees of the performance of some of our subsidiaries in certain situations, which
obligates us to perform in the event that the subsidiaries do not perform. In the event of non-performance by the
subsidiaries, we could incur substantial cost to fulfill our obligations under these guarantees. Such performance
guarantees could have a material impact on our business, results of operations, financial condition and cash flows. See
Notes 11 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 New Credit Facilities, the Partnership will be required to offer each electing lender to prepay such lender’s term
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loans under the New 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.
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 35%, 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 materially affect the after-tax cash available to distribute to us.
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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 analyzes 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.
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 50% of its
adjusted taxable income (generally, U.S. federal taxable income before net interest expense, net operating loss
carryovers, 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.
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. While 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. 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.
Additionally, the new U.S. presidential administration may make changes to fiscal and tax policies that may
adversely affect our business, as the new administration has called for changes to fiscal and tax policies, which may
include comprehensive tax reform. At the present time, it remains unclear, however, what specific changes may be
implemented. Though our business could be affected by these changes, we cannot, at the present time, predict the
impact, if any, that these changes may have on our business. It is likely that some policies adopted by the new
administration will benefit us and others will negatively affect us. Until we know what changes are enacted, we will not
know whether in total we benefit from, or are negatively affected by, the changes.
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,
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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 December 31, 2017 and December 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.”
Nine of our projects, representing 25% of our net MW and 30% of our 2016 Project Adjusted EBITDA, have
PPAs or other contractual arrangements that will expire within the next five years. These projects are Kapuskasing
(2017), North Bay (2017), Williams Lake (2018), Kenilworth (2018), Naval Station (2019), Naval Training Center
(2019), North Island (2019), Calstock (2020) and Oxnard (2020). There are no PPA expirations in 2021.
Recent developments affecting our Ontario projects
In January 2017, we announced changes to the operational status of and contractual arrangements for our
Kapuskasing, North Bay and Nipigon projects in Ontario, together representing 8% of our net MW and 14% of our 2016
Project Adjusted EBITDA. We agreed with the customer to terminate the PPAs at Kapuskasing and North Bay one year
ahead of the December 2017 expiration date. As part of this agreement, we signed Enhanced Dispatch Contracts which
are effective for 2017 that provide a fixed monthly payment to the projects through December 31, 2017. We have no
delivery obligations under the contracts, which allow us to retain operating flexibility. Based on our assessment of the
Ontario power market, we put these projects in a non-operational status. Although we will pursue new PPAs or other
contractual arrangements for these plants after 2017, there is no assurance that we will be successful.
We also signed an Enhanced Dispatch Contract for Nipigon that has a similar monthly payment schedule and
runs through October 31, 2018. During that period, the PPA for the project will be suspended. We have also put Nipigon
in a non-operational status. At the end of the term of the Enhanced Dispatch Contract, or later should that be agreed to,
the arrangement will revert to the existing terms of Nipigon’s PPA, which is scheduled to expire in December 2022.
Our other gas project in Ontario, Tunis, has not been operating since the expiration of its previous PPA in
December 2014. However, Tunis has a 15-year PPA executed in late 2014 that will commence between November 2017
and June 2019, at our option. We currently plan to return Tunis to service under the new PPA in 2018.
Recent developments affecting our San Diego projects
Three of our projects (Naval Station, Naval Training Center and North Island) representing 7% of our net MW
and 11% of our 2016 Project Adjusted EBITDA, have PPAs (“Existing PPAs”) with San Diego Gas & Electric that
expire in December 2019, although the steam sales agreements with the U.S. Navy for all three projects (“Navy
Agreements”) expire in February 2018. Production and sale of steam at certain minimum levels is a requirement for the
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projects to retain their QF status, which is a requirement of the Existing PPAs. The Navy Agreements also incorporate a
right to use the property on which the plants are located (on existing Naval or Marine bases).
We do not currently anticipate that the Navy will have a need for steam from these three projects after the Navy
Agreements end in February 2018. However, in February 2017, the Navy issued a request for proposals to provide
energy security and resiliency using the existing sites at Naval Station and North Island. We intend to respond to the
Navy solicitation, which if successful would provide us the right to use the property at the relevant facilities beyond
February 2018. However, there is no assurance that we will be successful in this solicitation or in obtaining the right to
use the property at the Naval Training Center site. If we do not reach new agreements with the Navy, the projects would
lose their QF status in February 2018 and we likely would also lose the right to use the property at that time. Under such
an outcome, we would be unable to operate one or more of these projects beyond February 2018, which could subject us
to potential liabilities under the early termination provisions of the Existing PPAs.
Concurrently, we are in negotiations with the existing offtaker for new PPAs at two of the three projects but
cannot provide any assurance that such negotiations will be successful. We expect that any new PPA for these or our
other San Diego project would not require these facilities to be QFs, but instead operate as EWGs that would no longer
provide steam to a third party such as the Navy. A new PPA would be conditioned upon, among other things, the
approval of the California Public Utilities Commission and execution of an agreement with the Navy allowing us use of
the property (see above). In any case, based on current market conditions we expect that any new PPAs, if successfully
executed, would result in a significant reduction in Project Adjusted EBITDA compared to the Existing PPAs.
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 2016, the largest customers of our
power generation projects, including projects recorded under the equity method of accounting, are Public Service
Company of Colorado, IESO, and San Diego Gas & Electric, which purchase approximately 20%, 13% and 11%,
respectively, of the net electric generation capacity 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
Those of our projects operating without a PPA or with PPAs 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
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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;
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.
We are also exposed to market power prices at the Selkirk, Morris and Chambers projects. At Chambers, our
utility customer has the right to sell a portion of the plant’s output into the spot power market if it is economical to do so,
and the Chambers project shares in the profits from these sales. In addition, during periods of low spot electricity prices
the utility takes less generation, which negatively affects the project’s operating margin. At Morris, approximately 68%
of the facility’s capacity is currently not contracted. The facility can generate and sell this excess capacity into the grid at
market prices. If market prices do not justify the increased generation, the project has no requirement to sell any excess
capacity. At Selkirk, the capacity of the facility is not contracted and is therefore sold at market prices or not sold at all if
market prices do not support the profitable operation of the facility. As a result, fluctuations in the price of electricity
may have a material adverse effect on the operating margins of these facilities and on our business, results of operations
and financial condition.
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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
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 energy payments at our Orlando project are
subject to fluctuations as the energy payments are comprised of a fuel component based on the cost of coal consumed at
a nearby coal-fired generating station.
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
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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
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.
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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.
Economic and political developments in the United States, including as they relate to the North American
Free Trade Agreement, could adversely affect our business, results of operations and financial condition
Officials in the new U.S. presidential administration and other policy makers have suggested renegotiations of
the North American Free Trade Agreement (“NAFTA”) and other international trade agreements and the implementation
of tariffs, border taxes, border controls and other immigration restrictions, or other measures that could impact the level
of trade and mobility between the United States and Canada. At the present time, it remains unclear what specific
proposals may be implemented and the extent to which trade and/or border mobility between the United States and
Canada would be affected, nor is the long-term impact of proposed reforms (including future reforms that may be part of
any enacted reform) on the broader U.S. and Canadian economies clear. Given that we operate plants in both the United
States and Canada, our business could be affected should the United States adopt trade or border control policies to
restrict trade and/or mobility between the United States and Canada, but it is impossible at the present time to assess
what this impact would be.
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
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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.
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 Public Utility Holding Company Act
(“PUHCA”) 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.
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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.
Additionally, public policy mechanisms and favorable regulatory incentives in the United States and Canada,
including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits,
renewable portfolio standards, and carbon trading plans, impact the viability of our renewable energy projects. As a
result of budgetary constraints, political factors or otherwise, governments from time to time may review their policies
that support renewable energy and consider actions to make the policies less conducive to the development and operation
of renewable energy facilities. In the United States, in December 2015, the federal renewable energy production and
investment tax credits were extended but will begin to phase down in 2017 and 2020, respectively. Any reductions to, or
the elimination of, governmental incentives that support renewable energy, or the imposition of additional taxes or other
assessments on renewable energy, could result in a material adverse effect on our business, results of operations and
financial condition.
The introductions of new laws, or other future regulatory developments, may have a material adverse impact on
our business, operations or financial condition.
Risks with respect to the two Canadian provinces where we currently have projects are addressed further below.
British Columbia
The Government of British Columbia has a number of specific statutes and regulations that govern the
generation, transmission and distribution of electricity within British Columbia. Our projects in that province are subject
to these laws. These statutes can be changed by act of the provincial legislature and the regulations may be changed by
the provincial cabinet. Such changes could have a material effect on our projects.
The Utilities Commission Act governs the BCUC, which is responsible for the regulation of British Columbia’s
public energy utilities, which include publicly owned and investor-owned utilities (i.e., independent power producers).
All contracts for electricity supply, including those between independent power producers and BC Hydro, must be filed
with and approved by the BCUC as being “in the public interest.” The BCUC may hold a hearing in this regard.
Furthermore, the BCUC may make rules governing conditions to be contained in agreements entered into by public
utilities for electricity. Consequently, power procurement is controlled by the BCUC and, as a result, our potential
contracts with BC Hydro may be subject to terms that adversely affect us.
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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. While 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.
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. 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.
Noncompliance with federal reliability standards may subject us and our projects to penalties
Many of our operations are subject to the regulations of NERC, a self-regulatory non-governmental
organization which has statutory responsibility to regulate bulk power system users and generation and transmission
owners and operators. NERC groups the users, owners, and operators of the bulk power system into 17 categories,
known as functional entities—e.g., Generator Owner, Generator Operator, Purchasing-Selling Entity, etc.—according to
the tasks they perform. The NERC Compliance Registry lists the entities responsible for complying with federal
mandatory reliability standards and the FERC, NERC, or a regional reliability organization may assess penalties against
any responsible entity found to be in noncompliance. Violations may be discovered or identified through
self-certification, compliance audits, spot checking, self-reporting, compliance investigations by NERC (or a regional
reliability organization) and the FERC, periodic data submissions, exception reporting, and complaints. The penalty that
could be imposed for violating the requirements of the standards is a function of the Violation Risk Factor. Penalties for
the most severe violations can reach as high as $1 million per violation, per day, and our projects could be exposed to
these penalties if violations occur, which could have a material adverse effect on our business, results of operations and
financial condition.
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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 time, and this trend may
continue. 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. In July 2011, the EPA issued its final Cross-State Air Pollution Rule (“CSAPR”), which replaces its prior
Clean Air Interstate Rule and 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. In November 2014, the EPA issued a ministerial rule setting a schedule for implementation of the
CSAPR beginning in 2015, and in September 2016, the EPA issued the CSAPR Update Rule, intended to implement the
2008 ozone national air quality standards by requiring further reductions in nitrogen oxides in 2017 in 23 states subject
to CSAPR during the summertime ozone season. Other more stringent EPA air emission regulations being implemented
include the more stringent national ambient air quality standards for sulfur dioxide, issued in June 2010, for fine
particulate matter, issued in December 2012, and for ozone, issued in October 2015. Additionally, the EPA’s new
mercury and air toxics emissions standards for power plants, first issued in December 2011, underwent court-mandated
reconsideration and revision in 2015 and 2016 and are beginning to go into effect. Meeting these new standards, when
implemented, may have a material adverse impact on our business, results of operations and financial condition.
In December 2014, the EPA issued its final regulations governing disposal of coal ash in landfills and
impoundments. The final rule affirmed the historic treatment of coal ash as non-hazardous solid waste but establishes
new requirements governing structural integrity, groundwater protection, operating criteria, recordkeeping and reporting,
and closure for such landfills and impoundments. We are currently assessing the increased compliance obligations and
associated costs to our 40% owned coal-fired facility.
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
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
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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 greenhouse gas legislation or regulations may
require greenhouse gas emission reductions from the natural gas sector and 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 the GGIRTA and the
GGRCTA, 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
Ontario Cap and Trade Act and the Cap and Trade Program, from the beginning of 2017, are increasing 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”. The increasing carbon price and
other initiatives to reduce GHG emissions associated with the generation of electricity in the Province could affect our
ability to operate our projects in Ontario and affect our profitability.
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, committing significant capital toward carbon
capture and storage technology, 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, and the selected
compliance alternatives. 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.
While President Trump has indicated an interest in revoking Obama era climate regulations, it remains unclear
at this time if the new U.S. presidential administration will implement, modify or repeal the regulations described above.
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Impairment of goodwill or long-lived assets could have a material adverse effect on our results of operations and
financial condition
As of December 31, 2016, we had $36.0 million of goodwill, which represented approximately 2.5% 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),
our inability to renew certain of our PPAs following their expiration or termination (for a description of the status of
these agreements and related renegotiations, see Item 1A. Risk Factors - The expiration or termination of our PPAs
could have a material adverse impact on our business, results of operation and financial condition), divestiture of a
significant component of our business or adverse actions or assessments by a regulator. 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. See
Note 8 to the consolidated financial statements included in this Annual Report on Form 10-K.
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 $85.9 million, $127.8 million and $106.6 million of goodwill and long-lived asset
impairments for the years ended December 31, 2016, 2015 and 2014, respectively.
Increasing competition could adversely affect our performance and the performance of our projects
The power generation industry is characterized by intense competition and our projects encounter competition
from utilities, industrial companies and other independent power producers, in particular with respect to uncontracted
output. In recent years, there has been increasing competition among generators for PPAs, and this has contributed to a
reduction in electricity prices in certain markets where supply has surpassed demand plus appropriate reserve margins.
Further, changes and developments in technology, including fuel cells, microturbines, solar cells and other
emerging technologies related to energy generation, distribution and consumption, may facilitate the entrance of new
competitors, increase the supply of electricity, and reduce the cost of methods of producing power that we do not
currently use or lower the price of or demand for energy. If these technologies became cost competitive, we could face
increasing competition and the value of our generating facilities could be reduced.
In addition, we continue to confront significant competition for acquisition and investment opportunities and, to
the extent that any opportunities are identified, we may be unable to effect acquisitions or investments on attractive
terms, if at all. Increasing competition among participants in the power generation industry may adversely affect our
performance and the performance of our projects. Further, a payout of a significant portion of our cash flow to service
our debt may result in us not retaining a sufficient amount of cash to finance acquisition or investment opportunities and
make other capital and operating expenditures. See “—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.”
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We have limited control over management decisions at certain projects
Five of our projects are not wholly-owned by us or we have contracted for their operations and maintenance,
and in some cases we have limited control over the operation of the projects. Although we generally prefer to acquire
projects where we have control, we may make acquisitions in non-control situations to the extent that we consider it
advantageous to do so and consistent with regulatory requirements and restrictions, including the Investment Company
Act of 1940. Third-party operators operate five of our projects. As such, we must rely on the technical and management
expertise of these third-party operators although typically we negotiate to obtain positions on a management or operating
committee if we do not own 100% of a project. To the extent that such third-party operators do not fulfill their
obligations to manage the operations of the projects or are not effective in doing so, our cash flow may be adversely
affected. The approval of third-party operators also may be required for us to receive distributions of funds from projects
or to transfer our interest in projects. Our inability to control fully certain projects could have an adverse effect on our
business, results of operations and financial condition.
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
To the extent identification of and pursuit of acquisition opportunities forms a part of our strategy, 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, creating the need for more generation, such growth is
expected to occur at a slower rate. The U.S. power industry is continuing to undergo consolidation and 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
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.”
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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 four 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. As of
December 31, 2016, our pension plan was at a deficit on a going concern basis, which measures its funded status on the
basis that the plan will continue to operate indefinitely. 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
A cyber intrusion is considered to be any adverse event that threatens the confidentiality, integrity or
availability of our information resources. More specifically, a cyber intrusion is an intentional attack or an unintentional
event that can include gaining unauthorized access to systems to disrupt operations, corrupt data, steal confidential
information, and impact our ability to make collections or otherwise impact our operations. We are dependent on various
information technologies throughout our company and our projects to carry out multiple business activities. Further, the
computer systems that run our facilities are not completely isolated from external networks. Parties that wish to disrupt
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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.
39
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 New Credit Facilities or under non-recourse operating level debt arrangements.
Our principal executive office is located at 3 Allied Drive Suite 220, Dedham, Massachusetts under a lease that
expires in 2019.
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,
2016.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
40
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Share Repurchase Program
On December 22, 2015, our Board of Directors approved a normal course issuer bid (“NCIB”) for each series of
our convertible unsecured subordinated debentures, our common shares and for each series of the preferred shares of
Atlantic Power Preferred Equity Ltd. (“APPEL”), our wholly-owned subsidiary. The Board authorization permitted the
Company to repurchase shares through open market repurchases. The NCIB expired on December 28, 2016. Under the
NCIB, we were eligible to purchase up to a total of 12,139,215 common shares (Cdn$28.0 million based on the
Cdn$2.31 closing share price of our common shares on the TSX on December 31, 2015) and were limited to daily
purchases of 22,600 common shares per day with certain exceptions including block purchases and purchases on other
approved exchanges. All purchases made under the NCIB were made through the facilities of the TSX or other Canadian
designated exchanges and published marketplaces and in accordance with the rules of the TSX at market prices
prevailing at the time of purchase. Common share purchases under the NCIB were also made on the New York Stock
Exchange in compliance with rule 10b-18 under the U.S. Securities Exchange Act of 1934, as amended. From inception
of the NCIB through its expiration on December 28, 2016, we repurchased and cancelled 8,067,051 common shares.
The following table presents information regarding repurchases made by the Company of its common shares for
the quarter ended December 31, 2016(1).
Repurchase Period
10/1/2016 - 10/31/2016
11/1/2016 - 11/30/2016
12/1/2016 - 12/31/2016
Total
Total Number of
Shares Purchased
Average Price Paid
Per Share
Total Number of Shares
Dollar Value of Maximum Number
as Part of a Publicly Announced of Shares to be Purchased Under
Purchase Plan
the Plan
1,394,096 Cdn$
848,198 Cdn$
146,021 Cdn$
2,388,315 Cdn$
3.25
3.32
3.40
3.29
1,394,096 Cdn$
848,198 Cdn$
146,021 Cdn$
2,388,315
11,703,345
9,744,007
—
(1) a. The NCIB pursuant to which the share purchases were made was announced on December 22, 2015.
b. The dollar amount approved under the NCIB was Cdn$28.0 million based on the Cdn$2.31 closing share price
of our common shares on the TSX on December 31, 2015 (12,139,215 common shares).
c. The NCIB expired on December 28, 2016.
d. No other plan or program, other than the NCIB, expired in the final quarter of 2016.
e. We did not terminate any plan prior to expiration, nor is there any plan currently in effect pursuant to which we
do not intend to make further purchases.
On December 29, 2016, we commenced a new NCIB (the “New NCIB”) for each series of our 5.75% Series C
and 6.0% Series D convertible unsecured subordinated 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 NCIB
expires on December 28, 2017 or such earlier date as the Company and/or APPEL complete their respective purchases
pursuant to the New NCIBs. Under the New NCIB, we may purchase up to a total of 11,303,772 common shares based
on 10% of our public float as of December 15, 2016 and we are limited to daily purchases of 12,703 common shares per
day with certain exceptions including block purchases and purchases on other approved exchanges. All purchases made
under the New NCIB 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 New NCIB 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.
41
Market Information and Holders
Our common shares trade on the NYSE under the symbol “AT” and on the TSX under the symbol “ATP”.
The following table sets forth the price ranges of our outstanding common shares, as reported by the NYSE for
the periods indicated:
Period
Quarter ended December 31, 2016
Quarter ended September 30, 2016
Quarter ended June 30, 2016
Quarter ended March 31, 2016
Quarter ended December 31, 2015
Quarter ended September 30, 2015
Quarter ended June 30, 2015
Quarter ended March 31, 2015
High (US$) Low (US$)
2.13
2.33
2.21
1.58
1.57
1.83
2.59
2.51
2.75
2.67
2.75
2.58
2.26
3.27
3.34
3.12
The following table sets forth the price ranges of our common shares, as applicable, as reported by the TSX for
the periods indicated:
Period
Quarter ended December 31, 2016
Quarter ended September 30, 2016
Quarter ended June 30, 2016
Quarter ended March 31, 2016
Quarter ended December 31, 2015
Quarter ended September 30, 2015
Quarter ended June 30, 2015
Quarter ended March 31, 2015
High (Cdn$) Low (Cdn$)
2.88
3.05
2.85
2.21
2.19
2.46
3.26
3.04
3.67
3.49
3.49
3.36
2.95
4.08
4.10
4.00
The number of common shares outstanding was 114,649,888 on February 28, 2017.
Dividends
Dividends declared per common share in 2015 were as follows (Cdn$):
Month
January
February
March
April
May
June
July
August
September
October
November
December
2015
$
—
0.0300
—
—
0.0300
—
—
0.0300
—
—
0.0300
—
On February 9, 2016, our Board of Directors, consistent with management’s recommendation, eliminated the
Company’s common share dividend, effective immediately. Previously, the Company had paid a dividend of Cdn$0.03
42
per share quarterly, with the final payment on December 31, 2015. In conjunction with the elimination of the common
share dividend, the Company’s dividend reinvestment plan was terminated.
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of December 31, 2016 regarding our Long-Term Incentive Plan.
For the description of our Long-Term Incentive Plan, see Note 16, Equity Compensation Plans to the consolidated
financial statements.
issued upon exercise of
outstanding options,
Number of securities to be Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
warrants and rights(1)(2)
(a)
Number of securities remaining
available for future issuance
under equity compensation plans
(excluding securities reflected
in column (a))(1)(2)
(c)
Equity compensation plans approved by
security holders
Equity compensation plans not approved
by security holders
Total
1,400,745 $
359,936
1,760,681 $
—
—
—
(573,701)
240,064
(333,637)
(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. See
Item 15. “Exhibits and Financial Statements Schedule”—Note 2(u), Equity compensation plans. We intend to seek
shareholder approval to increase the amount of securities available for future issuance. If the amount available for
future issuance is not sufficient for the number of securities to be issued upon exercise of outstanding awards,
management can elect to redeem the awards with cash as opposed to issuing common shares.
(2) The maximum aggregate number of common shares that may be issued under our Long-Term Incentive Plan upon
redemption of notional shares is 3,000,000 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, 2011, through December 31, 2016, 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, 2011, 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.
43
Comparison of Cumulative Total Return
AT
S&P
S&P / TSX
Dec-2011
Dec-2012
Dec-2013
Dec-2014
Dec-2015
Dec-2016
$
100.00 $
100.00
100.00
86.38 $
28.81 $
24.46 $
116.00
104.00
153.57
113.94
174.60
122.40
18.48 $
177.01
108.82
23.45
198.18
127.88
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, 2016 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, 2016.
44
(in millions of U.S. dollars, except as otherwise stated)
Project revenue
Project income (loss)
Loss from continuing operations
Income (loss) from discontinued operations, net of tax
Net loss attributable to Atlantic Power Corporation
Basic and diluted (loss) income per share(f)
(Loss) Income per share from continuing
operations attributable to Atlantic Power Corporation
Income (loss) from discontinued operations, net of tax
Net (loss) income attributable to Atlantic Power
Corporation
Per common share dividend declared
Total assets
Total long-term liabilities
Year Ended December 31,
$
2016(a)
399.2 $
10.1
(113.9)
—
(122.4)
2015(a)(b)
2014(a)(b)(c)(d)
2013(b)(c)(d)(e)
420.2 $
(41.4)
(84.1)
19.5
(62.4)
489.9 $
(38.9)
(153.2)
(29.0)
(177.4)
2012(a)(c)(d)(e)
429.8
(31.2)
(116.0)
15.7
(112.8)
473.4 $
45.0
(23.6)
(0.2)
(33.0)
$
(1.02) $
—
(0.76) $
0.25
(1.37) $
(0.10)
(0.30) $
0.02
(1.10)
0.13
(1.02) $
— $
(0.97)
$
$
1.10
$ 1,456.8 $ 1,671.2 $ 2,853.2 $ 3,353.3 $ 3,955.5
$ 1,020.0 $ 1,147.1 $ 1,656.6 $ 1,867.9 $ 2,233.6
(0.28) $
0.54 $
(1.47) $
0.29 $
(0.51) $
0.09 $
(a)
Includes $85.9 million, $127.8 million, $106.6 million and $34.9 million of goodwill and long-lived asset
impairment for the years end December 31, 2016, 2015, 2014 and 2013, respectively.
(b) Excludes the Wind Projects, which are classified as discontinued operations for the years ended December 31, 2015,
2014 and 2013.
(c) Excludes Greeley, which is classified as discontinued operations for the years ended December 31, 2014, 2013 and
2012.
(d) The total assets exclude $62.8 million, $41.7 million and $47.2 million of deferred financing costs for the years
ended December 31, 2014, 2013 and 2012, respectively.
(e) Excludes the Florida Projects, Path 15 and Rollcast, which are classified as discontinued operations for the years
ended December 31, 2013 and 2012.
(f) 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.
45
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 2016 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 2016 Results and Recent Events
Management continues to be focused on the following priorities:
• Debt reduction: By strengthening our balance sheet we will improve our financial flexibility and become
more competitive to pursue external growth opportunities.
• Overhead cost reduction: Improving our cost structure provides additional flexibility for debt reduction,
external growth and other value-accretive investments.
• Fleet optimization: By making capital investments in 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.
• PPA renewals: We will leverage the strength of our operations, diversity and location of our projects to
renew or extend, or make alternative arrangements to our contracts in a challenging market.
• External growth: We will take a creative, disciplined and value-oriented approach to external development
or acquisitions.
In 2016, we continued to make progress in strengthening the Company. Our key achievements in the execution
of our strategy during 2016 were:
• Debt refinancing– in April 2016, we entered into new Senior Secured Credit Facilities, comprising $700
million in aggregate principal amount of Senior Secured Term Loan Facilities (the “New Term Loans”)
and $200 million in aggregate principal amount of senior secured revolving credit facilities (the “New
Revolver” and, together with the New Term Loans, the “New Credit Facilities”). We utilized the proceeds
to redeem our existing Senior Secured Term Loan Facility and redeem and cancel our convertible
debentures with near-term maturities. The New Term Loans improved our financial flexibility and
extended the maturity dates from the Senior Secured Term Loan Facility. The targeted debt amortization is
consistent with our goals of debt reduction and strengthening of our balance sheet. See “Liquidity and
Capital Resources” for additional discussion of the New Credit Facilities.
• Debt repayment and convertible debenture repurchase – during 2016, we made payments of $96.5 million
to amortize our corporate and project-level debt. Additionally, we made payments of $188.5 million to
repurchase and cancel convertible debentures. The repurchases of convertible debentures were made from
a combination of discretionary capital under the NCIB and with proceeds from the New Term Loan
facility.
46
• Common share repurchases - we utilized $19.5 million of our discretionary capital to repurchase and
cancel approximately 8 million common shares during 2016 with the goal of capturing price-to-value
opportunities in the market.
• Overhead cost reduction – We have cut our corporate overhead expense from approximately $54 million in
2013 to $23 million for 2016, which represents a cumulative reduction from 2013 of approximately 58%.
Overhead decreased by approximately $9 million from 2015 to $23 million.
•
Investment in our fleet – During 2016 we invested $3.4 million in our fleet for optimization projects and
approximately $25 million since 2013. These cumulative investments returned approximately $7.8 million
in cash during 2016.
• Restructuring of PPAs – the market for recontracting PPAs is challenging. We have worked on solutions
for our current contracts to enhance value where possible. In Ontario, the PPAs at our North Bay and
Kapuskasing projects were scheduled to expire in December of 2017. Our Nipigon project operates under a
PPA that expires in December 2022. For each of these projects, we entered into enhanced dispatch
contracts with the IESO. In conjunction with the execution of the new contracts, we agreed to terminate the
PPAs for Kapuskasing and North Bay and to suspend for a period (as described below) the Nipigon
PPA. The enhanced dispatch contracts for Kapuskasing and North Bay provide a fixed monthly payment to
the plants until December 31, 2017. The contracts have no delivery obligations and allow us to retain
operating flexibility. The enhanced dispatch contract for Nipigon provides fixed monthly payments to that
plant through October 31, 2018. During that period, Nipigon's PPA will be suspended. At the conclusion of
that period, or after that date should that subsequently be agreed to, the arrangement will revert to the
existing terms of the PPA. The impact on 2017 financial results is expected to be positive as compared to
the corresponding results under the previous arrangements for the three plants due to the mitigation of
potential cap and trade expenses and lower operations and maintenance costs.
Performance highlights
Project revenue
Project income (loss)
Loss from continuing operations
Income from discontinued operations
Net loss attributable to Atlantic Power Corporation
Loss per share from continuing operations attributable to Atlantic Power
Corporation—basic and diluted
Earnings per share from discontinued operations—basic and diluted
Loss per share attributable to Atlantic Power Corporation—basic and diluted
Project Adjusted EBITDA(1)
2016
2014
Year Ended December 31,
2015
$ 399.2 $ 420.2 $ 489.9
10.1 $ (41.4) $ (38.9)
$
$ (113.9) $ (84.1) $ (153.2)
$
19.5 $ (29.0)
$ (122.4) $ (62.4) $ (177.4)
— $
—
$ (1.02) $ (0.76) $ (1.37)
(0.10)
$ (1.02) $ (0.51) $ (1.47)
$ 202.2 $ 208.9 $ 229.4
0.25
(1) See reconciliation and definition below under Supplementary Non-GAAP Financial Information.
Revenue decreased from $420.2 million in the year ended December 31, 2015 to $399.2 million in the year
ended December 31, 2016, a decrease of 5.3%. The primary drivers of the decrease are as follows:
• Morris maintenance outages – during the first quarter of 2016, the Morris project completed capital
upgrades to enhance efficiency and comply with the terms of its amended energy services agreement. In the
third quarter of 2016, the Morris project underwent a planned gas turbine overhaul. These actions resulted
in a $9.1 million decrease in revenue from 2015. However, due to lower fuel usage and pricing, the net
impact to the project’s gross margin was a $2.3 million decrease from 2015;
• Waste heat – our projects operating in Ontario recorded $4.3 million of lower waste heat revenue than 2015
primarily due to decreased gas distributed by TransCanada, and
47
• Energy prices and dispatch – we recorded $4.8 million of lower revenue than 2015 at our Kenilworth,
Cadillac and Manchief projects due to lower energy prices in their respective regions as well as lower
dispatch.
Consolidated project income was $10.1 million for the year ended December 31, 2016, an increase of
$51.5 million from the prior year project loss. The primary drivers of the increase are as follows:
•
Impairment of goodwill and long-lived assets – goodwill and long–lived asset impairment decreased $41.9
million from $127.8 million in 2015 to $85.9 million in 2016;
• Change in fair value of derivative instruments – the change in the fair value of our derivative instruments
increased $22.5 million to $37.9 million in 2016 from $15.4 million in 2015. The increase is due to a $22.8
million increase in the fair value of gas purchase agreements in our Canada segment, $9.0 million in natural
gas swaps at our Orlando project and $6.1 million in interest rate swaps related to project debt at our
Piedmont project and the New Credit Facilities; and
• Fuel expense - fuel expense decreased from $165.1 million in 2015 to $149.5 million in 2016 primarily due
to the maintenance outage at Morris discussed above ($6.8 million impact), as well as a $5.2 million
decrease at our Kenilworth project due to lower generation, improved metering and a reimbursement
received from its supplier.
These increases in project income were partially offset by decreases in project income resulting from:
• Revenue – revenue decreased $21.0 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 62.
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 long-lived assets and goodwill. 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.
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 December 31, 2017 and December 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. For example, the PPA at Selkirk expired in August 2014. As a result, 100%
of the capacity at Selkirk is not contracted and therefore sold at market power prices. Our next PPA
expirations occur on December 31, 2017 and are at our North Bay and Kapuskasing projects in Ontario.
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.”
• While approximately 82% of our power generation revenue in 2016 was related to contractual energy and
capacity payments, commodity prices do influence our variable revenues and the cost of fuel. Our PPAs are
48
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. Our projects 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 Selkirk, Chambers and Morris projects.
At Chambers, our utility customer has the right to sell a portion of the plant’s output to the spot power
market if it is economical to do so, and the Chambers project shares in the profits from those sales. With
low demand for electricity the utility reduces its dispatch to minimum contracted levels during off-peak
hours. At Selkirk, the capacity of the facility is not currently contracted and is sold at market power prices
or not sold at all if market prices do not support profitable operation of the facility. Additionally at Morris,
approximately 68% of the facility’s capacity is currently not contracted and is sold at market power prices
or not sold at all if market prices do not support profitable operation of that portion of the facility. 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
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.
• Some of our projects have non-recourse project-level debt that can restrict the ability of the project to make
cash distributions. The project-level debt agreements typically contain cash flow coverage ratio tests that
restrict the project’s cash distributions if project cash flows do not exceed project-level debt service
requirements by a specified amount. Although all projects, with the exception of Piedmont, are currently
meeting these debt service requirements, we cannot provide any assurances that these projects 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.
49
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 $85.9 million, $127.8 million and $106.6 million of goodwill and long-lived asset impairments for
the years ended December 31, 2016, 2015 and 2014, 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. We revised our
reportable business segments in the second quarter of 2015 as a result of significant project asset sales and in order to
align our reportable business segments with changes in management’s structure, resource allocation and performance
assessment in making decisions regarding our operations. 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 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.
50
2016 compared to 2015
The following tables and discussion summarize our consolidated results of operations and provide an analysis
Years Ended December 31,
2016
2015
$ change % change
$ 184.2 $ 191.5 $
141.9
73.1
399.2
149.3
79.4
420.2
149.5
105.2
—
113.5
368.2
165.1
103.5
1.1
110.0
379.7
37.9
35.9
(9.2)
(85.9)
0.4
(20.9)
10.1
15.4
36.7
(8.2)
(127.8)
2.0
(81.9)
(41.4)
22.6
106.0
13.9
(3.9)
138.6
(128.5)
(14.6)
(113.9)
—
(113.9)
—
29.4
107.1
(60.3)
(3.1)
73.1
(114.5)
(30.4)
(84.1)
19.5
(64.6)
(11.0)
(7.3)
(7.4)
(6.3)
(21.0)
(15.6)
1.7
(1.1)
3.5
(11.5)
22.5
(0.8)
(1.0)
41.9
(1.6)
61.0
51.5
(6.8)
(1.1)
74.2
(0.8)
65.5
(14.0)
15.8
(29.8)
(19.5)
(49.3)
11.0
8.5
(0.3)
$ (122.4) $ (62.4) $ (60.0)
8.8
(3.8) %
(5.0) %
(7.9) %
(5.0) %
(9.4) %
1.6 %
NM %
3.2 %
(3.0) %
146.1 %
(2.2) %
12.2 %
(32.8) %
(80.0) %
(74.5) %
NM %
(23.1) %
(1.0) %
NM %
25.8 %
89.6 %
12.2 %
(52.0) %
35.4 %
NM %
76.3 %
NM %
(3.4) %
96.2 %
by reportable segment:
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Development
Depreciation and amortization
Project other expense:
Change in fair value of derivative instruments
Equity in earnings of unconsolidated affiliates
Interest expense, net
Impairment
Other income, net
Project income (loss)
Administrative and other expenses:
Administration
Interest, net
Foreign exchange loss (gain)
Other income, net
Loss from continuing operations before income taxes
Income tax benefit
Loss from continuing operations
Income from discontinued operations, net of tax
Net loss
Net loss attributable to noncontrolling interests
Net income attributable to Preferred share dividends of a
subsidiary company
Net loss attributable to Atlantic Power Corporation
51
Project Income (Loss) by Segment
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (expense):
Change in fair value of derivative instruments
Equity in earnings of unconsolidated affiliates
Interest expense, net
Impairment
Other expense, net
Project income (loss)
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Development
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 expense, net
Project income (loss)
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
Year Ended December 31, 2015
East U.S. West U.S. Canada
Un-Allocated Consolidated
Corporate
Total(1)
$ 77.0 $ 36.3 $
54.9
18.1
150.0
45.4
22.9
104.6
78.2 $
49.0
37.5
164.7
58.5
31.8
—
32.7
123.0
39.0
32.0
—
29.1
100.1
67.6
37.4
—
47.3
152.3
—
33.7
(8.2)
(13.7)
(0.1)
11.7
$ 38.7 $
—
3.1
—
—
—
3.1
7.6 $ (85.7) $
16.0
—
—
(114.1)
—
(98.1)
— $
—
0.9
0.9
—
2.3
1.1
0.9
4.3
191.5
149.3
79.4
420.2
165.1
103.5
1.1
110.0
379.7
(0.6)
(0.1)
—
—
2.1
1.4
(2.0) $
15.4
36.7
(8.2)
(127.8)
2.0
(81.9)
(41.4)
(1) Excludes the Wind Projects, which were sold in June 2015 and classified as discontinued operations.
52
East U.S.
Project income for 2016 decreased $7.5 million from 2015 primarily due to:
•
•
decreased project income of $5.1 million at Curtis Palmer due primarily to a $1.7 million increase in
goodwill impairment and a $3.1 million decrease in revenue from lower water flows than 2015; and
decreased project income of $12.8 million at Morris due primarily to $7.4 million of increased maintenance
expenses resulting from the overhaul of two gas turbines and one steam turbine during 2016. The
maintenance outage also resulted in $9.1 million lower revenues and $6.8 million lower fuel expense.
These increases were partially offset by:
•
increased project income of $9.4 million at Orlando due primarily to a $7.4 million increase in the fair
value of natural gas swaps and higher revenue from increased dispatch and a $1.8 million decrease in fuel
expense due to lower gas prices.
West U.S.
Project income for 2016 increased $4.2 million from 2015 primarily due to:
•
increased project income of $7.1 million at Manchief due primarily to $8.0 million of lower maintenance
expense related to a 2015 maintenance overhaul.
This increase was partially offset by:
•
decreased project income of $2.3 million at Oxnard, which underwent a planned maintenance outage in the
fourth quarter of 2016.
Canada
Project loss for 2016 decreased $50.0 million from 2015 primarily due to:
•
•
•
increased project income from Williams Lake of $119.2 million due primarily to a $109.7 million goodwill
and long-lived asset impairment recorded in 2015 and $9.3 million of lower depreciation expense during
2016 related to the prior-year long-lived asset impairment;
increased project income from Calstock of $2.5 million due primarily to a $4.4 million goodwill
impairment recorded in 2015 and $0.9 million lower fuel costs. This was partially offset by a $2.8 million
decrease in revenue due to the expiration of a rate adder under its PPA and lower waste heat; and
increased project income from Nipigon of $1.8 million due primarily to a $1.7 million increase in the fair
value of fuel agreements accounted for as derivatives.
These increases were partially offset by:
•
•
increased project loss from Mamquam of $43.6 million due primarily to a $50.2 million goodwill
impairment recorded in the third quarter of 2016, partially offset by a $4.6 million increase in energy
revenue due to higher water flows than 2015 and a $2.1 million decrease in operation and maintenance
expense due to a maintenance outage in 2015;
increased project loss from North Bay of $13.8 million due primarily to a $10.2 million goodwill and long-
lived asset impairment recorded in the third quarter of 2016 and $5.9 million increased amortization related
to the acceleration of a PPA intangible resulting from the termination of the PPA in December 2016. This
53
was partially offset by a $3.9 million increase in the fair value of a fuel agreement accounted for as a
derivative; and
•
increased project loss from Kapuskasing of $13.8 million due primarily to an $8.9 million goodwill and
long-lived asset impairment recorded in the third quarter of 2016 and $5.9 million increased amortization
related to the acceleration of a PPA intangible resulting from the termination of the PPA in December
2016. This was partially offset by a $3.9 million increase in the fair value of a fuel agreement accounted for
as a derivative.
Un-Allocated Corporate
Total project income increased $4.8 million from 2015 primarily due to a $3.8 million increase in the fair value
of interest rate swap agreements, a $1.3 million decrease in employee compensation and a $1.1 million decrease in
development costs, partially offset by a $2.3 million gain on the sale of our Frontier solar development project recorded
in 2015.
Administrative and other expenses (income)
Administrative and other expenses (income) include 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 decreased $6.8 million or 23.1% from 2015 primarily due to a $3.6 million decrease in
employee compensation costs, $1.8 million of lower professional services costs and $1.5 million of lower rent expense.
Interest, net
Interest expense decreased $1.1 million or 1.0% from the comparable 2015 period primarily due to:
•
•
decreased convertible debenture interest expense of $6.5 million resulting from the repurchase and
cancellation of the Series A, B and, in part, C and D convertible debentures during 2016; and
decreased deferred financing costs amortization of $3.9 million 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.
These decreases were partially offset by:
•
increased interest expense on our corporate debt of $8.9 million due to higher interest rates and principal
balance on our New Term Loan Facility, partially offset by lower interest expense from the redemption of
our 9.0% Notes in 2015.
Foreign exchange loss (gain)
Foreign exchange loss was $13.9 million for the year ended December 31, 2016, a change of $74.2 million
from the $60.3 million gain recorded in 2015 period primarily due to a $74.3 million increase in unrealized loss in the
revaluation of instruments denominated in Canadian dollars. The repurchase of Cdn$152.1 million Canadian dollar-
54
denominated convertible debentures was the most significant factor in the decrease. The U.S. dollar to Canadian dollar
exchange rate was 1.34 and 1.38 at December 31, 2016 and 2015, respectively, a decrease of 3.0%. The average U.S.
dollar to Canadian dollar exchange rate was 1.32 for the year ended December 31, 2016 and was 1.27 for the year ended
December 31, 2015.
Other income, net
Other income, net increased $0.8 million from the 2015 comparable period primarily due to a $3.7 million gain
recorded on the purchase and cancellation of convertible debentures during 2016, as compared to a $3.1 million gain on
the purchase and cancellation of convertible debentures recorded during 2015.
Income tax benefit
Income tax benefit for the year ended December 31, 2016 was $14.6 million. Expected income tax benefit for
the same period, based on the Canadian enacted statutory rate of 26%, was $33.4 million. The primary items impacting
the tax rate for the year ended December 31, 2016 were $22.3 million related to goodwill impairment, $6.9 million
related to foreign exchange and $1.3 million related to return to provision adjustments. In addition, the rate was further
impacted by a net increase to our valuation allowances of $10.8 million, consisting primarily of increases of $27.2
million in Canada related to losses and a decrease of $16.4 million in the United States due to tax restructurings and
additional earnings. These items were offset by $18.0 million Canadian capital losses recognized on tax restructurings,
$2.9 million related to operating in higher tax rate jurisdictions and $1.5 million related to changes in tax rates.
55
2015 compared to 2014
The following tables and discussion summarize our consolidated results of operations and provides an analysis
Year ended December 31,
2015
2014
$ change % change
$ 191.5 $ 236.9 $ (45.4)
(12.0)
161.3
(12.3)
91.7
(69.7)
489.9
149.3
79.4
420.2
165.1
103.5
1.1
110.0
379.7
210.4
109.0
3.7
122.3
445.4
(45.3)
(5.5)
(2.6)
(12.3)
(65.7)
15.4
36.7
—
(8.2)
(127.8)
2.0
(81.9)
(41.4)
29.4
107.1
(60.3)
(3.1)
73.1
(114.5)
(30.4)
(84.1)
19.5
(64.6)
(11.0)
6.8
25.5
8.6
(17.7)
(106.6)
—
(83.4)
(38.9)
8.6
11.2
(8.6)
9.5
(21.2)
2.0
1.5
(2.5)
37.9
146.7
(38.3)
(0.6)
145.7
(184.6)
(31.4)
(153.2)
(29.0)
(182.2)
(16.4)
(8.5)
(39.6)
(22.0)
(2.5)
(72.6)
70.1
1.0
69.1
48.5
117.6
5.4
8.8
(2.8)
$ (62.4) $ (177.4) $ 115.0
11.6
(19.2)%
(7.4)%
(13.4)%
(14.2)%
(21.5)%
(5.0)%
(70.3)%
(10.1)%
(14.8)%
126.5 %
43.9 %
NM
(53.7)%
19.9 %
NM
(1.8)%
6.4 %
(22.4)%
(27.0)%
57.4 %
NM
(49.8)%
(38.0)%
(3.2)%
(45.1)%
(167.2)%
(64.5)%
(32.9)%
(24.1)%
(64.8)%
by reportable segment:
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Development
Depreciation and amortization
Project other expense:
Change in fair value of derivative instruments
Equity in earnings of unconsolidated affiliates
Gain on sale of equity investments
Interest expense, net
Impairment
Other income, net
Project loss
Administrative and other expenses (income):
Administration
Interest, net
Foreign exchange loss
Other income, net
Loss from continuing operations before income taxes
Income tax benefit
Loss from continuing operations
Income (loss) from discontinued operations, net of tax
Net loss
Net loss attributable to noncontrolling interests
Net income attributable to Preferred share dividends of a
subsidiary company
Net loss attributable to Atlantic Power Corporation
56
Project Income (Loss) by Segment
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Development
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 expense, net
Project income (loss)
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Development
Depreciation and amortization
Project other income (expense):
Change in fair value of derivative instruments
Equity in earnings of unconsolidated affiliates
Gain on sale of equity investment
Interest expense, net
Impairment
Year Ended December 31, 2015
East U.S. West U.S. Canada
Un-Allocated Consolidated
Corporate
Total(1)
$ 77.0 $ 36.3 $
54.9
18.1
150.0
45.4
22.9
104.6
78.2 $
49.0
37.5
164.7
58.5
31.8
—
32.7
123.0
39.0
32.0
—
29.1
100.1
67.6
37.4
—
47.3
152.3
—
33.7
(8.2)
(13.7)
(0.1)
11.7
$ 38.7 $
—
3.1
—
—
—
3.1
7.6 $ (85.7) $
16.0
—
—
(114.1)
—
(98.1)
— $
—
0.9
0.9
—
2.3
1.1
0.9
4.3
191.5
149.3
79.4
420.2
165.1
103.5
1.1
110.0
379.7
(0.6)
(0.1)
—
—
2.1
1.4
(2.0) $
15.4
36.7
(8.2)
(127.8)
2.0
(81.9)
(41.4)
Year Ended December 31, 2014
East U.S. West U.S.(2) Canada
Un-Allocated Consolidated
Corporate
Total(1)
$ 86.8 $
52.1
28.2
167.1
52.7 $ 97.4 $
45.3
25.6
123.6
63.9
37.0
198.3
— $
—
0.9
0.9
76.9
32.1
—
32.5
141.5
(3.6)
22.3
—
(17.7)
(17.9)
(16.9)
56.1
27.7
—
29.0
112.8
77.3
44.5
—
60.1
181.9
0.1
4.7
3.7
0.7
9.2
11.6
—
—
—
(38.5)
(26.9)
—
3.3
8.6
—
(50.3)
(38.4)
(27.6) $ (10.5) $
(1.2)
(0.1)
—
—
0.1
(1.2)
(9.5) $
6.8
25.5
8.6
(17.7)
(106.6)
(83.4)
(38.9)
236.9
161.3
91.7
489.9
210.4
109.0
3.7
122.3
445.4
Project income (loss)
$
8.7 $
(1) Excludes the Wind Projects, which were sold in June 2015 and classified as discontinued operations.
(2) Excludes Greeley, which was sold in 2014 and is classified as discontinued operations.
57
East U.S.
Project income for 2015 increased $30.0 million from 2014 primarily due to:
•
•
•
•
•
increased project income of $17.5 million at Kenilworth due primarily to a $17.9 million goodwill
impairment charge recorded during the year ended December 31, 2014;
increased project income of $10.5 million at Orlando due primarily to $3.6 million of higher revenue from
increased dispatch and a $3.8 million decrease in fuel expense due to lower gas prices;
increased project income of $3.7 million at Morris due primarily to lower natural gas prices and lower
maintenance expense than the 2014 period;
increased project income of $3.4 million at Selkirk due primarily to $12.7 million of accelerated
depreciation recorded during the 2014 period due to expiration of its PPA in August 2014, partially offset
by lower gross margin in 2015 due to operating as a merchant facility since the PPA expiration; and
increased project income of $3.2 million at Piedmont due primarily to a $2.3 million increase in the fair
value of interest rate swaps, a $0.8 million increase in revenue and a $0.8 million decrease in fuel expense
from 2014.
These increases were partially offset by:
•
decreased project income of $9.4 million at Curtis Palmer due primarily to a $13.7 million goodwill
impairment and a $1.2 million decrease in revenue from lower water flows than the 2014 period. This was
partially offset by a $6.2 million decrease in interest expense.
West U.S.
Project income for 2015 was $7.6 million as opposed to a project loss of $27.6 million in 2014 primarily due to:
•
•
increased project income of $41.0 million at Manchief due primarily to a $50.2 million goodwill
impairment charge recorded during the year ended December 31, 2014, partially offset by an $8.0 million
increase in maintenance expense related to a 2015 maintenance overhaul; and
increased project income of $2.9 million at North Island due primarily to $2.2 million of lower
maintenance expense and $0.7 million of higher gross margin compared to the 2014 period. North Island
underwent a maintenance outage in 2014.
These increases were partially offset by:
•
decreased project income of $8.5 million at Delta-Person which was sold in July 2014, and resulted in a
gain on sale of $8.6 million recorded during 2014.
Project income for the West U.S. segment excludes the Greeley project, which is accounted for as a component
of discontinued operations. Project loss for Greeley was ($0.1) million for the year ended December 31, 2014.
Canada
Project loss for 2015 increased $75.2 million from 2014 primarily due to:
•
decreased project income from Williams Lake of $84.1 million due primarily to a $109.7 million goodwill
and long-lived asset impairment recorded during the year ended December 31, 2015 as compared to a
$23.7 million goodwill impairment recorded during the year ended December 31, 2014; and
58
•
decreased project income from Mamquam of $4.6 million due primarily to a $4.1 million decrease in
energy revenue from lower water flows and a maintenance outage during the third quarter of 2015.
These decreases were partially offset by:
•
•
increased project income from Tunis of $9.2 million due primarily to a $14.8 million goodwill and long-
lived asset impairment charge recorded during the year ended December 31, 2014. Tunis has not operated
since the expiration of its PPA on December 31, 2014; and
increased project income from Kapuskasing of $3.9 million due primarily to a $4.0 million non-cash
change in the fair value of a gas purchase agreement that is accounted for as a derivative.
Un-Allocated Corporate
Total project loss decreased $7.5 million from 2014 primarily due to a $2.6 million decrease in development
costs and a $2.3 million gain on the sale of our Frontier solar development project, as well as headcount reductions
undertaken during the year ended December 31, 2015.
Administrative and other expenses (income)
Administrative and other expenses (income) include 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 decreased $8.5 million or 22.4% from 2014 primarily due to a $3.9 million decrease in
legal costs from the 2014 period, a $1.9 million decrease in business development costs and a $1.9 million decrease in
employee severance expenses.
Interest, net
Interest expense decreased $39.6 million or 27.0% from the comparable 2014 period primarily due to
$23.3 million of make-whole premiums paid to redeem the Series A Notes (the “Series A Notes”) and Series B Notes
(the “Series B Notes”) issued by Atlantic Power (US) GP in the 2014 period, as well as $16.4 million of premiums paid
and non-cash deferred financing costs written off for the repurchase of $140.1 million aggregate principal amount of the
9.0% Notes in the first quarter of 2014. Additionally, interest expense decreased due to lower interest expense from the
purchase and cancellation of $24.6 million aggregate principal of convertible debentures beginning in the fourth quarter
of 2014 and continuing through December 2015 and the redemption of our 9.0% Notes in July 2015. This was partially
offset by $14.0 million of make-whole premiums paid and $9.0 million of deferred financing costs written off related to
the redemption of our 9.0% Notes in July 2015.
Foreign exchange gain
Foreign exchange gain increased $22.0 million or 57.4% from the comparable 2014 period primarily due to a
$22.6 million increase in unrealized gain in the revaluation of instruments denominated in Canadian dollars. The U.S.
dollar to Canadian dollar exchange rate was 1.38 and 1.16 at December 31, 2015 and 2014, respectively, an increase of
59
19.3%. The average U.S. dollar to Canadian dollar exchange rate was 1.27 for the year ended December 31, 2015 and
was 1.11 for the year ended December 31, 2014.
Other income, net
Other income, net increased $2.5 million from the 2014 comparable period primarily due to a $3.1 million gain
recorded on the purchase and cancellation of convertible debentures under the NCIB during 2015.
Income tax benefit
Income tax benefit for the year ended December 31, 2015 was $30.4 million. Expected income tax benefit for
the same period, based on the Canadian enacted statutory rate of 26%, was $29.8 million. The primary items impacting
the tax rate for the year ended December 31, 2015 were $14.8 million relating to goodwill impairment, $6.6 million
relating to a change in the valuation allowance, $2.1 million related to capital gain on intercompany notes, $2.1 million
relating to changes in tax rates and $1.1 million relating to dividend withholding and other taxes. These items were
partially offset by $7.0 million relating to foreign exchange, $6.3 million relating to return to provision adjustments, $5.0
million of intra-period allocations from the wind projects, $4.9 million relating to operating in higher tax rate
jurisdictions, $3.6 million related to tax credits and $0.5 million of 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 MWhs.
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
MWh.
Generation
(in thousands of Net MWh)
Segment
East U.S.
West U.S. (1)
Canada
Total (2)
Year ended December 31,
% change
% change
2016
2015
2014
2016 vs. 2015 2015 vs. 2014
2,430.2 2,628.0 2,671.3
1,506.6 1,835.9 1,639.1
1,977.2 1,889.4 2,088.5
5,914.0 6,353.3 6,398.9
(7.5)%
(17.9)%
4.6 %
(6.9)%
(1.6)%
12.0 %
(9.5)%
(0.7)%
(1) Excludes (i) Delta-Person, which was sold in July 2014, and (ii) Greeley, which was sold in March 2014 and is
classified as discontinued operations.
(2) Excludes the Wind Projects, which were sold in June 2015 and are classified as discontinued operations.
Year ended December 31, 2016 compared with Year ended December 31, 2015
Aggregate power generation for 2016 decreased 6.9% from 2015 primarily due to:
•
•
decreased generation in the West U.S. segment, primarily due to a 206.9 net MWh decrease in generation
at Frederickson, which had decreased dispatch from lower demand, and a 110.1 net MWh decrease in
generation at Manchief due to lower dispatch; and
decreased generation in the East U.S. segment, primarily due to an 83.4 net MWh decrease in generation at
Morris due to a maintenance outage in the third quarter of 2016, an 83.3 net MWh decrease at Selkirk due
60
to lower dispatch from low merchant power prices and a 53.5 net MWh decrease at Chambers due to a
maintenance outage in the second quarter of 2016.
This decrease was partially offset by:
•
increased generation in the Canada segment, primarily due to a 133.3 net MWh increase in generation at
Mamquam due to higher water flows during 2016. Mamquam also underwent a maintenance outage during
2015.
Year ended December 31, 2015 compared with Year ended December 31, 2014
Aggregate power generation for 2015 decreased 0.7% from 2014 primarily due to:
•
decreased generation in the Canada segment, primarily due to a 271.7 net MWh decrease in generation at
Tunis, for which the PPA expired in December 2014, and a 73.3 net MWh decrease in generation at
Mamquam, which underwent a scheduled maintenance outage in the third quarter of 2015. This was
partially offset by a 57.0 net MWh increase in generation at Nipigon, which underwent a maintenance
outage in September 2014.
This decrease was partially offset by:
•
increased generation in the West U.S. segment, primarily due to a 276.9 net MWh increase in generation at
Frederickson due to higher dispatch resulting from warmer weather and reduced hydro availability in the
region than the 2014 period, as well as a scheduled outage that occurred from February to April 2014.
Generation did not change materially in our East U.S. segment for the year ended December 31, 2015.
Availability
Segment
East U.S.
West U.S. (1)
Canada
Weighted average(2)
2016
2015
Year ended December 31,
% change
2016 vs. 2015 2015 vs. 2014
% change
2014
93.1 % 96.9 % 93.3 %
92.1 % 92.8 % 92.4 %
95.3 % 93.9 % 93.1 %
93.3 % 95.2 % 93.0 %
(3.9)%
(0.8)%
1.5 %
(2.0)%
3.9 %
0.4 %
0.9 %
2.4 %
(1) Excludes (i) Delta-Person, which was sold in July 2014, and (ii) Greeley, which was sold in March 2014 and is
classified as discontinued operations.
(2) Excludes the Wind Projects, which were sold in June 2015 and are classified as discontinued operations.
Year ended December 31, 2016 compared with Year ended December 31, 2015
Weighted average availability for 2016 decreased to 93.3% from 95.2% in 2015 primarily due to:
•
•
decreased availability in the East U.S. segment resulting from decreased availability at Morris, which
underwent a planned maintenance in the third quarter of 2016; and
decreased availability in the West U.S. segment resulting from decreased availability at Frederickson,
which underwent a maintenance outage in 2016, offset by increased availability at Manchief, which
underwent a maintenance outage in 2015.
61
These decreases were partially offset by:
•
increased availability in the Canada segment resulting from increased availability at Mamquam, which
underwent a maintenance outage in the 2015 period.
Year ended December 31, 2015 compared with Year ended December 31, 2014
Weighted average availability for 2015 increased to 95.2% from 93.0% in 2014 primarily due to:
•
•
increased availability in the East U.S. segment resulting from increased availability at Piedmont, which had
longer outages in 2014, and from Cadillac and Orlando, both of which underwent maintenance outages in
the 2014 period; and
increased availability in the West U.S. segment resulting from increased availability at North Island, which
underwent a maintenance outage in the 2014 period, offset by decreased availability at Naval Training
Center, which underwent a maintenance outage in 2015.
These increases were partially offset by:
•
decreased availability in the Canada segment resulting from decreased availability at Mamquam, which
underwent a maintenance outage in the 2015 period, and from Tunis, for which the PPA expired in
December 2014, partially offset by increased availability at Nipigon, which had extensive outages in the
2014 period.
Supplementary Non-GAAP Financial Information
Project Adjusted EBITDA
The key measurement we use to evaluate the results of our business is Project Adjusted EBITDA. Project
Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including
non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a
measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore
unlikely to be comparable to similar measures presented by other companies. We believe that Project Adjusted EBITDA
is a useful measure of financial results at our projects because it excludes non-cash impairment charges, gains or losses
on the sale of assets and non-cash mark-to-market adjustments, all of which can affect year-to-year comparisons. Project
Adjusted EBITDA is before corporate overhead expense. The most directly comparable GAAP measure to Project
Adjusted EBITDA is Project income. A reconciliation of Net (loss) income to Project 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.
62
Year ended December 31,
2015
2014
2016
$ change
2016
2015
Net loss
Net income (loss) from discontinued operations, net of tax
Income tax benefit
Loss from continuing operations before income taxes
Administration
Interest, net
Foreign exchange loss (gain)
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 and other expense
Project Adjusted EBITDA
Project Adjusted EBITDA by segment(1)
East U.S.
West U.S.(2)
Canada
Un-Allocated Corporate
Total
$ (113.9) $ (64.6) $ (182.2) $ (49.3) $ 117.6
48.5
1.0
70.1
(8.5)
(39.6)
(22.0)
(2.5)
(2.5)
—
(14.6)
(128.5)
22.6
106.0
13.9
(3.9)
10.1 $ (41.4) $ (38.9) $ 51.5 $
19.5
(30.4)
(114.5)
29.4
107.1
(60.3)
(3.1)
(29.0)
(31.4)
(184.6)
37.9
146.7
(38.3)
(0.6)
(19.5)
15.8
(14.0)
(6.8)
(1.1)
74.2
(0.8)
$
133.5
10.9
(37.9)
85.6
130.1
9.8
(15.4)
125.8
$ 202.2 $ 208.9 $ 229.4 $
155.9
20.5
(6.2)
98.1
3.4
1.1
(22.5)
(40.2)
(25.8)
(10.7)
(9.2)
27.7
(6.7) $ (20.5)
92.4
51.2
58.8
(0.2)
104.8
46.9
59.7
(2.5)
106.4
54.2
76.3
(7.5)
$ 202.2 $ 208.9 $ 229.4 $
(1.6)
(12.4)
(7.3)
4.3
(16.6)
(0.9)
2.3
5.0
(6.7) $ (20.5)
(1) Excludes the Wind Projects, which were sold in June 2015 and are classified as discontinued operations.
(2) Excludes Greeley, which was sold in March 2014, and is classified as discontinued operations.
East U.S.
The following table summarizes Project Adjusted EBITDA for our East U.S. segment for the periods indicated:
2016
2015
Year ended December 31,
% change
2016 vs. 2015 2015 vs. 2014
% change
2014
East U.S.
Project Adjusted EBITDA
$ 92.4 $ 104.8 $ 106.4
(12)%
(2)%
Year ended December 31, 2016 compared with Year ended December 31, 2015
Project Adjusted EBITDA for 2016 decreased $12.4 million or 12% from 2015 primarily due to decreases in
Project Adjusted EBITDA of:
•
•
$10.1 million at Morris due to $7.9 million of increased maintenance expenses resulting from the overhaul
of two gas turbines and one steam turbine during 2016. The maintenance outage also resulted in $9.1
million lower revenues and $6.8 million lower fuel expense; and
$3.3 million at Curtis Palmer due to $3.1 million of decreased revenues from lower water flows than the
2015 period.
These decreases were partially offset by an increase in Project Adjusted EBITDA of:
•
$2.1 million at Orlando primarily due to $1.8 million of lower fuel expense from lower natural gas prices
than 2015.
63
Year ended December 31, 2015 compared with Year ended December 31, 2014
Project Adjusted EBITDA for 2015 decreased $1.6 million or 2% from 2014 primarily due to decreases in
Project Adjusted EBITDA of:
•
•
$10.2 million at Selkirk due to lower revenue from operating as a merchant facility since the expiration of
its PPA in August 2014; and
$1.7 million at Curtis Palmer due to lower water flows than the 2014 period.
These decreases were partially offset by increases in Project Adjusted EBITDA of:
•
•
$6.6 million at Orlando primarily due to $3.6 million of increased revenue from higher generation and $3.7
million of lower fuel expense from lower natural gas prices than the 2014 period; and
$3.8 million at Morris due to lower fuel expense from lower natural gas prices and lower maintenance
expense than the comparable 2014 period.
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
2016 vs 2015
2014
2015
% change
2015 vs 2014
2016
West U.S.
Project Adjusted EBITDA
$ 51.2 $ 46.9 $ 54.2
9 %
(13)%
Year ended December 31, 2016 compared with Year ended December 31, 2015
Project Adjusted EBITDA for 2016 increased by $4.3 million or 9% from 2015 primarily due to increases in
Project Adjusted EBITDA of:
•
$7.2 million at Manchief attributable to $8.0 million of lower maintenance expense in 2016. Manchief
underwent a maintenance overhaul during 2015.
This increase was partially offset by a decrease in Project Adjusted EBITDA of:
•
$2.2 million at Oxnard, which underwent a planned maintenance outage in the fourth quarter of 2016.
Year ended December 31, 2015 compared with Year ended December 31, 2014
Project Adjusted EBITDA for 2015 decreased by $7.3 million or 13% from 2014 primarily due to decreases in
Project Adjusted EBITDA of:
•
•
$9.2 million at Manchief attributable to higher project operations and maintenance expense due to a
maintenance overhaul during the second quarter of 2015; and
$0.9 million at Delta-Person, which was sold in July 2014.
These decreases were partially offset by an increase in Project Adjusted EBITDA of:
•
$3.0 million at North Island, which underwent a turbine maintenance outage in the first quarter of 2014.
64
Project Adjusted EBITDA for the West U.S. segment excludes the Greeley project, which is accounted for as a
component of discontinued operations. Project Adjusted EBITDA for Greeley was $0.1 million for the year ended
December 31, 2014.
Canada
The following table summarizes Project Adjusted EBITDA for our Canada segment for the periods indicated:
Canada
Project Adjusted EBITDA
Year Ended December 31,
2016
2015
2014
% change
2016 vs. 2015 2015 vs. 2014
% change
$ 58.8 $ 59.7 $ 76.3
(2)%
(22)%
Year ended December 31, 2016 compared with Year ended December 31, 2015
Project Adjusted EBITDA for 2016 decreased by $0.9 million from 2015 primarily due to decreases in Project
Adjusted EBITDA of:
•
•
•
$2.9 million at Kapuskasing primarily due to $1.1 million of lower waste heat revenue, $1.1 million of fuel
costs under a fuel contract and $0.8 million of increased operations and maintenance expense for turbine
repairs;
$2.2 million at Calstock due primarily to a $2.8 million decrease in revenue due to the expiration of a rate
adder under its PPA and lower waste heat; and
$2.0 million at North Bay due to $1.3 million of lower waste heat revenue and $1.1 million of fuel costs
under a fuel contract.
These decreases were partially offset by an increase in Project Adjusted EBITDA of:
•
$6.7 million at Mamquam, due to $4.6 million of increased energy revenue from higher water flows in
2016 and a $2.1 million decrease in operations and maintenance expense resulting from a maintenance
outage in 2015.
Year ended December 31, 2015 compared with Year ended December 31, 2014
Project Adjusted EBITDA for 2015 decreased by $16.6 million or 22% from 2014 primarily due to decreases in
Project Adjusted EBITDA of:
•
•
•
$10.7 million at Tunis due to the expiration of its PPA in December 2014;
$4.8 million at Mamquam due to lower revenue and higher maintenance expense than the comparable 2014
period resulting from lower water flows and a maintenance outage in the third quarter of 2015; and
$3.2 million at North Bay due to higher fuel expense from costs under the project’s fuel agreements and
increased maintenance expense due to turbine repairs, partially offset by increased energy revenue from
higher waste heat generation than the comparable 2014 period.
These decreases were partially offset by an increase in Project Adjusted EBITDA of:
•
$3.1 million at Nipigon, which had an outage to upgrade its steam generator in September 2014.
65
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,
2016
2015
2014
% change
2016 vs. 2015
% change
2015 vs. 2014
$ (0.2) $ (2.5) $ (7.5)
92 %
67 %
Year ended December 31, 2016 compared with Year ended December 31, 2015
Project Adjusted EBITDA for 2016 increased by $2.3 million or 92% from the comparable 2015 period
primarily due to decreased development costs and decreased administrative expense due to a reduction in workforce.
Year ended December 31, 2015 compared with Year ended December 31, 2014
Project Adjusted EBITDA for 2015 increased by $5.0 million or 67% from the comparable 2014 period
primarily due to decreased development costs and decreased administrative expense due to a reduction in workforce.
Consolidated Cash Flow
2016 compared to 2015
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) provided by investing activities
Net cash used in financing activities
Operating Activities
2016
$ 111.8 $
(0.5)
(98.1)
2015
87.4 $
Change
24.4
(321.4)
347.7
320.9
(445.8)
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, 2016, the net increase in cash flows provided by operating activities of $24.4
million was primarily the result of the following:
• Decrease in interest payments – we made $29.3 million in lower interest payments than 2015 primarily
due to the redemption of the 9.0% Notes in July 2015 and the repurchase and cancellation of, in full,
our Series A and B and, in part, our Series C convertible debentures during 2016.
This increase was partially offset by a decrease in net cash provided by operating activities primarily
the result of the following:
•
Sale of the Wind Projects – in 2015 the Wind Projects, which were sold in June 2015, provided $21.9
million of operating cash flows.
66
Investing Activities
For the year ended December 31, 2016, the net decrease in cash flows used in investing activities of $321.4
million was primarily the result of the following:
•
Sale of Wind Projects – we received $326.3 in cash million from the sale of the Wind Projects and the
Frontier solar development project in the second quarter of 2015.
This decrease was partially offset by 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.
Financing Activities
For the year ended December 31, 2016, the net decrease in cash flows used in financing activities of $347.7
million was primarily the result of the following:
• The New Credit Facilities – we received $679.0 million of net proceeds from the issuance of New
Credit Facilities in 2016; and
• Dividend paid to common shareholders and noncontrolling interest – we paid $14.8 million in
dividends to our common shareholders and noncontrolling interests in 2015 as compared to no such
payments in 2016
These decreases were partially offset by the following:
• Corporate and project-level debt – we redeemed the Senior Secured Credit Facilities in full for $447.9
million in the second quarter of 2016 as compared to the $319.9 million paid to redeem our 9.0% High
Yield Notes in 2015;
• Repayment of convertible debentures – we paid $188.5 million in cash to redeem and cancel $191.5
million aggregate principal of our Series A, B and, in part, C convertible debentures during 2016. This
was a $169.6 million increase in convertible debenture repurchases from 2015; and
• Deferred financing costs – we incurred $16.2 million of deferred financing costs associated with the
New Term Loan Facilities during 2016.
2015 compared to 2014
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 provided by investing activities
Net cash used in financing activities
Operating Activities
2015
87.4 $
$
320.9
(445.8)
2014
65.0 $
68.7
(182.4)
Change
22.4
252.2
(263.4)
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.
67
For the year ended December 31, 2015, the net increase in cash flows from operating activities of $22.4 million
was primarily the result of the following:
• Debt retirement costs – in 2014, we paid $46.8 million of make-whole, accrued interest and premium
payments in connection with the redemption of the Series A and Series B Notes and the 5.9% Senior
Notes due 2014 issued by Curtis Palmer LLC (the “Curtis Palmer Notes”) as compared to
$19.5 million of make-whole premiums and accrued interest paid related to the redemption of our
9.0% Notes in July 2015; and
• Changes in working capital – operating cash flows increased $27.4 million from 2014 due to changes
in working capital, primarily related to changes in accrued interest and other accrued expenses.
These increases were partially offset by decreases in net cash provided by operating activities
primarily the result of the following:
•
Sale of the Wind Projects – in 2015 the Wind Projects, which were sold in June 2015, provided $21.9
million of operating cash flows partially offset by $6.3 million of withholding and alternative
minimum tax payments. In 2014, the Wind Projects provided $48.3 million of operating cash flows.
Investing Activities
For the year ended December 31, 2015, the net increase in cash flows from investing activities of $252.2
million was primarily the result of the following:
• Asset sale proceeds – an increase of $326.3 million for cash received from the sale of the Wind
Projects and the Frontier Solar Development project; and
• Restricted cash – a decrease of $65.3 million from the change in restricted cash primarily due to the
release of the $75.0 million restriction requirement under the prior credit facility in 2014.
Financing Activities
For the year ended December 31, 2015, the net increase in cash flows used in financing activities of $263.4
million was primarily the result of the following:
• Proceeds from the Senior Secured Term Loan Facilities – in February 2014, we received $600.0
million in proceeds from the issuance our Senior Secured Term Loan Facilities. During 2015, we had
no proceeds from corporate or project-level debt;
• Repayment of corporate and project-level debt – our debt repayment decreased from $639.8 million in
2014 to $403.3 million in 2015. Our 2014 repayments included $225.0 million for the repayment of
the Series A Notes and Series B Notes, $190.0 million for the Curtis Palmer Notes, and $140.1 million
aggregate principal amount of the 9.0% Notes with the proceeds from the Senior Secured Credit
Facilities. We also made $47.0 million of repayments on our Senior Secured Credit Facilities and other
non-recourse project-level debt. Our 2015 repayments included the remaining $319.9 million
aggregate principal amount of the 9.0% Notes primarily with the proceeds from the sale of the Wind
Projects and $83.4 million of repayments on our Senior Secured Credit Facilities and other non-
recourse project-level debt;
• Convertible debenture repayments – repayments on our convertible debentures decreased from $43.0
million in 2014 to $18.9 million in 2015. In 2014, we repaid our $43.0 million 6.5% Debentures due
October 2014 with cash on hand. During 2015, we paid $18.9 million to repurchase and cancel
convertible debentures under the NCIB;
• Deferred financing costs – cash paid for deferred financing costs decreased $39.0 million from 2014.
We incurred the $39.0 million of deferred financing costs in connection with the issuance of our
Senior Secured Credit Facilities in February 2014;
68
• Dividends paid to common shareholders – dividends paid to our common shareholders decreased
$23.8 million from 2014 due to a dividend reduction from Cdn$0.40 to Cdn$0.12 per share on an
annual basis in the third quarter of 2014; and
• Dividends paid to noncontrolling interests – dividends paid to noncontrolling interest decreased $7.2
million from 2014 due to the sale of the Rockland and Canadian Hills projects in June 2015.
Liquidity and Capital Resources
Cash and cash equivalents
Restricted cash
Total
Revolving credit facility availability
Total liquidity
December 31, December 31,
2016
2015
$
$
85.6 $
13.3
98.9
118.5
217.4 $
72.4
15.2
87.6
106.0
193.6
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 December 31, 2017 to December 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.”
We expect to reinvest approximately $50.6 million in our portfolio in the form of project capital expenditures
and maintenance expenses in 2017. Such investments are generally paid at the project level. See “—Capital and
Maintenance Expenditures.” We do not expect any other material or unusual requirements for cash outflow in 2017 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 28, 2017.
On December 29, 2015, we commenced a normal course issuer bid (“NCIB”), which expired on December 28,
2016. The actual amount of convertible debentures that could be purchased under the NCIB was approximately $28.5
million and was further limited to 10% of the public float of our convertible debentures. On April 13, 2016, we deposited
a portion of the proceeds from the issuance of the New Credit Facilities, for the redemption in whole on May 13, 2016 at
a price equal to par plus accrued interest (i) the outstanding Cdn$67.2 million 6.25% Debentures due March 2017 and
(ii) the outstanding Cdn$75.8 million 5.60% Debentures due June 2017. On June 17, 2016, we commenced a substantial
issuer bid (“SIB”) to purchase for cancellation up to $65.0 million aggregate principal amount of our issued and
outstanding 5.75% Series C Convertible Unsecured Subordinated Debentures maturing June 30, 2019. The offer expired
on July 22, 2016. As a result of the NCIB, the SIB and the redemptions made with proceeds from the New Credit
Facilities, we made payments of $188.5 million to redeem and cancel the 6.25% Debentures due March 2017 and the
5.60% Debentures due June 2017, in full, and the 5.75% Debentures due June 2019 and 6.00% Debentures due
December 2019, in part.
69
Dividend Elimination
On February 9, 2016, the Board of Directors, consistent with management’s recommendation, eliminated the
Company’s common share dividend, effective immediately. Previously, we paid a dividend of Cdn$0.03 per share
quarterly, with the final payment on December 31, 2015. In conjunction with the elimination of the common share
dividend, our dividend reinvestment plan was terminated.
With the additional liquidity provided by this action, we prioritized allocation of our discretionary capital (after
mandatory debt repayment) to equity and debt repurchases, each under the NCIBs implemented in December 2016 and
2015, with a goal of capturing price-to-value opportunities in our publicly traded securities. In addition, we will continue
to pursue external growth opportunities and make high-return investments in our existing projects, as well as potential
repowering projects linked to extensions of PPAs.
NCIB
On November 2, 2016, our Board of Directors approved a new NCIB for each series of our convertible
unsecured subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power
Preferred Equity Ltd (“APPEL”), our wholly-owned subsidiary. Under the NCIB, our broker may purchase up to 10% of
the public float of our convertible debentures and common shares and up to 5% of the amount issued and outstanding of
APPEL’s preferred shares, determined as of December 15, 2016, up to the following limits:
Convertible Debenture
Convertible Debenture
Common Shares
Series 1 Preferred Shares
Series 2 Preferred Shares
Series 3 Preferred Shares
Maturity
Date
June 2019
Interest
Rates
5.75 %
December 2019
6.00 % Cdn$
Limit on Purchase
(Principal Amount)
Total Limit
$
4,258,700
8,100,500
Limit on Purchase
(Number of Shares)
Total Limit (1)
11,303,772
250,000
116,904
83,095
(1) Represented 10% of the public float for the Common Shares and 5% of the amount issued and outstanding for the
Preferred Shares.
The Board authorization permits the Company to repurchase common and preferred shares and convertible
debentures through open market repurchases. There can be no assurances as to the amount, timing or prices of
repurchases, which may vary based on market conditions and other factors. The NCIB commenced on December 29,
2016 and will expire on December 28, 2017 or such earlier date as the Company and/or APPEL complete their
respective purchases pursuant to the NCIB.
70
Corporate Debt Service Obligations
The following table summarizes the maturities of our corporate debt at December 31, 2016:
New Term Loan Facility(1)
Atlantic Power Income LP
Note
Convertible Debenture
Convertible Debenture
Total Corporate Debt
Maturity
Date
April 2023
Interest
Rates
Remaining
Principal
Repayments
2017
2018
2019
2020
2021
6.00% - 6.20% $
639.9 $ 100.0 $ 90.0 $ 65.0 $ 105.0 $ 80.0 $
Thereafter
199.9
June 2036
June 2019
December 2019
5.95%
5.75%
6.00%
156.4
42.6
60.3
—
—
—
—
—
—
—
42.6
60.3
—
—
—
—
—
—
$
899.2 $ 100.0 $ 90.0 $ 167.9 $ 105.0 $ 80.0 $
156.4
—
—
356.3
(1)
The New 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 Holdings and its subsidiaries, debt service on the New Credit Facilities and the 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 New 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.
New Credit Facilities
On April 13, 2016, APLP Holdings, our wholly-owned subsidiary, entered into new Senior Secured Credit
Facilities, comprising $700 million in aggregate principal amount of New Term Loan facilities (the “New Term Loans”)
and $200 million in aggregate principal amount of senior secured revolving credit facilities (the “New Revolver” and
together with the New Term Loans, the “New Credit Facilities”). On the same date, $700 million was drawn under the
New Term Loan, bearing interest at the Adjusted Eurodollar Rate plus the applicable margin of 5.00%, and letters of
credit in an aggregate face amount of $81.5 million were issued (but not drawn) pursuant to the revolving commitments
under the New Revolver and used (i) to fund a debt service reserve in an amount equivalent to six months of debt service
(approximately $25.3 million), and (ii) to support contractual credit support obligations of APLP Holdings and its
subsidiaries and of certain other affiliates of the Company. The New Revolver matures in April 2021 and the New Term
Loans mature in April 2023. We received $679.0 million in proceeds after an original issue discount of 3% ($21.0
million).
We have used the $679.0 million proceeds from the New Term Loans to:
• redeem in whole, at a price equal to par plus accrued interest, Atlantic Power Limited Partnership’s
(“APLP”) existing Senior Secured Term Loan, maturing in February 2021, in an aggregate principal
amount outstanding of $447.9 million (see “Senior Secured Credit Facilities” below);
• redeem in whole, at a price equal to par plus accrued interest (i) our outstanding Cdn$67.2 million 6.25%
Convertible Unsecured Subordinated Debentures, Series A, maturing in March 2017 (the “Series A
Debentures”) and (ii) our outstanding Cdn$75.8 million 5.60% Convertible Unsecured Subordinated
Debentures, Series B, maturing in June 2017 (the “Series B Debentures”) (total US$ equivalent of $110.7
million);
• redeem, at a price equal to $965 per $1,000 principal amount plus accrued interest, $62.7 million of our
5.75% Convertible Unsecured Subordinated Debentures, Series C, maturing on June 30, 2019; and
• pay transaction costs and expenses of approximately $14.6 million.
71
We may use the remaining proceeds for any corporate purpose including common share repurchases, or
repurchases under the new NCIB.
We accounted for the redemption of the Senior Secured Credit Facilities as an extinguishment of debt and wrote
off $30.2 million of deferred financing costs to interest expense in the year ended December 31, 2016.
Borrowings under the New Credit Facilities are available in U.S. dollars and Canadian dollars and bear 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 varies depending on whether the loan is a Eurodollar Rate Loan, Base
Rate Loan, or Canadian Prime Rate Loan. The New Term Loans include a 3% original issue discount, and matures on
April 12, 2023. The revolving commitments under the New Revolver terminate on April 12, 2021. Letters of credit are
available to be issued under the New 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 New Credit Facilities,
APLP Holdings is required to pay a commitment fee of 0.75% times the unused commitments under the New Revolver.
The New 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 New Credit Facilities also have the benefit of a debt service reserve account,
which is required to be 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 5.95%
Medium Term Notes due June 23, 2036 (the “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 New 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 6.00:1.00 in 2016 to 4.25:1.00 from June 30, 2020, and an Interest
Coverage Ratio (as defined in the Credit Agreement) ranging from 2.75:1.00 in 2016 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 New Credit Facilities, it will be required to
offer each electing lender a prepayment of such lender’s term loans under the New 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 one year from the initial funding 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
72
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
• in respect of excess cash flow, 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 New 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 New 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 New Revolver), or
defaults under certain guaranties and collateral documents securing the New 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
share of the non-recourse project-level debt balances at December 31, 2016. 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 11, Long-term debt. Although all of our projects with
non-recourse loans, with the exception of Piedmont, 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. Currently we do not expect our Piedmont project to meet its debt service coverage
ratio covenants or to make distributions before 2018 at the earliest, due to higher forecasted maintenance and fuel
expenses than initially expected.
73
Non-Recourse Debt
The range of interest rates presented represents the rates in effect at December 31, 2016. 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 2017
2018
2019 2020
2021
Thereafter
Consolidated Projects:
Epsilon Power Partners
Piedmont
Cadillac
Total Consolidated Projects
Equity Method Projects:
Chambers(1)
Total Equity Method Projects
Total Project-Level Debt
January 2019 4.00 %
August 2018 8.22 %
August 2025 6.19 %
$
December 2019
and 2023
4.50 % - 5.00 %
$
13.5 $ 6.3 $ 6.4 $ 0.8 $ — $ — $
—
56.6
—
2.7
3.0 3.1
27.0
2.7
97.1 11.8 63.5 3.9
2.5 54.1
3.0
—
3.1
3.1
42.9
42.9
8.8
8.8
140.0 $ 11.8 $ 63.5 $ 9.1 $ 10.9 $ 11.5 $
— 5.2
— 5.2
7.8
7.8
—
—
—
—
12.1
12.1
21.1
21.1
33.2
(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 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.
The subsidiary company paid aggregate dividends of $8.5 million and $8.8 million on Series 1 Shares, Series 2
Shares and Series 3 Shares for the years ended December 31, 2016 and 2015, respectively.
74
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 $50.6 million in 2017 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 2017 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 $53.7 million of project capital expenditures and maintenance expenses for the year
ended December 31, 2016. In all cases, scheduled maintenance outages during the year ended December 31, 2016
occurred at such times that did not adversely impact the facilities’ availability requirements under their respective PPAs.
Restricted Cash
At December 31, 2016, restricted cash totaled $13.3 million as compared to $15.2 million as of December 31,
2015.
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual obligations as of December 31, 2016:
Payment Due by Period
Long-term debt including estimated interest(1)
Operating leases
Operations and maintenance commitments
Fuel purchase and transportation obligations
Other liabilities
Total contractual obligations
Less than
1 year
$ 174.9 $ 426.7 $ 257.1 $
1-3 Years 3-5 Years Thereafter
0.7
0.4
2.2
0.4
0.9
0.8
16.5
0.8
0.1
0.8
21.5
—
$ 178.6 $ 445.7 $ 279.5 $
Total
523.7 $ 1,382.4
1.7
2.2
61.7
3.7
547.9 $ 1,451.7
—
0.2
21.5
2.5
(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, 2016 was 4.0% to
8.22%.
Guarantees
We and our subsidiaries entered into various contracts that include indemnification and guarantee provisions as
a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint
venture agreements, operation and maintenance agreements, fuel purchase and transportation agreements and other types
of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify
the counterparty for certain tax, environmental liability, litigation and other matters, as well as breaches of
representations, warranties and covenants set forth in these agreements.
75
Off-Balance Sheet Arrangements
As of December 31, 2016, 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.
Impairment of long-lived assets and equity 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 may not be recoverable. 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.
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
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.
76
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.
Goodwill
Goodwill is not amortized. Instead, it is reviewed for impairment annually (in the fourth quarter) or more
frequently if indicators of impairment exist. A significant amount of judgment is involved in determining if an indicator
of impairment has occurred. Such indicators may include a prolonged decline in our market capitalization, deterioration
in general economic conditions, adverse changes in the market in which a reporting unit operates, decreases in energy or
capacity revenues as the result of re-contracting or increases in input costs that have a negative effect on earnings and
cash flows, or a trend of negative or declining cash flows over multiple periods, among others. The fair value that could
be realized in an actual transaction may differ from that used to evaluate the impairment of goodwill. Our goodwill is
allocated among and evaluated for impairment at the reporting unit level, which is one level below our operating
segments.
We apply a standard that provides an entity the option to first assess qualitative factors to determine whether the
existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair
value of a reporting unit is less than its carrying amount. These factors include an assessment of macroeconomic and
industry conditions, market events and circumstances as well as the overall financial performance of our reporting units.
Because we have not been able to make a more likely than not determination of whether the fair value of a reporting unit
is less than the carrying value for our reporting units, we have performed the two-step quantitative test for the years
ended December 31, 2016 and 2015.
Under the two-step quantitative impairment test, the evaluation of impairment involves comparing the current
fair value of each reporting unit to its carrying value, including goodwill. In the event the estimated fair value of a
reporting unit is less than the carrying value, additional analysis would be required. The additional analysis would
compare the carrying amount of the reporting unit’s goodwill with the implied fair value of that goodwill, which may
involve the use of valuation experts. The implied fair value of goodwill is the excess of the fair value of the reporting
unit over the fair value amounts assigned to all of the assets and liabilities of that unit as if the reporting unit was
acquired in a business combination and the fair value of the reporting unit represented the purchase price. If the carrying
value of goodwill exceeds its implied fair value, an impairment loss equal to such excess would be recognized, which
could significantly and adversely impact reported results of operations and shareholders’ equity.
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 step 1 and 2 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 step 1 and step 2 of the quantitative impairment test 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.
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.
77
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. 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”.
Our goodwill balance was $36.0 million and $134.5 million as of December 31, 2016 and December 31, 2015,
respectively. We apply an accounting standard under which goodwill has an indefinite life and is not amortized.
Goodwill is tested for impairments at least annually, or more frequently whenever an event or change in circumstances
occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test
goodwill for impairment at the reporting unit level, which is at the project level and, the lowest level below the operating
segments for which discrete financial information is available.
In the third quarter of 2016 (as of July 31, 2016), we performed an event-driven goodwill impairment test.
While declining power prices have 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 of goodwill at the Mamquam reporting unit, a $15.4 million partial impairment
of goodwill at the Curtis Palmer reporting unit, a $6.5 million full impairment of goodwill at the North Bay reporting
unit, a $6.7 million full impairment of goodwill 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 recorded goodwill impairment. British Columbia’s peak
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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 two years before December
2027. As a result, the discounted cash flow model for Curtis Palmer utilizes forward power prices for that two-year
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. While declining power prices have been observed over the past two years, 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.
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.
The Moresby Lake reporting unit 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 have declined significantly over the past several years. Moresby Lake failed step 2 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.
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 instruments 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.
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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.
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, 2016, we have recorded a valuation
allowance of $186.0 million.
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. We had no asset acquisitions
in the years ended December 31, 2016, 2015 and 2014, respectively.
Recent Accounting Developments
Accounting Standards Adopted in 2016
In August 2014, the FASB issued changes to the disclosure of uncertainties about an entity’s ability to continue
as a going concern. Under GAAP, continuation of a reporting entity as a going concern is presumed as the basis for
preparing financial statements unless and until the entity’s liquidation becomes imminent. Even if an entity’s liquidation
is not imminent, there may be conditions or events that raise substantial doubt about the entity’s ability to continue as a
going concern. Because there is no guidance in GAAP about management’s responsibility to evaluate whether there is
substantial doubt about an entity’s ability to continue as a going concern or to provide related note disclosures, there is
diversity in practice whether, when, and how an entity discloses the relevant conditions and events in its financial
statements. As a result, these changes require an entity’s management to evaluate whether there are conditions or events,
considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within
one year after the date that financial statements are issued. Substantial doubt is defined as an indication that it is probable
that an entity will be unable to meet its obligations as they become due within one year after the date that financial
statements are issued. If management has concluded that substantial doubt exists, then the following disclosures should
be made in the financial statements: (i) principal conditions or events that raised the substantial doubt, (ii) management’s
evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, (iii)
management’s plans that alleviated the initial substantial doubt or, if substantial doubt was not alleviated, management’s
plans that are intended to at least mitigate the conditions or events that raise substantial doubt, and (iv) if the latter in (iii)
is disclosed, an explicit statement that there is substantial doubt about the entity’s ability to continue as a going concern.
These changes became effective for us for financial statements issued after December 15, 2016, and had no impact on
the consolidated financial statements.
In January 2015, the FASB issued changes to the presentation of extraordinary items. Such items are defined
as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be
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presented separately in an entity’s income statement, net of income tax, after income from continuing operations. The
changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be
required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is
both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes became
effective for us on January 1, 2016. The adoption of these changes did not have an impact on the consolidated financial
statements.
In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it
should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited
partnerships and similar legal entities are VIEs or voting interest entities, (ii) eliminate the presumption that a general
partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are
involved with VIEs, particularly those that have fee arrangements and related party relationships, and (iv) provide a
scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to
comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment
Company Act of 1940 for registered money market funds. These changes became effective for us on January 1, 2016,
and had no impact on the consolidated financial statements.
In April 2015, the FASB issued changes to the presentation of debt issuance costs. The changes require that
debt issuance costs be presented in an entity’s balance sheet as a direct deduction from the carrying value of the related
debt liability as opposed to a non-current asset on the consolidated balance sheet. The amortization of debt issuance costs
remains unchanged. These changes became effective for us on January 1, 2016, and the adoption of these changes
resulted in a decrease of approximately $17.8 million and $42.5 million at December 31, 2016 and 2015, respectively, to
both deferred financing costs located in noncurrent assets, convertible debentures, and long-term debt on the
accompanying consolidated balance sheets.
In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a
business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments
will be recognized in the reporting period in which the adjustments are determined. The effects of changes in
depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in
earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also
required to present separately on the face of the income statement or disclose in the notes the portion of the amount
recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the
adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements became
effective for us beginning January 1, 2016. We will apply this new guidance to any future business combinations.
Accounting Standards Not Yet Adopted
In January 2017, the FASB issued authoritative guidance, which removes the requirement to perform a
hypothetical purchase price allocation to measure goodwill impairment. A goodwill impairment will now be the amount
by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. This
guidance is effective for us for annual and interim periods beginning January 1, 2020, with early adoption permitted, and
applied prospectively. We plan to adopt this guidance at the earlier of an event-driven impairment test in 2017 or when
we perform our annual goodwill impairment test in the fourth quarter of 2017. We cannot assess the impact on our
financial statements because the determination will be made based on a fair value measurement at the time the test is
conducted.
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. The guidance is effective for fiscal years beginning after December 15, 2017, with
early adoption permitted. The guidance will not have a material impact on the consolidated financial statements.
In October 2016, the FASB issued authoritative guidance, which amends existing guidance related to the
recognition of current and deferred incomes taxes for intra-entity asset transfers. Under the new guidance, current and
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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. The guidance is effective for annual periods, including interim periods
within those annual periods, beginning after December 15, 2017 with early adoption permitted. We are currently
evaluating the potential impact of the adoption 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. The guidance is effective for fiscal years
beginning after December 15, 2017, with early adoption permitted. The guidance is not expected to have a material
impact on the consolidated financial statements.
In March 2016, the FASB issued authoritative guidance intended to simplify and improve several aspects of the
accounting for share-based payment transactions. The new guidance includes amendments to share-based accounting for
income taxes, including adjustments to how excess tax benefits and a company's payments for tax withholdings should
be classified in the statement of cash flows. This guidance is effective for annual and interim reporting periods beginning
after December 15, 2016, with early adoption permitted. We are currently evaluating the potential impact on our
financial position and results of operations upon adoption of this guidance.
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. The guidance should be applied under a modified retrospective transition approach for leases existing at
the beginning of the earliest comparative period presented in the adoption-period financial statements. 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 are currently evaluating the potential impact on our financial position and results of operations
upon adoption of this guidance.
In November 2015, the FASB issued changes to the balance sheet classification of deferred taxes. These
changes simplify the presentation of deferred income taxes by requiring all deferred income tax assets and liabilities,
along with any related valuation allowance, to be classified as noncurrent in a classified balance sheet. The current
requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a
single amount is not affected by these changes. The new guidance will be effective for us in fiscal years beginning after
December 15, 2016 and is not expected to have an impact on the consolidated financial statements.
In July 2015, the FASB issued changes to the subsequent measurement of inventory. Currently, an entity is
required to measure its inventory at the lower of cost or market, whereby market can be replacement cost, net realizable
value, or net realizable value less an approximately normal profit margin. The changes require that inventory be
measured at the lower of cost and net realizable value, thereby eliminating the use of the other two market
methodologies. Net realizable value is defined as the estimated selling prices in the ordinary course of business less
reasonably predictable costs of completion, disposal, and transportation. These changes become effective for us on
January 1, 2017. We have determined that the adoption of these changes will 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
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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 will recognize 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. The new disclosure requirements will 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. Entities will generally be
required to make more estimates and use more judgment under the new standard. The new requirements will be effective
for us beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a
cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017.
Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements.
We have developed a project plan to assess the potential impact of the standard and have evaluated a sampling of our
most significant contracts (PPAs). We have approximately 20 PPAs at our consolidated projects that require further
analysis under this standard. Currently we recognize energy revenue upon transmission to the customer. Capacity
revenue is recognized when billed as hours are made available under the terms of the relevant PPA. Our current policy
appears to be in compliance with the new standard’s focus on when the customer obtains control of the goods or
services. However, these agreements are complex and still require significant analysis prior to reaching a conclusion as
to how the adoption of the standard will impact our financial position, results of operations and cash flows. Upon
adoption, we expect utilize the cumulative-effect adjustment method upon adoption as of January 1, 2018.
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 14, Accounting for derivative instruments and
hedging activities for additional information.
Fuel Commodity Market Risk
Our current and future cash flows are impacted by changes in electricity, natural gas, biomass and coal prices.
See “Item 1A. Risk Factors—Risks Related to Our Business and Our Projects—Our projects depend on third-party
suppliers under fuel supply agreements, and increases in fuel costs may adversely affect the 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.
83
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 4.9 million MMBtu of future natural gas purchases at Orlando, which
includes approximately 95% of our 2017 gas consumption and 12% of our 2018 gas consumption. These contracts are
accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at
December 31, 2016. Changes in the fair market value of these contracts are recorded in the consolidated statement of
operations. Based on our forecasted operations, a $1.00 MMBtu change in the price of natural gas would have a $0.2
million impact on estimated cash distributions for 2017.
Our 17.7%-owned Selkirk project is exposed to changes in natural gas prices. Selkirk does not have a PPA and
operates as a merchant facility. Based on our forecasted operations, a $1.00 MMBtu change in the price of natural gas
would have a $1.3 million impact on the ability to make cash distributions for 2017. We do not forecast Selkirk making
distributions in 2017.
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 Piedmont and Cadillac projects do not have long-term biomass fuel contracts. A $2 per Ton change from
our budgeted wood waste costs at these facilities would have an estimated $1.0 million total impact on forecasted cash
distributions in 2017 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 until 2019. We are exposed to the remaining 35% of the project’s
estimate fuel requirements. A $2 per Ton change from our budgeted wood waste costs at Calstock would have an
estimated $1.2 million impact on forecasted cash distributions in 2017 based on planned operations.
Coal
Our 40%-owned Chambers project is exposed to changes in coal prices. For 2017, we forecasted an average
coal price of $97.85 per Ton. A 10% change from our forecasted price would impact cash distributions from Chambers
by an estimated $1.8 million for 2017 based on planned operations.
A significant portion of energy revenue at Orlando is indexed to the price of coal burned at Duke Energy’s
Crystal River I and II steam plants in Crystal River, Florida. We estimate that a $0.25 per MMBtu price change in
Crystal River coal would have a $1.1 million impact on cash distributions from Orlando for 2017.
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, Morris, and Selkirk projects.
At our 40%-owned Chambers project, our utility customer has the right to sell a portion of the plant’s output
into the spot power market if it is profitable to do so, and the Chambers project shares in the profits from these sales. In
addition, during periods of low spot electricity prices the utility takes less generation, which negatively affects the
project’s operating margin. In 2017, projected cash distributions from Chambers would change by approximately
$1.2 million per 10% change in the PJM-East spot price of electricity.
At Morris, where we own 100% of the project, the facility can sell approximately 120 MW above the offtaker’s
demand into the grid at market prices. If market prices do not justify the increased generation the project has no
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requirement to sell power in excess of the offtaker’s demand which can negatively impact operating margins. In 2017,
projected cash distributions from Morris would change by approximately $1.0 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.
At Selkirk, where we own 17.7% of the project, 100% of the project’s capacity is currently not contracted and
is sold into the spot power market or not sold at all if market prices do not support profitable operation. We do not
expect Selkirk to make distributions in 2017.
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 project 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
many of our projects generate cash flow in U.S. dollars and Canadian dollars but we pay dividends on our preferred
shares and interest on some of our corporate level long-term debt and one of our convertible debentures, predominantly
in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on any Canadian
dollar obligation. From time to time, we execute this strategy utilizing cash flows from our projects that generate
Canadian dollars and by entering into forward contracts to purchase Canadian dollars. These foreign exchange forward
contracts are recorded at estimated fair value based on quoted market prices and the estimation of the counterparty’s
credit risk. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain)
loss in the consolidated statements of operations. As of December 31, 2016, we have no foreign currency forward
contracts as there are sufficient Canadian dollars generated from the business to cover Canadian dollar obligations.
The following table contains the components of recorded foreign exchange (gain) loss for the years ended
December 31, 2016, 2015, and 2014:
Year Ended December 31,
2015
2016
2014
Unrealized foreign exchange (gain) loss:
Convertible debentures, corporate debt, and other
Foreign currency forwards
Realized foreign exchange loss
$
$
13.8 $
—
13.8
0.1
13.9 $
(60.5) $
—
(60.5)
0.2
(60.3) $
(39.9)
1.1
(38.8)
0.5
(38.3)
A 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar would have a
$19.7 million impact on the carrying value of our corporate debt and convertible debentures denominated in Canadian
dollars at December 31, 2016.
Interest Rate Risk
Changes in interest rates impact cash payments that are required on our debt instruments as approximately
22.2% 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 $2.3 million at
December 31, 2016.
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The Partnership
APLP Holdings has entered into several interest rate swap agreements to mitigate its exposure to changes in
interest at the Adjusted Eurodollar Rate for $422.7 million notional amount of the remaining $639.9 million aggregate
principal amount of borrowings under the New Term Loans. These interest rate swap agreements expire at various dates
through March 31, 2020. Borrowings under the $700.0 million New Term Loans bear interest at a rate equal to the
Adjusted Eurodollar Rate plus an applicable margin of 5.00%. Based on the terms of the Credit Agreement, the Adjusted
Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 6.00% all-in rate on the Term Loan Facility. As a
result of entering into the swap agreements, the all-in rate for $422.7 million of the New Term Loans cannot be less than
6.00%, if the Adjusted Eurodollar Rate is equal to or greater than 1.00%.
Cadillac
We have an interest rate swap at our consolidated Cadillac project to economically fix its exposure to changes
in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of
the forecasted interest payments under the project-level Cadillac debt and changes in its fair market value are recorded in
other comprehensive loss (“OCL”). The interest rate swap expires on September 30, 2025.
In accounting for the cash flow hedge, gains and losses on the derivative contract are reported in OCL, but only
to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain
from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net
loss. That is, for a cash flow hedge, all effective components of the derivative contract’s gains and losses are recorded in
OCL, pending occurrence of the expected transaction. OCL consists of those financial items that are included in
“Accumulated other comprehensive loss” in our accompanying consolidated balance sheets but not included in our net
loss. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, OCL changes by exactly as much as
the derivative contracts and there is no impact on net loss until the expected transaction occurs.
Piedmont
The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest
rates related to its variable(cid:486)rate debt. The interest rate swap agreement effectively converts the floating rate debt to a
fixed interest rate of 4.5% with an applicable margin of 3.75%, resulting in an all(cid:486)in rate of 8.22%. The swap continues
at the fixed rate of 4.5% until November 2030. The interest rate swap agreements are not designated as hedges, and
changes in their fair market value are recorded in the consolidated statements of operations.
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.
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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 Report on Financial Statements and Practices
The accompanying Consolidated Financial Statements of Atlantic Power Corporation were prepared by
management, which is responsible for their integrity and objectivity. The statements were prepared in accordance with
GAAP and include amounts that are based on management’s best judgments and estimates. The other financial
information included in this annual report is consistent with that in the financial statements.
Management also recognizes its responsibility for conducting the Company’s affairs according to the highest
standards of personal and corporate conduct. This responsibility is characterized and reflected in key policy statements
issued from time to time regarding, among other things, conduct of its business activities within the laws of the host
countries in which the Company operates and potentially conflicting outside business interests of its employees. The
Company maintains a systematic program to assess compliance with these policies.
(c)
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, 2016 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 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.
(d)
Attestation Report of the Registered Public Accounting Firm
The effectiveness of our internal control over financial reporting as of December 31, 2016 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.
(e)
Changes in Internal Control over Financial Reporting
As previously disclosed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2015,
management concluded that a material weakness existed in the Company's internal control over financial reporting
because the Company’s internal controls over its long-lived asset and goodwill impairment tests were not designed
effectively to ensure the proper application of U.S. GAAP over (i) the determination of the carrying value of our asset
groups and reporting units used in the accounting for long-lived asset recoverability and goodwill impairment test, and
(ii) the determination of the long-lived asset and goodwill impairment charges. Specifically, with respect to (i) and (ii),
we did not design and maintain effective controls related to determining the carrying value of the asset groups for the
purpose of performing the long-lived asset impairment testing as we did not appropriately include the carrying value of
goodwill in certain long-lived asset groups in which the asset group is at the same level as the reporting unit. This
87
resulted in an initial conclusion that no long-lived asset impairment should be recorded and also impacted the carrying
value of our reporting units for step 1 and step 2 of our goodwill impairment tests.
During the fiscal year ended December 31, 2016, management developed and implemented new control
procedures in an effort to remediate the previously identified material weakness. Management took the following actions
to address the material weakness:
Implementation of new controls, relating to the long-lived asset and goodwill impairment analysis, including (i)
improved design and operation of management review controls in order to enhance the precision at which management
review controls operate, (ii) improved the documentation of internal control procedures, and (iii) enhanced controls over
the evaluation of the components of carrying value and comparison to the requirements of GAAP.
Upon completion of our testing of the design and operating effectiveness of these new control procedures in our
annual goodwill impairment analysis performed in the fourth quarter of 2016, management concluded that it has
remediated the previously identified material weakness as of December 31, 2016. Management remains committed to the
rigorous enforcement of an effective control environment.
Except as described above, there has been no change in our internal control over financial reporting during the
fourth fiscal quarter ended December 31, 2016 that has materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
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.
88
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.
89
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
2.1 Plan of Arrangement of Atlantic Power Corporation, dated as of November 24, 2005 (incorporated by
reference to our registration statement on Form 10-12B filed on April 13, 2010)
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 (incorporated by reference to our Current
Report on Form 8-K filed on June 24, 2011)
3.1 Articles of Continuance of Atlantic Power Corporation, dated as of June 29, 2010 (incorporated by reference
to our registration statement on Form 10-12B filed on July 9, 2010)
4.1 Form of common share certificate (incorporated by reference to our registration statement on Form 10-12B
filed on April 13, 2010)
4.2 Trust Indenture, dated as of October 11, 2006 between Atlantic Power Corporation and Computershare Trust
Company of Canada (incorporated by reference to our registration statement on Form 10-12B filed on
April 13, 2010)
4.3 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 (incorporated by reference to our registration statement on Form 10-12B filed on
April 13, 2010)
4.4 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
(incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
4.5 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 (incorporated by reference to our registration statement on Form S-1/A (File
No. 33-138856) filed on September 27, 2010)
4.6 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 (incorporated by reference to our Current Report on Form 8-K filed on July 6, 2012)
4.7 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 (incorporated by reference to our Current Report on Form 8-K filed on August 20,
2012)
90
Exhibit
No.
Description
4.8 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. (incorporated by
reference to our Current Report on Form 8-K filed on November 30, 2012)
4.9 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. (incorporated by
reference to our Current Report on Form 8-K filed on December 11, 2012)
4.10 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 (incorporated by reference to our Current Report on Form 8-K
filed on March 26, 2013)
Indenture, dated as of November 4, 2011, by and among Atlantic Power Corporation, the Guarantors named
therein and Wilmington Trust, National Association (incorporated by reference to our Current Report on
Form 8-K filed on November 7, 2011)
4.11
4.12 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 (incorporated by reference to our Current Report on Form 8-K filed on November 7, 2011)
4.13 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 (incorporated
by reference to our Current Report on Form 8-K filed on November 7, 2011)
4.14 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
(incorporated by reference to our Annual Report on Form 10-K filed on March 1, 2013)
4.15 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
(incorporated by reference to our Annual Report on Form 10-K filed on March 1, 2013)
4.16 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 (incorporated by reference to our Annual Report on Form 10-K filed on March 1, 2013)
4.17 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 (incorporated by reference to our Annual Report on Form 10-K filed on March 1, 2013)
4.18 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 (incorporated by reference to our Current Report on
Form 8-K filed on November 7, 2011)
4.19 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 (incorporated by reference to our Current Report on Form 8-K filed on February 28, 2013)
4.20 Advance Notice Policy, dated April 1, 2013 (incorporated by reference to our Current Report on Form 8-K
filed on April 3, 2013)
91
Exhibit
No.
Description
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 (incorporated by
reference to our Annual Report on Form 10-K filed on February 28, 2014).
10.2 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 (incorporated by reference to our Current Report on
Form 8-K filed on August 5, 2013)
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 (incorporated by reference to our Current Report on Form 8-K filed on November 21,
2012)
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 (incorporated by reference to
our Annual Report on From 10-K filed on March 1, 2013)
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 (incorporated by reference to our Quarterly Report on
Form 10-K filed on March 1, 2013)
10.8+ Employment Agreement, dated April 15, 2013, between Atlantic Power Corporation and Terrence Ronan
(incorporated by reference to our Quarterly Report on Form 10-Q filed on August 8, 2013)
10.10+ Addendum to Executive Employment Agreements of each of Terrence Ronan and Edward Hall, dated
August 30, 2013 (incorporated by reference to our Current Report on Form 8-K filed on September 5, 2013)
10.11+ Deferred Share Unit Plan, dated as of April 24, 2007 of Atlantic Power Corporation (incorporated by
reference to our registration statement on Form 10-12B filed on April 13, 2010)
10.12+ Third Amended and Restated Long-Term Incentive Plan (incorporated by reference to our registration
statement on Form 10-12B filed on July 9, 2010)
10.13+ Fourth Amended and Restated Long-Term Incentive Plan (incorporated by reference to our Annual Report on
Form 10-K filed on February 29, 2012)
10.14+ Fifth Amended and Restated Long-Term Incentive Plan (incorporated by reference to our Current Report on
Form 8-K filed on April 11, 2013)
10.15+ Amendment No. 1 to the Fifth Amended and Restated Long-Term Incentive Plan of the Company
(incorporated by reference to Exhibit A to Schedule B of the Company’s definitive Proxy Statement on
Schedule 14A filed on April 30, 2014)
92
Exhibit
No.
10.21 Amended and Restated Operating Agreement, dated as of March 30, 2012, between Atlantic Oklahoma
Description
Wind, LLC and Apex Wind Energy Holdings, LLC (incorporated by reference to our Quarterly Report on
Form 10-Q filed November 4, 2011)
10.22 Termination of the Operating Agreement of Canadian Hills Wind, LLC, dated as of December 28, 2012
(incorporated by reference to our Current Report on Form 8-K filed on January 2, 2013)
10.23 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) (incorporated by reference to our Quarterly Report on Form 10-Q filed on May 8, 2013)
10.28 Agreement dated November 24, 2014, by and among Clinton Group and the Company (incorporated by
reference to our Current Report on Form 8-K filed on November 25, 2014)
10.29+ Employment Agreement among the Company, Atlantic Power Services, LLC and James J. Moore, Jr., dated
January 22, 2015 (incorporated by reference to our Current Report on Form 8-K filed on January 23, 2015)
10.30+ Transition Equity Grant Participation Agreement between Atlantic Power Services, LLC and James J. Moore,
Jr., dated January 22, 2015 (incorporated by reference to our Current Report on Form 8-K filed on
January 23, 2015
10.32 Membership Interest Purchase Agreement by and between Atlantic Power Transmission, Inc. and Terraform
AP Acquisition Holdings, LLC dated as of March 31, 2015 (incorporated by reference to our Quarterly
Report on Form 10-Q filed on May 7, 2015)
10.33 Guaranty Agreement by Atlantic Power Corporation in favor of Terraform AP Acquisition Holdings, LLC,
dated as of March 31, 2015 (incorporated by reference to our Quarterly Report on Form 10-Q filed on May 7,
2015)
10.34 Agreement dated May 21, 2015, by and among Mangrove Partners and the Company (incorporated by
reference to our Current Report on Form 8-K filed on May 21, 2015)
10.35 Amendment No.1 to Membership Interest Purchase Agreement, dated June 3, 2015 (incorporated by
reference to our Quarterly Report on Form 10-Q filed on August 10, 2015)
10.36+ Employment Agreement among the Company, Atlantic Power Services, LLC and Joseph E. Cofelice, dated
September 15, 2015 (incorporated by reference to our Current Report on Form 8-K filed on September 16,
2015)
10.37 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 (incorporated by reference to
Exhibit 10.1 to our Current Report on Form 8-K filed on April 13, 2016)
10.38 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 (incorporated by reference to
Exhibit 10.2 to our Current Report on Form 8-K filed on April 13, 2016)
16.1 Letter from KPMG LLP, Chartered Accountants, to the Securities and Exchange Commission, dated
August 10, 2010 (incorporated by reference to our Current Report on Form 8-K filed on August 10, 2010)
21.1* Subsidiaries of Atlantic Power Corporation
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
93
Exhibit
No.
32.1** Certification of the Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906
Description
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 of
the Sarbanes-Oxley Act of 2002
101* The following materials from our Annual Report on Form 10-K for the year ended December 31, 2016
formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the
Consolidated Statements of Operations, (iii) the Consolidated Statements of Shareholders’ Equity, (iv) the
Consolidated Statements of Cash Flows, and (v) related notes to these financial statements
+ Indicates management contract or compensatory plan or arrangement.
* Filed herewith.
** Furnished herewith.
(b) Exhibits:
See Item 15(a)(3) above.
(c) Financial Statement Schedules:
See Item 15(a)(2) above.
ITEM 16. FORM 10-K SUMMARY.
None.
94
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: March 2, 2017
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
March 2, 2017
(principal executive officer)
/s/ TERRENCE RONAN
Terrence Ronan
Chief Financial Officer (Duly Authorized
Officer and Principal Financial and Accounting Officer)
/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/ HOLLI LADHANI
Holli Ladhani
Director
/s/ GILBERT S. PALTER
Gilbert S. Palter
Director
/s/ TERESA M. RESSEL
Teresa M. Ressel
Director
March 2, 2017
March 2, 2017
March 2, 2017
March 2, 2017
March 2, 2017
March 2, 2017
March 2, 2017
95
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Atlantic Power Corporation
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Audited Financial Statements
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Loss
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-58
F-62
F-1
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Atlantic Power Corporation:
We have audited Atlantic Power Corporation’s (the “Company”) internal control over financial reporting as of
December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). Atlantic Power Corporation’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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). 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 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.
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.
In our opinion, Atlantic Power Corporation maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the consolidated balance sheets of Atlantic Power Corporation and subsidiaries as of December 31, 2016 and 2015, and the
related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for each of the years in the
three-year period ended December 31, 2016, and our report dated March 2, 2017 expressed an unqualified opinion on those
consolidated financial statements.
/s/ KPMG LLP
New York, New York
March 2, 2017
F-2
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Atlantic Power Corporation:
We have audited the accompanying consolidated balance sheets of Atlantic Power Corporation and subsidiaries (the
“Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive loss,
shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016. In connection with our
audits of the consolidated financial statements, we also have audited financial statement schedules I to II in Item 15. These
consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these consolidated financial statements and financial statement schedules based on our
audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of Atlantic Power Corporation and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and
their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted
accounting principles. Also in our opinion, the related financial statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), Atlantic Power Corporation’s internal control over financial reporting as of December 31, 2016, based on criteria established
in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated March 2, 2017 expressed an unqualified opinion on the effectiveness of the Company’s
internal control over financial reporting.
/s/ KPMG LLP
New York, New York
March 2, 2017
F-3
ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of U.S. dollars)
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Current portion of derivative instruments asset (Notes 13 and 14)
Inventory (Note 6)
Prepayments
Other current assets
Total current assets
Property, plant, and equipment, net (Note 7)
Equity investments in unconsolidated affiliates (Note 5)
Power purchase agreements and intangible assets, net (Note 9)
Goodwill (Note 8)
Derivative instruments asset (Notes 13 and 14)
Other assets
Total assets
Liabilities
Current liabilities:
Accounts payable
Accrued interest
Other accrued liabilities
Current portion of long-term debt (Note 11)
Current portion of derivative instruments liability (Notes 13 and 14)
Other current liabilities
Total current liabilities
Long-term debt, net of unamortized discount and deferred financing costs (Note 11)
Convertible debentures, net of unamortized deferred financing costs (Note 12)
Derivative instruments liability (Notes 13 and 14)
Deferred income taxes (Note 15)
Power purchase and fuel supply agreement liabilities, net (Note 9)
Other long-term liabilities (Note 10)
Total liabilities
Equity
Common shares, no par value, unlimited authorized shares; 114,649,888 and 122,153,082 issued and
outstanding at December 31, 2016 and December 31, 2015
Accumulated other comprehensive loss (Note 4)
Retained deficit
Total Atlantic Power Corporation shareholders’ equity
Preferred shares issued by a subsidiary company (Note 19)
Total equity
Total liabilities and equity
See accompanying notes to consolidated financial statements.
December 31,
2016
2015
$
$
$
$
$
$
85.6
13.3
37.3
4.0
16.0
5.9
2.8
164.9
733.2
266.8
246.2
36.0
4.6
5.1
1,456.8
4.5
0.7
24.4
111.9
7.6
1.8
150.9
749.2
100.4
21.3
68.3
25.3
55.5
1,170.9
1,272.9
(148.5)
(1,059.8)
64.6
221.3
285.9
1,456.8
$
$
72.4
15.2
39.6
—
16.9
8.3
4.5
156.9
777.7
286.2
308.9
134.5
0.3
6.7
1,671.2
6.9
1.6
25.4
15.8
36.7
2.5
88.9
682.7
277.7
20.8
85.7
27.0
53.2
1,236.0
1,290.6
(139.3)
(937.4)
213.9
221.3
435.2
1,671.2
F-4
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions of U.S. dollars, except per share amounts)
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Development
Depreciation and amortization
Project other expenses:
Change in fair value of derivative instruments (Notes 13 and 14)
Equity in earnings of unconsolidated affiliates (Note 5)
Gain on sale of equity investments (Note 3)
Interest, net
Impairment (Notes 8 and 9)
Other income, net (Note 3)
Project income (loss)
Administrative and other expenses:
Administration
Interest, net
Foreign exchange loss (gain) (Note 14)
Other income, net (Note 12)
Loss from continuing operations before income taxes
Income tax benefit (Note 15)
Loss from continuing operations
Net income (loss) from discontinued operations, net of tax (Note 21)
Net loss
Net loss attributable to noncontrolling interests
Net income attributable to preferred shares dividends of a subsidiary company
Net loss attributable to Atlantic Power Corporation
Basic and diluted (loss) income per share: (Note 20)
Year Ended December 31,
2015
2014
2016
$ 184.2 $ 191.5 $ 236.9
161.3
91.7
489.9
149.3
79.4
420.2
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
165.1
103.5
1.1
110.0
379.7
210.4
109.0
3.7
122.3
445.4
15.4
36.7
—
(8.2)
(127.8)
2.0
(81.9)
(41.4)
6.8
25.5
8.6
(17.7)
(106.6)
—
(83.4)
(38.9)
22.6
106.0
13.9
(3.9)
138.6
(128.5)
(14.6)
(113.9)
—
(113.9)
—
8.5
29.4
107.1
(60.3)
(3.1)
73.1
(114.5)
(30.4)
(84.1)
19.5
(64.6)
(11.0)
8.8
37.9
146.7
(38.3)
(0.6)
145.7
(184.6)
(31.4)
(153.2)
(29.0)
(182.2)
(16.4)
11.6
(62.4) $ (177.4)
$ (122.4) $
Loss from continuing operations attributable to Atlantic Power Corporation
Income (loss) from discontinued operations, net of tax
Net loss attributable to Atlantic Power Corporation
$
$
(1.02) $
—
(1.02) $
(0.76) $
0.25
(0.51) $
(1.37)
(0.10)
(1.47)
Weighted average number of common shares outstanding: (Note 20)
Basic
Diluted
119.5
119.5
121.9
121.9
120.7
120.7
Dividends per common share:
$
— $
0.09 $
0.29
See accompanying notes to consolidated financial statements.
F-5
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in millions of U.S. dollars)
Net loss
Other comprehensive loss, net of tax:
Unrealized loss on hedging activities
Net amount reclassified to earnings
Net unrealized gain (loss) on derivatives
Defined benefit plan, net of tax
Foreign currency translation adjustments
Other comprehensive loss, net of tax
Comprehensive loss
Less: Comprehensive income (loss) attributable to noncontrolling interests
Comprehensive loss attributable to Atlantic Power Corporation
2016
$ (113.9) $
Year Ended December 31,
2015
(64.6) $ (182.2)
2014
$
(0.2) $
0.7
0.5
(0.5)
(9.2)
(9.2)
(123.1)
8.5
(1.0)
0.9
(0.1)
(1.7)
(44.1)
(45.9)
(228.1)
(4.8)
$ (131.6) $ (133.5) $ (223.3)
(0.6) $
0.7
0.1
1.6
(72.8)
(71.1)
(135.7)
(2.2)
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, 2013
Net (loss) income
Common shares issued for LTIP
Common shares issued for DRIP
Dividends declared on common shares
Dividends paid to noncontrolling interests
Dividends declared on preferred shares of a
subsidiary company
Unrealized loss on hedging activities, net of
tax of $0.3 million
Foreign currency translation adjustments
Defined benefit plan, net of tax of
$0.6 million
December 31, 2014
Net (loss) income
Common shares issued for LTIP
Common shares issued for DRIP
Common share repurchases
Dividends declared on common shares
Dividends paid to noncontrolling interests
Dividends declared on preferred shares of a
subsidiary company
Derecognition of noncontrolling interests
upon sale of subsidiaries
Unrealized gain on hedging activities, net of
tax of $0.1 million
Foreign currency translation adjustments
Defined benefit plan, net of tax of $0.6
million
December 31, 2015
Net loss
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
Retained
Common Common
Shares
Shares
(Shares) (Amount) Deficit
120.2 $ 1,286.1 $
—
2.3
—
—
—
—
0.6
0.5
—
—
(655.4) $
(177.4)
—
—
(31.1)
—
—
—
—
—
—
—
—
—
—
—
—
121.3 $ 1,288.4 $
—
0.7
0.2
(0.1)
—
—
—
2.3
—
(0.1)
—
—
—
(863.9) $
(62.4)
—
—
—
(11.1)
—
Accumulated
Other
Preferred
Shares of a
Total
Comprehensive Noncontrolling Subsidiary Shareholders’
Income (loss)
Company
Interests
Equity
(22.4) $
—
—
—
—
—
266.4 $ 221.3 $ 1,096.0
(182.2)
11.6
(16.4)
2.3
—
—
—
—
—
(31.1)
—
—
(11.0)
—
(11.0)
—
—
(11.6)
(11.6)
(0.1)
(44.1)
(1.7)
(68.3) $
—
—
—
—
—
—
—
—
—
—
—
—
239.0 $ 221.3 $
(11.0)
—
—
—
—
(3.7)
8.8
—
—
—
—
—
(0.1)
(44.1)
(1.7)
816.5
(64.6)
2.3
—
(0.1)
(11.1)
(3.7)
—
—
—
—
—
(8.8)
(8.8)
—
—
—
—
—
—
—
—
—
—
—
122.1 $ 1,290.6 $
—
1.8
—
0.5
—
(937.4) $
(122.4)
—
—
(8.0)
—
(19.5)
—
—
—
—
—
—
—
—
—
—
114.6 $ 1,272.9 $ (1,059.8) $
—
—
(224.3)
—
(224.3)
0.2
(72.8)
1.6
(139.3) $
—
—
—
—
0.5
(9.2)
—
—
—
—
0.2
(72.8)
—
—
— $ 221.3 $
8.5
—
—
—
1.6
435.2
(113.9)
1.8
—
—
—
—
(8.5)
—
(8.5)
(19.5)
—
—
0.5
(9.2)
(0.5)
(148.5) $
—
— $ 221.3 $
—
(0.5)
285.9
See accompanying notes to consolidated financial statements.
F-7
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of U.S. dollars)
Cash provided by operating activities:
Net loss
Adjustments to reconcile net loss to net cash provided by operating activities:
Years Ended December 31,
2016
2015
2014
$
(113.9)
$
(64.6)
$
(182.2)
Depreciation and amortization
Gain on sale of assets
Gain on sale of equity investments
Gain on purchase and cancellation of convertible debentures
Write off of deferred financing costs
Stock-based compensation expense
Long-lived asset and goodwill impairment charges
Equity in earnings from unconsolidated affiliates
Distributions from unconsolidated affiliates
Unrealized foreign exchange loss (gain)
Change in fair value of derivative instruments
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) provided by investing activities:
Change in restricted cash
Proceeds from sale of assets and equity investments, net
Contribution to unconsolidated affiliate
Capitalized development costs
Reimbursement of costs for third-party construction project
Purchase of property, plant and equipment
Cash (used in) provided by investing activities
Cash used in financing activities:
Proceeds from New Term Loan facility, net of discount
Common share repurchases
Repayment of corporate and project-level debt
Repayment of convertible debentures
Deferred financing costs
Dividends paid to common shareholders
Dividends paid to noncontrolling interests
Dividends paid to preferred shareholders
Cash used in financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period at discontinued operations
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental cash flow information
Interest paid
Income taxes paid, net
Accruals for construction in progress
$
$
$
$
113.5
0.2
—
(3.7)
32.8
1.8
85.9
(35.9)
55.3
13.8
(37.9)
(17.5)
2.3
0.9
17.0
(0.2)
(2.6)
111.8
1.9
—
—
—
4.8
(7.2)
(0.5)
679.0
(19.5)
(544.4)
(188.5)
(16.2)
—
—
(8.5)
(98.1)
13.2
—
72.4
85.6
70.7
3.5
1.2
$
$
$
$
120.3
(48.7)
—
(3.1)
9.0
2.3
127.8
(36.2)
58.5
(60.5)
(14.7)
(3.5)
5.7
2.4
11.9
(8.9)
(10.3)
87.4
7.3
326.3
(0.6)
(0.8)
—
(11.3)
320.9
—
—
(403.3)
(18.9)
—
(11.1)
(3.7)
(8.8)
(445.8)
(37.5)
3.9
106.0
72.4
100.0
10.2
0.6
$
$
$
$
162.6
(2.9)
(8.6)
—
—
3.5
106.6
(25.8)
76.2
(38.8)
8.7
(15.7)
6.9
(3.3)
21.1
(4.1)
(39.2)
65.0
72.6
9.5
—
—
—
(13.4)
68.7
600.0
—
(639.8)
(43.0)
(39.0)
(34.9)
(11.1)
(14.6)
(182.4)
(48.7)
(3.9)
158.6
106.0
168.8
3.8
—
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 owns and operates a diverse fleet of power generation assets in the United States and Canada.
Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term
power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of
December 31, 2016, our power generation projects had an aggregate gross electric generation capacity of approximately
2,138 megawatts (“MW”) in which our aggregate ownership interest is approximately 1,500 MW. Our current portfolio
consists of interests in twenty-three power generation projects across nine states in the United States and two provinces
in Canada. Nineteen of the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337
MW on a net ownership basis. The remaining four projects, all in Ontario, are not operational, three due to revised
contractual arrangements with the offtaker and the other, Tunis, has a forward-starting 15-year contractual agreement
that will commence between November 2017 and June 2019. Eighteen of our projects are majority-owned.
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 220, 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.
(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 $17.8 million and $42.5 million at December 31, 2016 and 2015, respectively. Interest expense from the
amortization of deferred finance costs for the years ended December 31, 2016, 2015, and 2014 was $40.8 million,
$20.5 million, and $16.5 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 or 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.
(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
F-10
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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
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
F-11
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 two-step quantitative impairment
test. In the first step of 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 and the second step of the impairment test is unnecessary.
The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which
case, the implied fair value of the reporting unit’s goodwill is compared with its carrying amount to measure the amount
of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of
goodwill is determined in a business combination, using the fair value of the reporting unit as if it were the purchase
price. When the carrying amount of reporting unit goodwill exceeds the implied fair value of the goodwill, an
impairment loss is recognized in an amount equal to the excess and is recorded in the consolidated statements of
operations.
(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)
Assets held for sale and discontinued operations:
For those businesses where we have committed to a plan to divest, each business is valued at the lower of its
carrying amount or estimated fair value less cost to sell. If the carrying amount of the business exceeds its estimated fair
value, an impairment loss is recognized. Fair value is estimated using accepted valuation techniques such as a discounted
cash flow model, valuations performed by third parties, earnings multiples, or indicative bids, when available. A number
of significant estimates and assumptions are involved in the application of these techniques, including the forecasting of
markets and market share, sales volumes and prices, costs and expenses, and multiple other factors. We consider
historical experience and all available information at the time the estimates are made; however, the fair value that is
ultimately realized upon the divestiture of a business may differ from the estimated fair value reflected in the
consolidated financial statements. Depreciation and amortization expense is not recorded on assets of a business to be
F-12
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
divested once they are classified as held for sale. Businesses to be divested are classified in the consolidated financial
statements as either discontinued operations or held for sale.
For businesses classified as discontinued operations, the balance sheet amounts and results of operations are
reclassified from their historical presentation to assets and liabilities of operations held for sale on the consolidated
balance sheet and to discontinued operations on the consolidated statements of operations, respectively, for all periods
presented. The gains or losses associated with these divested businesses are recorded in discontinued operations on the
consolidated statements of operations. Segment information does not include the assets or operating results of businesses
classified as discontinued operations for all periods presented.
(o)
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 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
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
Foreign exchange (gain) loss
Foreign exchange (gain) loss
(p)
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 15 for more information.
F-13
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(q)
Revenue recognition:
We recognize energy sales revenue on a gross basis when electricity and steam are delivered under the terms of
the related contracts. PPAs, steam purchase arrangements and energy services agreements are long-term contracts to sell
power and steam on a predetermined basis.
Energy—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.
Capacity—Capacity payments under the PPAs are recognized as the amount billable under the PPA.
(r)
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.
(s)
Power purchase arrangements containing a lease:
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.
(t)
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.
(u)
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
F-14
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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. In 2016, we have estimated a weighted average forfeiture rate of 11% for the long-
term incentive plan (“LTIP”) granted in 2016. 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.
(v)
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.
(w)
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
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 and the rate of future compensation increases. Our actuarial consultants use
assumptions for such items as 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.
(x)
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.
(y)
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
F-15
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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.
(z)
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.
(aa)
Recently adopted and issued accounting standards:
Accounting Standards Adopted in 2016
In August 2014, the FASB issued changes to the disclosure of uncertainties about an entity’s ability to continue
as a going concern. Under GAAP, continuation of a reporting entity as a going concern is presumed as the basis for
preparing financial statements unless and until the entity’s liquidation becomes imminent. Even if an entity’s liquidation
is not imminent, there may be conditions or events that raise substantial doubt about the entity’s ability to continue as a
going concern. Because there is no guidance in GAAP about management’s responsibility to evaluate whether there is
substantial doubt about an entity’s ability to continue as a going concern or to provide related note disclosures, there is
diversity in practice whether, when, and how an entity discloses the relevant conditions and events in its financial
statements. As a result, these changes require an entity’s management to evaluate whether there are conditions or events,
considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within
one year after the date that financial statements are issued. Substantial doubt is defined as an indication that it is probable
that an entity will be unable to meet its obligations as they become due within one year after the date that financial
statements are issued. If management has concluded that substantial doubt exists, then the following disclosures should
be made in the financial statements: (i) principal conditions or events that raised the substantial doubt, (ii) management’s
evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, (iii)
management’s plans that alleviated the initial substantial doubt or, if substantial doubt was not alleviated, management’s
plans that are intended to at least mitigate the conditions or events that raise substantial doubt, and (iv) if the latter in (iii)
is disclosed, an explicit statement that there is substantial doubt about the entity’s ability to continue as a going concern.
These changes became effective for us for financial statements issued after December 15, 2016, and had no impact on
the consolidated financial statements.
In January 2015, the FASB issued changes to the presentation of extraordinary items. Such items are defined
as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be
presented separately in an entity’s income statement, net of income tax, after income from continuing operations. The
changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be
required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is
F-16
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes became
effective for us on January 1, 2016. The adoption of these changes did not have an impact on the consolidated financial
statements.
In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it
should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited
partnerships and similar legal entities are VIEs or voting interest entities, (ii) eliminate the presumption that a general
partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are
involved with VIEs, particularly those that have fee arrangements and related party relationships, and (iv) provide a
scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to
comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment
Company Act of 1940 for registered money market funds. These changes became effective for us on January 1, 2016,
and had no impact on the consolidated financial statements.
In April 2015, the FASB issued changes to the presentation of debt issuance costs. The changes require that
debt issuance costs be presented in an entity’s balance sheet as a direct deduction from the carrying value of the related
debt liability as opposed to a non-current asset on the consolidated balance sheet. The amortization of debt issuance costs
remains unchanged. These changes became effective for us on January 1, 2016, and the adoption of these changes
resulted in a decrease of approximately $17.8 million and $42.5 million at December 31, 2016 and 2015, respectively, to
both deferred financing costs located in noncurrent assets, convertible debentures, and long-term debt on the
accompanying consolidated balance sheets.
In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a
business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments
will be recognized in the reporting period in which the adjustments are determined. The effects of changes in
depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in
earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also
required to present separately on the face of the income statement or disclose in the notes the portion of the amount
recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the
adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements became
effective for us beginning January 1, 2016. We will apply this new guidance to any future business combinations.
Accounting Standards Not Yet Adopted
In January 2017, the FASB issued authoritative guidance, which removes the requirement to perform a
hypothetical purchase price allocation to measure goodwill impairment. A goodwill impairment will now be the amount
by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. This
guidance is effective for us for annual and interim periods beginning January 1, 2020, with early adoption permitted, and
applied prospectively. We plan to adopt this guidance the earlier of an event-driven impairment test in 2017 or when we
perform our annual goodwill impairment test in the fourth quarter of 2017. We cannot assess the impact on our financial
statements because the determination will be made based on a fair value measurement at the time the test is conducted.
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. The guidance is effective for fiscal years beginning after December 15, 2017, with
early adoption permitted. The guidance will not have a material impact on the consolidated financial statements.
In October 2016, the FASB issued authoritative guidance, which amends existing guidance related to the
F-17
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
recognition of current and deferred incomes 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. The guidance is effective for annual periods, including interim periods
within those annual periods, beginning after December 15, 2017 with early adoption permitted. We are currently
evaluating the potential impact of the adoption 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. The guidance is effective for fiscal years
beginning after December 15, 2017, with early adoption permitted. The guidance is not expected to have a material
impact on the consolidated financial statements.
In March 2016, the FASB issued authoritative guidance intended to simplify and improve several aspects of the
accounting for share-based payment transactions. The new guidance includes amendments to share-based accounting for
income taxes, including adjustments to how excess tax benefits and a company's payments for tax withholdings should
be classified in the statement of cash flows. This guidance is effective for annual and interim reporting periods beginning
after December 15, 2016, with early adoption permitted. We are currently evaluating the potential impact on our
financial position and results of operations upon adoption of this guidance.
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. The guidance should be applied under a modified retrospective transition approach for leases existing at
the beginning of the earliest comparative period presented in the adoption-period financial statements. 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 are currently evaluating the potential impact on our financial position and results of operations
upon adoption of this guidance.
In November 2015, the FASB issued changes to the balance sheet classification of deferred taxes. These
changes simplify the presentation of deferred income taxes by requiring all deferred income tax assets and liabilities,
along with any related valuation allowance, to be classified as noncurrent in a classified balance sheet. The current
requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a
single amount is not affected by these changes. The new guidance will be effective for us in fiscal years beginning after
December 15, 2016 and is not expected to have an impact on the consolidated financial statements.
In July 2015, the FASB issued changes to the subsequent measurement of inventory. Currently, an entity is
required to measure its inventory at the lower of cost or market, whereby market can be replacement cost, net realizable
value, or net realizable value less an approximately normal profit margin. The changes require that inventory be
measured at the lower of cost and net realizable value, thereby eliminating the use of the other two market
methodologies. Net realizable value is defined as the estimated selling prices in the ordinary course of business less
F-18
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
reasonably predictable costs of completion, disposal, and transportation. These changes become effective for us on
January 1, 2017. We have determined that the adoption of these changes will 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 will recognize 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. The new disclosure requirements will 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. Entities will generally be
required to make more estimates and use more judgment under the new standard. The new requirements will be effective
for us beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a
cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017.
Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements.
We have developed a project plan to assess the potential impact of the standard and have evaluated a sampling of our
most significant contracts (PPAs). We have approximately 20 PPAs at our consolidated projects that require further
analysis under this standard. Currently we recognize energy revenue upon transmission to the customer. Capacity
revenue is recognized when billed as hours are made available under the terms of the relevant PPA. Our current policy
appears to be in compliance with the new standard’s focus on when the customer obtains control of the goods or
services. However, these agreements are complex and still require significant analysis prior to reaching a conclusion as
to how the adoption of the standard will impact our financial position, results of operations and cash flows. We expect to
utilize the cumulative-effect adjustment method upon adoption as of January 1, 2018.
3. Divestments
2015 Divestments
(a)
Wind Projects
On March 31, 2015, Atlantic Power Transmission (“APT”), our wholly-owned, direct subsidiary, entered into a
purchase agreement with TerraForm AP Acquisition Holdings, LLC (“TerraForm”), an affiliate of SunEdison, Inc., to
sell our Wind Projects. On June 26, 2015, the sale was completed for aggregate cash proceeds of approximately $335
million after transaction fees, exclusive of transaction-related taxes. We recorded a $46.8 million gain on sale, which is
included as a component of income from discontinued operations in the consolidated statements of operations for the
year ended December 31, 2015.
Terraform acquired from APT, 100% of APT’s direct membership interests in a holding company formed to
facilitate the sale, thereby acquiring our indirect interests in our portfolio of Wind Projects consisting of five operating
wind projects in Idaho and Oklahoma and representing 521 MW net ownership: Goshen (12.5% economic interest),
Idaho Wind (27.6% economic interest), Meadow Creek (100% economic interest); Rockland Wind Farm (50%
economic interest, but consolidated on a 100% basis); and Canadian Hills (99% economic interest). As a result of the
sale, we deconsolidated approximately $249 million of project debt (or approximately $274 million as adjusted for our
proportional ownership of Rockland, Goshen North and Idaho Wind) and approximately $224 million of non-controlling
interest related to tax equity interests at Canadian Hills and the minority ownership interests at Rockland and Canadian
Hills.
F-19
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The Wind Projects were designated as assets held for sale and discontinued operations on March 31, 2015, the
date we established a firm commitment to a plan to sell the wind assets. Our determination to designate the Wind
Projects as discontinued operations was based on the impact the sale will have on our operations and financial results
and because the Wind Projects made up the entirety of our Wind Reportable Segment. We stopped depreciating the
property, plant and equipment of the Wind Projects on the designation date.
(b)
Frontier
On April 22, 2015, our indirect wholly-owned subsidiary, Ridgeline Energy LLC (‘‘Ridgeline’), closed a
transaction with CRE-Frontier Solar California LLC (‘‘CRE’’), a subsidiary of Centaurus Renewable Energy LLC,
whereby CRE agreed to purchase 100% of Ridgeline’s equity interests in Frontier Solar, LLC (‘‘Frontier’’), which is
developing an approximately 20 MW solar electric generating facility in California, for net cash proceeds of $4.3
million. If Frontier achieves commercial operations and meets certain operating performance metrics, we could receive
additional cash proceeds. We recorded a $2.3 million gain on sale related to the transaction in other income in the
consolidated statements of operations for the year ended December 31, 2015. Frontier is not accounted for as a
component of discontinued operations.
2014 Divestments
(a)
Delta-Person
In December 2012, we and the other owners of Delta-Person, entered into a purchase and sale agreement with
BHB Power, LLC and Public Service Company of New Mexico to sell the project for approximately $37.2 million
including working capital adjustments. The sale of Delta-Person closed in July 2014 resulting in a gain on sale of
approximately $8.6 million in the consolidated statement of operations for the year ended December 31, 2014. We
received net cash proceeds in July 2014 for our ownership interest of approximately $7.2 million in the aggregate. Delta-
Person is not accounted for as a component of discontinued operations.
(b)
Greeley
In March 2014, we closed a transaction with Initium Power Partners, LLC. (“Initium”), whereby Initium agreed
to purchase all of the issued and outstanding membership interests in Greeley for approximately $1.0 million. We
recorded a $2.1 million non-cash gain on the sale, which is included as a component of income from discontinued
operations in the consolidated statement of operations for the year ended December 31, 2014.
F-20
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
4. 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:
Unrecognized net actuarial gain (loss)
Tax benefit (expense)
Total Other comprehensive (loss) income before reclassifications, net of tax
Amortization of net actuarial loss
Tax benefit
Total amount reclassified from accumulated other comprehensive loss, net
of tax
Total other comprehensive (loss) income
Balance at end of period
Cash flow hedges
Balance at beginning of period
Other comprehensive loss:
Net change from periodic revaluations
Tax benefit
Total Other comprehensive loss 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 (loss) income
Balance at end of period
Year Ended December 31,
2015
2014
2016
$ (139.1) $
(66.3) $
(22.2)
(9.2)
(72.8)
$ (148.3) $ (139.1) $
(44.1)
(66.3)
$
(0.4) $
(2.1) $
(0.4)
(0.7)
0.2
(0.5)
—
—
2.2
(0.6)
1.6
0.1
—
(2.3)
0.6
(1.7)
—
—
—
(1.7)
(2.1)
—
(0.5)
(0.9) $
0.1
1.7
(0.4) $
$
$
0.2 $
0.1 $
0.2
(0.3)
0.1
(0.2)
1.0
(0.3)
(1.0)
0.4
(0.6)
1.3
(0.6)
0.7
0.5
0.7 $
0.7
0.1
0.2 $
$
(1.7)
0.7
(1.0)
1.5
(0.6)
0.9
(0.1)
0.1
(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-21
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
5. 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
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Total
Percentage of
Ownership as of
December 31, 2016
Carrying value as of
December 31,
2016
2015
50.2 % $ 115.3 $ 124.7
8.4
7.3
50.0 %
5.4
5.0
49.8 %
135.7
40.0 % 127.6
12.0
11.6
17.7 %
$ 266.8 $ 286.2
(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 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.
Deficit in earnings of equity method investments, net of distributions, was as follows:
Entity name
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Total
Distributions from equity method investments
Deficit in earnings of equity method investments, net of
distributions
Year Ended December 31,
2015
2014
2016
$
2.2 $
2.6 $
27.8
0.8
5.5
(0.4)
35.9
(55.3)
27.0
0.4
6.5
0.2
36.7
(58.5)
2.2
18.6
0.9
7.0
(3.2)
25.5
(76.2)
$ (19.4) $ (21.8) $ (50.7)
Distributions from equity method investments exceeded earnings of equity method investments for the years
ended December 31, 2016, 2015 and 2014, respectively. Distributions from are 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 or changes in the fair value of derivative financial instruments.
F-22
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, 2016, 2015 and 2014, and operating results
for the years ended December 31, 2016, 2015 and 2014, respectively, for our proportional ownership interest in equity
method investments:
2016
2015
2014
$
1.7 $
7.5
0.6
15.0
11.3
1.8 $
10.0
0.7
15.0
11.5
1.8
6.3
0.7
14.4
12.2
114.1
9.1
5.0
190.0
2.4
134.0
11.3
5.5
213.4
1.7
$ 356.7 $ 382.4 $ 401.3
124.0
10.2
5.3
201.7
2.2
$
0.1 $
9.2
0.1
3.8
0.6
0.7 $
11.7
0.6
3.7
—
0.3
6.5
0.1
3.5
1.3
0.5
—
0.5
73.6
1.5
0.4
0.1
0.5
81.0
0.7
$ 89.9 $ 96.2 $ 94.4
0.4
—
0.5
77.3
1.3
Assets
Current assets
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Non-current assets
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Liabilities
Current liabilities
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Non-current liabilities
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
F-23
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
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Delta Person, LP
Project expenses
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Delta Person, LP
Project other expense
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Delta Person, LP
Project income
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Delta Person, LP
2016
2015
2014
$ 20.7 $ 21.6 $ 20.6
50.5
1.9
54.8
41.6
1.8
171.2
54.6
1.9
44.7
7.9
—
129.8
54.1
1.5
48.0
11.6
—
136.8
18.5
26.9
1.1
37.4
8.2
—
92.1
—
—
—
(1.8)
—
—
(1.8)
19.0
27.1
1.1
39.7
11.6
—
98.5
18.4
31.9
1.0
44.8
44.1
1.7
141.9
—
—
—
(1.8)
0.2
—
(1.6)
—
—
—
(3.0)
(0.7)
(0.1)
(3.8)
2.2
27.7
0.8
5.5
(0.3)
—
2.2
18.6
0.9
7.0
(3.2)
—
$ 35.9 $ 36.7 $ 25.5
2.6
27.0
0.4
6.5
0.2
—
6. Inventory
Inventory consists of the following:
Parts and other consumables
Fuel
Total inventory
December 31,
2016
10.0 $
6.0
16.0 $
2015
9.3
7.6
16.9
$
$
F-24
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
7. Property, plant and equipment, net
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
$
2016
5.3 $
5.6
2.2
27.7
981.1
1,021.9
(288.7)
733.2 $
2015
5.2
5.6
—
27.4
975.8
1,014.0
(236.3)
777.7
Depreciable
Lives
3 - 10 years
7 - 15 years
1 - 43 years
1 - 45 years
Depreciation expense of $49.5 million, $59.0 million and $64.6 million was recorded for the years ended
December 31, 2016, 2015 and 2014, respectively.
As described in Note 8, Goodwill, we recorded a $5.9 million and a $76.6 million long-lived asset impairment
to property, plant and equipment in the years ended December 31, 2016 and 2015, respectively.
8. Goodwill
Our goodwill balance was $36.0 million and $134.5 million as of December 31, 2016 and December 31, 2015,
respectively. We apply an accounting standard under which goodwill has an indefinite life and is not amortized.
Goodwill is tested for impairments at least annually, or more frequently whenever an event or change in circumstances
occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test
goodwill for impairment at the reporting unit level, which is at the project level and, the lowest level below the operating
segments for which discrete financial information is available.
In the third quarter of 2016, we performed an event-driven goodwill impairment test as of July 31, 2016. While
declining power prices have 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
F-25
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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
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 two years before December 2027. As a result, the discounted cash flow
model for Curtis Palmer utilizes forward power prices for that two-year 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. While declining power prices have been observed over the past two years, 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.
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.
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
F-26
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
forward prices have 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.
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 long-lived asset recovery and step 1 and 2
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 step 1 and step 2 of the quantitative impairment test
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.
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.
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.
F-27
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table is a rollforward of goodwill for the years ended December 31, 2016 and 2015:
Reporting unit
Segment
2015
Impairment
December 31,
Translation
adjustment
December 31,
2016
Curtis Palmer
Morris
Kapuskasing
Mamquam
Moresby Lake
Nipigon
North Bay
East U.S.
East U.S.
Canada
Canada
Canada
Canada
Canada
$
$
44.5 $
3.3
8.8
64.4
1.6
3.6
8.3
134.5 $
(15.4) $
—
(6.7)
(50.2)
(1.2)
—
(6.5)
(80.0) $
— $
—
(2.1)
(14.2)
(0.4)
—
(1.8)
(18.5) $
29.1
3.3
—
—
—
3.6
—
36.0
Reporting unit
Segment
2014
Impairment
December 31,
Translation
adjustment
December 31,
2015
Curtis Palmer
Morris
Kapuskasing
Mamquam
Moresby Lake
Williams Lake
Calstock
Nipigon
North Bay
East U.S.
East U.S.
Canada
Canada
Canada
Canada
Canada
Canada
Canada
$
$
58.2 $
3.3
8.8
64.4
1.6
46.4
2.6
3.6
8.3
197.2 $
(13.7) $
—
—
—
—
(35.6)
(1.9)
—
—
(51.2) $
— $
—
—
—
—
(10.8)
(0.7)
—
—
(11.5) $
44.5
3.3
8.8
64.4
1.6
—
—
3.6
8.3
134.5
9. PPAs and other intangible assets and liabilities
Other intangible assets and liabilities include PPAs, fuel supply agreements and capitalized development costs.
In December 2016, we entered into agreements to terminate our PPAs at North Bay and Kapuskasing originally
scheduled to expire on December 31, 2017. As a result, we wrote off the remaining intangible assets related to these
PPAs and recorded $12.7 million of accelerated amortization expense in the year ended December 31, 2016.
F-28
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following tables summarize the components of our intangible assets and other liabilities subject to
amortization at December 31, 2016 and 2015:
Assets
Gross balances, December 31, 2016
Less: accumulated amortization
Net carrying amounts, December 31, 2016
Gross balances, December 31, 2015
Less: accumulated amortization
Net carrying amounts, December 31, 2015
Liabilities
Gross balances, December 31, 2016
Less: accumulated amortization
Net carrying amounts, December 31, 2016
Gross balances, December 31, 2015
Less: accumulated amortization
Net carrying amounts, December 31, 2015
Other Intangible Assets, Net
Development
Power Purchase
Agreements
$
538.7 $
(292.7)
246.0
$
$
Costs
13.0 $
(12.8)
0.2
$
Total
551.7
(305.5)
246.2
Other Intangible Assets, Net
Development
Power Purchase
Agreements
$
534.0 $
(225.4)
308.6
$
$
Costs
12.9 $
(12.6)
0.3
$
Total
546.9
(238.0)
308.9
Power Purchase and Fuel Supply Agreement Liabilities, Net
Power Purchase
Fuel Supply
Agreements
Agreements
Total
$
$
(29.0) $
11.0
(18.0)
$
(12.6) $
5.3
(7.3)
$
(41.6)
16.3
(25.3)
Power Purchase and Fuel Supply Agreement Liabilities, Net
Power Purchase
Fuel Supply
Agreements
Agreements
Total
$
$
(28.4) $
(12.6) $
9.1
(19.3)
$
4.9
(7.7)
$
(41.0)
14.0
(27.0)
The following table presents amortization expense of intangible assets for the years ended December 31, 2016,
2015 and 2014:
2014
2016
2015
$ 63.3 $ 51.3 $ 57.6
(1.2)
$ 62.9 $ 50.1 $ 56.4
(0.4)
(1.2)
PPAs
Fuel supply agreements
Total amortization
F-29
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table presents estimated future amortization expense for the next five years related to PPAs and
fuel supply agreements:
Year Ended December 31,
2017
2018
2019
2020
2021
Power Purchase Fuel Supply
Agreements
Agreements
(0.4)
$
(0.4)
(0.4)
(0.4)
(0.4)
38.0 $
36.9
36.3
25.5
22.9
The following table presents the weighted average remaining amortization period related to our intangible
assets as of December 31, 2016:
As of December 31, 2016
(in years)
Weighted average remaining amortization period
Power Purchase Fuel Supply
Agreements
Agreements
7.9
18.6
10. Other long-term liabilities
Other long-term liabilities consist of the following at December 31:
Asset retirement obligations
Net pension liability
Deferred revenue
Accrued LTIP and director share units
Other
2016
50.3 $
1.3
—
1.7
2.2
55.5 $
2015
48.5
0.6
0.5
1.1
2.5
53.2
$
$
The following table is a rollforward of asset retirement obligations for the years ended December 31:
Asset retirement obligations beginning of year
Accretion of asset retirement obligations
Translation adjustments
Asset retirement obligations, end of year
2016
48.5 $
1.2
0.6
50.3 $
2015
51.2
1.1
(3.8)
48.5
$
$
F-30
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
11. Long-term debt
Long-term debt consists of the following:
Recourse Debt:
Senior Secured Term Loan facility, due 2021
New Term Loan facility, due 2023(2)
Senior unsecured notes, due June 2036 (Cdn$210.0)
Non-Recourse Debt:
Epsilon Power Partners term facility, due 2019
Cadillac term loan, due 2025
Piedmont term loan, due 2018
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:
Current Maturities:
Senior Secured Term Loan facility, due 2021
New Term Loan facility, due 2023(2)
Epsilon Power Partners term facility, due 2019
Cadillac term loan, due 2025
Piedmont term loan, due 2018
Other short-term debt
Total current maturities
December 31, December 31,
2016
2015
Interest Rate
$
— $
639.9
156.4
13.5
27.0
56.6
0.2
(17.2)
(15.3)
(111.9)
749.2 $
$
473.2
LIBOR(1) plus
— LIBOR(1) plus
151.7
3.75 %
5.00 %
5.95 %
19.5 LIBOR(3) plus 3.125 %
1.37 %
29.5
LIBOR plus
59.0 LIBOR(3) plus
3.75 %
0.4
6.70 %
5.50 % -
—
(34.8)
(15.8)
682.7
December 31, December 31,
2016
2015
Interest Rate
$
$
— $
100.0
6.2
3.0
2.5
0.2
111.9 $
LIBOR(1) plus 3.75 %
4.7
LIBOR(1) plus 5.00 %
—
6.0 LIBORplus 3.125 %
LIBOR(3) plus 1.37 %
2.5
LIBOR(3) plus 3.75 %
2.4
5.50 % - 6.70 %
0.2
15.8
(1) LIBOR cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the
exposure to changes in LIBOR for $422.7 million of the $639.9 million outstanding aggregate
borrowings under our New Term Loan facility at December 31, 2016. See Note 14, Accounting for
derivative instruments and hedging activities for further details.
(2) 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 New Term Loan facility
classified as current is based on principal payments required to reduce the aggregate principal amount
of New Term Loans outstanding to achieve a target principal amount that declines quarterly based on a
pre-determined specified schedule.
(3) We have entered into interest rate swap agreements to economically fix our exposure to changes in
interest rates for this non-recourse debt. See Note 14, Accounting for derivative instruments and
hedging activities, for further details.
F-31
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:
2017
2018
2019
2020
2021
Thereafter
New Credit Facilities
$
$
111.9
153.4
68.9
108.1
82.7
368.6
893.6
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 “New Term Loans”) and $200 million in aggregate principal amount of senior secured
revolving credit facilities (the “New Revolver” and together with the New Term Loans, the “New Credit Facilities”). On
the same date, $700 million was drawn under the New Term Loan, bearing interest at the Adjusted Eurodollar Rate plus
the applicable margin of 5.00%, and letters of credit in an aggregate face amount of $105.8 million ($81.5 million at
December 31, 2016) were issued (but not drawn) pursuant to the revolving commitments under the New Revolver and
used (i) to fund a debt service reserve in an amount equivalent to six months of debt service (approximately $25.3
million), and (ii) to support contractual credit support obligations of APLP Holdings and its subsidiaries and of certain
other affiliates of the Company. The New Revolver matures in April 2021 and the New Term Loans mature in April
2023. We received $679.0 million in proceeds after an original issue discount of 3% ($21.0 million).
We have used the $679.0 million proceeds from the New Term Loans to:
• redeem in whole, at a price equal to par plus accrued interest, Atlantic Power Limited Partnership’s
(“APLP”) existing Senior Secured Term Loan, maturing in February 2021, in an aggregate principal
amount outstanding of $447.9 million (see “Senior Secured Credit Facilities” below);
• redeem in whole, at a price equal to par plus accrued interest (i) our outstanding Cdn$67.2 million 6.25%
Convertible Unsecured Subordinated Debentures, Series A, maturing in March 2017 (the “Series A
Debentures”) and (ii) our outstanding Cdn$75.8 million 5.60% Convertible Unsecured Subordinated
Debentures, Series B, maturing in June 2017 (the “Series B Debentures”) (total US$ equivalent of $110.7
million);
• redeem, at a price equal to $965 per $1,000 principal amount plus accrued interest, $62.7 million of our
5.75% Convertible Unsecured Subordinated Debentures, Series C, maturing on June 30, 2019; and
• pay transaction costs and expenses of approximately $14.6 million.
We may use the remaining proceeds for any corporate purpose including additional common share repurchases.
We accounted for the redemption of the Senior Secured Credit Facilities as an extinguishment of debt and wrote
off $30.2 million of deferred financing costs to interest expense in the year ended December 31, 2016.
Borrowings under the New Credit Facilities are available in U.S. dollars and Canadian dollars and bear 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 varies depending on whether the loan is a Eurodollar Rate Loan, Base
Rate Loan, or Canadian Prime Rate Loan. The New Term Loans include a 3% original issue discount, and matures on
April 12, 2023. The revolving commitments under the New Revolver terminate on April 12, 2021. Letters of credit are
available to be issued under the New Revolver until 30 days prior to the Letter of Credit Expiration Date under, and as
F-32
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
defined in, the Credit Agreement. In addition to paying interest on outstanding principal under the New Credit Facilities,
APLP Holdings is required to pay a commitment fee of 0.75% times the unused commitments under the New Revolver.
The New 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 New 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 5.95%
Medium Term Notes due June 23, 2036 (the “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 New 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 6.00:1.00 in 2016 to 4.25:1.00 from June 30, 2020, and an Interest
Coverage Ratio (as defined in the Credit Agreement) ranging from 2.75:1.00 in 2016 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 New Credit Facilities, it will be required to
offer each electing lender a prepayment of such lender’s term loans under the New 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 one year from the initial funding 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
F-33
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
service on the New 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 New 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 New Revolver), or
defaults under certain guaranties and collateral documents securing the New Credit Facilities, in each case subject to
various exceptions and notice, cure and grace periods.
As of December 31, 2016, we had no amount outstanding and $81.5 million issued in letters of credit under our
revolving credit facility.
Senior Secured Credit Facilities
As noted above in “New Credit Facilities”, the Company’s Senior Secured Credit Facilities were repaid on
April 13, 2016. The redemption and extinguishment was recorded in the three months ended June 30, 2016.
Notes of the Partnership
The Partnership, a wholly-owned subsidiary acquired on November 5, 2011, has outstanding Cdn$210.0 million
($156.4 million as of December 31, 2016) 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. 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.
Notes of Atlantic Power Corporation
On July 26, 2015, we redeemed all of our outstanding $310.9 million aggregate principal amount of 9.0%
Senior Unsecured Notes due November 2018 (the “Notes”) with the cash proceeds received from the sale of the Wind
Projects. The Notes were redeemed at a price equal to 104.5 percent of the principal amount of the Notes, plus accrued
and unpaid interest to the redemption date. We paid $330.4 million to fund the full redemption of the Notes, which
includes $14.0 million in make-whole premiums and $5.5 million in accrued interest. The make whole premiums,
accrued interest and the $9.0 million of deferred financing costs related to the Notes were recorded in interest expense in
the year ended December 31, 2015.
Non-Recourse Debt
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
F-34
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
contracts of the projects. The loans have certain financial covenants that must be met in order to distribute available
cash. At December 31, 2016, all of our projects, with the exception of Piedmont, 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. We do not
expect the Piedmont project to meet its debt service coverage ratio covenants or to make distributions before the
project’s debt maturity in 2018 at the earliest.
12. Convertible debentures
The following table provides details related to outstanding convertible debentures:
6.25% Debentures due March 2017
5.60% Debentures due June 2017
5.75% Debentures due June 2019
6.00% Debentures due December 2019 (Cdn $81.0 million)
Less: Unamortized deferred financing costs
Total convertible debentures
December 31, December 31,
2016
2015
$
$
— $
—
42.6
60.3
(2.5)
100.4 $
48.6
54.8
117.0
65.0
(7.7)
277.7
On December 29, 2015, we commenced a Normal Course Issuer Bid (“NCIB”), which expired on December
28, 2016. The actual amount of convertible debentures that could be purchased under the NCIB was approximately
$28.5 million and was further limited to 10% of the public float of our convertible debentures. On April 13, 2016, we
deposited a portion of the proceeds from the issuance of the New Credit Facilities, for the redemption in whole on May
13, 2016 at a price equal to par plus accrued interest (i) the outstanding Cdn$67.2 million 6.25% Debentures due March
2017 and (ii) the outstanding Cdn$75.8 million 5.60% Debentures due June 2017. On June 17, 2016, we commenced a
substantial issuer bid (“SIB”) to purchase for cancellation up to $65.0 million aggregate principal amount of our issued
and outstanding 5.75% Series C Convertible Unsecured Subordinated Debentures maturing June 30, 2019. The offer
expired on July 22, 2016. As a result of the NCIB, the SIB and the redemptions made with proceeds from the New
Credit Facilities, we made payments of $188.5 million to redeem and cancel the 6.25% Debentures due March 2017 and
the 5.60% Debentures due June 2017, in full, and the 5.75% Debentures due June 2019 and 6.00% Debentures due
December 2019, in part.
As a result of these repurchases and cancellations, we recorded a gain of $3.7 million in the consolidated
statement of operations for the year ended December 31, 2016. Additionally, we wrote off $2.7 million of deferred
financing costs related to the convertible debentures which was recorded to interest expense for the year ended
December 31, 2016.
On November 2, 2016, our Board of Directors approved a new NCIB for each series of our convertible
unsecured subordinated debentures. Under the NCIB, our broker may purchase up to $4.3 million principal amount of
the 5.75% convertible debentures due June 2019 and Cdn$8.1 million of the 6.00% convertible debentures due
December 2019. The Board authorization permits us to repurchase convertible debentures through open market
repurchases. The NCIB commenced on December 29, 2016 and will expire on December 28, 2017 or such earlier date as
we complete our respective purchases pursuant to the NCIB.
The $42.6 million remaining 5.75% Debentures due June 2019 pay interest semi(cid:486)annually on the last day of
June and December of each year. They are convertible into our common shares at an initial conversion rate of 57.9710
common shares per $1,000 principal amount, representing a conversion price of $17.25 per common share. The $60.3
million (Cdn$81.0 million) remaining 6.00% Debentures due December 2019 pay interest semi(cid:486)annually on the last day
F-35
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
of June and December of each year and 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.
13. 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,
2016
2015
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
$ 85.6 $
13.3
4.0
4.6
7.6
21.3
893.6
102.9
85.6 $ 72.4 $
13.3
4.0
4.6
7.6
21.3
826.0
102.0
15.2
—
0.3
36.7
20.8
733.3
285.4
Fair Value
72.4
15.2
—
0.3
36.7
20.8
686.5
231.4
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-36
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, 2016 and December 31, 2015. 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, 2016
Level 3
Level 2
Total
$
$
$
$
85.6 $
13.3
—
98.9 $
— $
—
8.6
8.6 $
— $
85.6
—
13.3
8.6
—
— $ 107.5
— $
— $
28.9 $
28.9 $
— $
— $
28.9
28.9
Level 1
December 31, 2015
Level 3
Level 2
Total
$
$
$
$
72.4 $
15.2
—
87.6 $
— $
—
0.3
0.3 $
— $
—
—
— $
72.4
15.2
0.3
87.9
— $
— $
57.5 $
57.5 $
— $
— $
57.5
57.5
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, 2016, the credit valuation adjustments
resulted in a $3.8 million net increase in fair value, which consists of a $0.3 million pre-tax gain in other comprehensive
income and a $3.5 million gain in change in fair value of derivative instruments. As of December 31, 2015, the credit
valuation adjustments resulted in a $3.8 million net increase in fair value, which consists of a $0.4 million pre-tax gain in
other comprehensive income and a $3.4 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.
14. Accounting for derivative instruments and hedging activities
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
F-37
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 entered into various gas purchase and sale agreements for our North Bay, Kapuskasing and Nipigon
projects that expire ranging from March 31, 2017 through December 31, 2022. These agreements do not qualify for the
normal purchase normal sales (“NPNS”) exemption and are accounted for as derivative financial instruments because we
could not conclude that it is probable that these contracts will not settle net and will result in physical delivery.
These derivative financial instruments 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 sales and purchase agreements for approximately 1.3 million Mmbtu
to effectively mitigate seasonal fluctuation of future natural gas price at Morris through March 2017. These contracts are
accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at
December 31, 2016. Changes in the fair market value of these contracts are recorded in the consolidated statement of
operations.
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 4.1 million Mmbtu of future
natural gas purchases at Orlando, which is approximately 95% of our share of the expected natural gas purchases at the
project in 2017 and 12% in 2018. These contracts are accounted for as derivative financial instruments and are recorded
in the consolidated balance sheet at fair value at December 31, 2016. Changes in the fair market value of these contracts
are recorded in the consolidated statement of operations.
Interest rate swaps
APLP Holdings has entered into several interest rate swap agreements to mitigate its exposure to changes in
interest at the Adjusted Eurodollar Rate for $422.7 million notional amount of the remaining $639.9 million aggregate
principal amount of borrowings under the New Term Loans. These interest rate swap agreements at various dates
through March 31, 2020. Borrowings under the $700.0 million New Term Loans bear interest at a rate equal to the
Adjusted Eurodollar Rate plus an applicable margin of 5.00%. Based on the terms of the Credit Agreement, the Adjusted
Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 6.00% all-in rate on the Term Loan Facility. As a
result of entering into the swap agreements, the all-in rate for $422.7 million of the New Term Loans cannot be less than
6.00%, if the Adjusted Eurodollar Rate is equal to or greater than 1.00%.
The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest
rates related to its variable(cid:486)rate debt. The interest rate swap agreement effectively converts the floating rate debt to a
fixed interest rate 4.5% with an applicable margin of 3.75%, resulting in an all(cid:486)in rate of 8.22%. The swap continues at
F-38
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
the fixed rate of 4.5% until November 2030. The interest rate swap agreements are not designated as hedges, and
changes in their fair market value are recorded in the consolidated statements of operations.
The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.0% through
February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15,
2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal
balance over the remaining life of Cadillac’s debt. This swap agreement, which qualifies for and is designated as a cash
flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in
accumulated other comprehensive loss.
Foreign currency forward contracts
From time to time, we use foreign currency forward contracts to manage our exposure to changes in foreign
exchange rates, as many of our projects generate cash flow in U.S. dollars and Canadian dollars.
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, 2016 and December 31, 2015:
Natural gas swaps
Gas purchase agreements
Interest rate swaps
Fair value of derivative instruments
Units
December 31, December 31,
2016
2015
Natural Gas (Mmbtu)
Natural Gas (Gigajoules)
Interest (US$)
4.9
11.3
506.9
2.8
25.0
302.3
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, 2016
Derivative
Assets
Derivative
Liabilities
$
— $
—
—
0.8
2.0
2.8
0.4
4.5
3.9
0.1
—
—
8.9
8.9 $
1.9
6.5
0.8
—
4.5
12.7
26.4
29.2
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
Total derivative instruments not designated as cash flow hedges
Total derivative instruments
$
F-39
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
Total derivative instruments not designated as cash flow hedges
Total derivative instruments
$
Accumulated other comprehensive income
December 31, 2015
Derivative
Assets
Derivative
Liabilities
$
— $
—
—
1.0
2.7
3.7
—
0.3
—
—
—
—
0.3
0.3 $
2.0
7.8
5.0
—
28.7
10.3
53.8
57.5
The following table summarizes the changes in the accumulated other comprehensive income (loss) (“OCI”)
balance attributable to derivative financial instruments designated as a hedge, net of tax:
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
Settlements expected to be recognized from OCI in expense in the
next 12 months, net of $0.4 million of tax
Year Ended December 31, 2015
Accumulated OCI balance at January 1, 2015
Change in fair value of cash flow hedges
Realized from OCI during the period
Accumulated OCI balance at December 31, 2015
For the year ended December 31, 2014
Accumulated OCI balance at January 1, 2014
Change in fair value of cash flow hedges
Realized from OCI during the period
Accumulated OCI balance at December 31, 2014
F-40
Interest Rate
Swaps
Interest Rate
Swaps
0.2
(0.2)
0.7
0.7
0.8
0.1
(0.6)
0.7
0.2
$
$
$
$
$
Interest Rate
Swaps
0.2
(1.0)
0.9
0.1
$
$
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 for derivative instruments not designated as cash flow hedges:
Gas purchase agreements
Natural gas swaps
Interest rate swaps
Foreign currency forwards
Classification of loss
recognized in income
Fuel
Fuel
Interest, net
Foreign exchange loss
Year Ended December 31,
2014
2015
2016
$ 48.5 $ 47.3 $ 52.4
4.3
6.1
0.5
6.0
3.8
—
4.9
3.9
—
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 gain (loss)
recognized in income
Year ended December 31,
2014
2016
2015
Natural gas swaps
Gas purchase agreements
Interest rate swaps
Foreign currency forwards
15. Income tax benefit
Change in fair value of derivatives $ 9.0 $ 1.0 $ (3.3)
16.1
11.6
Change in fair value of derivatives
(1.5)
(1.7)
Change in fair value of derivatives
$ 37.9 $ 15.4 $ 6.8
— $ (1.1)
$
Foreign exchange loss
22.8
6.1
— $
The following table summarizes the current and deferred portions of the net income tax benefit:
Year Ended December 31
2015
2016
2014
2.9 $
5.3 $
3.8
$
(17.5)
(35.2)
(35.7)
$ (14.6) $ (30.4) $ (31.4)
Current income tax expense
Deferred income tax benefit
Total income tax benefit, net
F-41
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 26%
for the years ended December 31, 2016, 2015 and 2014, respectively, to the provision for income taxes in the
consolidated statements of operations:
Loss from continuing operations before income taxes
Computed income taxes at 26% 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
Production tax credits
Changes in estimates of tax basis of equity method investments
Capital gain on intercompany notes
Goodwill impairment
Capital loss recognized on tax restructuring
Intra-period allocations from the Wind projects
Other
Income tax benefit
Effective income tax rate
2016
Year ended December 31,
2015
$ (128.5) $ (114.5) $ (184.6)
(47.5)
(29.8)
(33.4)
2014
(2.9)
(36.3)
10.8
(25.5)
(0.4)
6.9
(1.5)
—
1.3
(0.2)
22.3
(18.0)
—
0.5
10.9
(14.6) $
(11)%
$
(4.9)
(34.7)
6.6
(28.1)
1.1
(7.0)
2.1
(3.6)
(6.3)
2.1
14.8
—
(5.0)
(0.5)
(2.3)
(30.4) $
(27)%
(19.2)
(66.7)
40.5
(26.2)
0.8
(7.4)
(5.8)
(0.3)
(4.1)
—
33.9
(10.2)
(15.8)
3.7
(5.2)
(31.4)
(17)%
The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and
deferred tax liabilities at December 31, 2016 and 2015 are presented below:
Deferred tax assets:
Loss carryforwards
Capital loss carryforwards
Finance and share issuance costs
Tax credits
LTIP
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-42
2016
2015
$ 226.2 $ 224.6
13.8
1.7
4.7
3.9
15.1
5.2
6.0
275.0
(175.2)
99.8
33.9
3.4
4.7
4.0
4.7
0.5
6.5
283.9
(186.0)
97.9
(72.0)
(94.2)
(166.2)
(79.0)
(106.5)
(185.5)
$ (68.3) $ (85.7)
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, 2016 and 2015:
Long-term deferred tax liabilities
Net deferred tax liability
2016
2015
$ (68.3) $ (85.7)
$ (68.3) $ (85.7)
As of December 31, 2016, we have recorded a valuation allowance of $186.0 million. This amount is comprised
primarily of provisions against available Canadian and U.S. net operating loss carryforwards. Some of these loss
carryforwards may be subject to limitation on their use. 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 limitation 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, 2016, we have not recorded any tax benefits related to uncertain tax positions.
As of December 31, 2016, 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
$
$
43.2
93.0
70.8
25.8
13.4
19.0
137.7
167.0
17.0
32.1
619.0
F-43
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
16. 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, 2016, 2015 and 2014:
Outstanding at December 31, 2013
Granted
Additional shares from dividends
Forfeitures
Vested and redeemed
Outstanding at December 31, 2014
Granted
Additional shares from dividends
Forfeitures
Vested and redeemed
Outstanding at December 31, 2015
Granted
Vested and redeemed
Forfeitures
Outstanding at December 31, 2016
Units
766,988 $
Grant Date
Weighted-Average
Fair Value per Unit
7.86
2.64
3.79
6.68
4.78
3.28
2.75
2.87
3.75
3.21
2.88
1.81
2.83
2.71
2.08
1,776,083
178,114
(294,037)
(983,894)
1,443,254
1,007,726
59,996
(136,894)
(1,075,681)
1,298,401
1,594,954
(784,806)
(7,431)
2,101,118 $
The total grant date fair value of all outstanding notional units under the LTIP was $4.4 million, $3.7 million
and $4.6 million for the years ended December 31, 2016, 2015 and 2014. The weighted average remaining vesting term
for outstanding notional units was 1.8 years at December 31, 2016. Approximately $1.5 million of total unrecognized
compensation expense is expected to be recognized over this time period. Compensation expense related to LTIP was
$2.8 million, $3.1 million and $3.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. Cash
payments made for vested notional units were $0.5 million, $0.9 million and $0.7 million for the years ended
December 31, 2016, 2015 and 2014, respectively.
Transition Equity Participation Agreement
We also have 539,904 transition notional shares outstanding at December 31, 2016 under the Transition Equity
Participation Agreement with James J. Moore, Jr. Fifty percent of the transition notional shares granted with respect to
fiscal year 2015 will vest upon 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%.
17. Employee benefit plans
Defined benefit pension plan
We sponsor and operate a defined benefit pension plan that is available to certain legacy employees of the
Partnership. The Atlantic Power Services Canada LP Pension Plan (the “Plan”) is maintained solely for certain eligible
F-44
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
legacy Partnership participants. The Plan is a defined benefit pension plan that allows for employee contributions. We
expect to contribute $0.2 million to the pension plan in 2017.
The net annual periodic pension cost related to the pension plan for the years ended December 31, 2016, 2015
and 2014 includes the following components:
Service cost benefits earned
Interest cost on benefit obligation
Expected return on plan assets
Net period benefit cost
2016
$
2015
2014
0.7 $
0.7
(0.9)
0.5 $
0.9 $
0.7
(0.9)
0.7 $
0.8
0.7
(0.8)
0.7
$
A comparison of the pension benefit obligation and related plan assets for the pension plan at December 31 is as
follows:
2016
2015
Benefit obligation at January 1
Service cost
Interest cost
Actuarial (gain) loss
Employee contributions
Benefits paid
Foreign currency translation adjustment
Benefit obligation at December 31
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Employee contributions
Benefits paid
Foreign currency translation 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:
(0.7)
(0.7)
(0.5)
(0.1)
0.1
(0.4)
(17.4)
$ (15.1) $ (16.2)
(0.9)
(0.7)
2.2
(0.1)
0.7
(0.1)
(15.1)
13.6
1.0
0.5
0.1
(0.7)
(0.1)
14.4
(0.7)
14.4 $
0.7
0.5
0.1
(0.1)
0.5
16.1
(1.3) $
$
$
Non-current liabilities
2016
2015
$
1.3 $
0.6
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
2016
2015
$
0.5 $
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.
F-45
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table presents the balances of significant components of the pension plan:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
$
2016
17.4 $
15.1
16.1
2015
15.1
12.6
14.4
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 $16.1 million and $14.4 million for the years ended December 31, 2016 and 2015,
respectively.
We determine the level in the fair value hierarchy within which the fair value measurement in its entirety falls,
based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the
common/collective trust is valued at a fair value which is equal to the sum of the market value of the fund’s investments,
and is categorized as Level 2. There are no investments categorized as Level 1 or 3.
The following table presents the significant assumptions used to calculate our benefit obligations:
Weighted-Average Assumptions
Discount rate
Rate of compensation increase
2016
2015
4.0 %
2.0 %
4.3 %
3.0 %
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
2016 2015
2014
4.3 %
5.8 %
3.0 %
4.0 %
6.0 %
4.0 %
5.0 %
6.0 %
4.0 %
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 provided by 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, 2016, 2015 and 2014, 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-46
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
International fixed income
2016
2015
30 %
14 %
14 %
39 %
3 %
100 %
29 %
14 %
14 %
40 %
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$:
2017
2018
2019
2020
2021
2022-2025
2016
Cdn$
0.3
0.4
0.5
0.6
0.7
4.9
In January 2017, we notified several employees whom are participants in the Plan of their termination, which is
expected to be effective in March 2017. Because of the terminations, we expect to record a pre-tax curtailment gain of
approximately $0.4 million in the three months ended March 31, 2017. We recorded $1.1 million of severance expense
in the fourth quarter of 2016 for these employees and expect to record an additional $0.5 million of severance in 2017.
Defined Contribution Plans
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,
$1.3 million, and $2.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.
18. Common shares
Stock Repurchase Program
In December 2015, our Board of Directors approved an NCIB for each series of our convertible unsecured
subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred
Equity Ltd (“APPEL”), our wholly-owned subsidiary. The Board authorization permitted the Company to repurchase
stock through open market repurchases. The NCIB expired on December 28, 2016. For the year ended December 31,
2016, we repurchased a cumulative 8.0 million common shares at a total cost of $19.5 million. Repurchases and
retirement of common shares are recorded to common shares on the consolidated balance sheets.
On December 29, 2016, we commenced a new NCIB that will expire on December 28, 2017 or such earlier date
as the Company and/or APPEL complete their respective purchases pursuant to the NCIBs. Under the new NCIB, we
may purchase up to approximately 11.3 million common shares, or 10% of our public float.
F-47
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Common Share Dividends
We paid dividends of Cdn$0.03 per outstanding share to our common stockholders during the first, second,
third and fourth quarters of 2015.
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.
19. 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 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.
The subsidiary company paid aggregate dividends of $8.5 million on the Series 1 Shares, Series 2 Shares and
Series 3 in 2016 as compared to $8.8 million in 2015.
20. Basic and diluted loss per share
Basic loss per share is calculated by dividing net loss by the weighted average common shares outstanding
during their respective period. Diluted earnings per share is computed including dilutive potential shares as if they were
outstanding shares during the year. Dilutive potential shares include the weighted average number of shares, as of the
date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP
F-48
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
were vested and redeemed for shares under the terms of the LTIP.
Because we reported a loss for the years ended December 31, 2016, 2015 and 2014, diluted loss per share is
equal to basic loss per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.
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, 2016, 2015 and 2014:
2016
2015
2014
Numerator:
Loss from continuing operations attributable to Atlantic Power
Corporation
Income (loss) from discontinued operations, net of tax
Net loss attributable to Atlantic Power Corporation
Denominator:
Weighted average basic shares outstanding
Dilutive potential shares:
Convertible debentures
LTIP notional units
Potentially dilutive shares
Diluted loss per share from continuing operations attributable
to Atlantic Power Corporation
Diluted earnings (loss) per share from discontinued operations
Diluted loss per share attributable to Atlantic Power
$ (122.4) $ (92.9) $ (164.8)
(12.6)
$ (122.4) $ (62.4) $ (177.4)
30.5
—
119.5
121.9
120.7
13.1
0.1
132.7
22.7
0.2
144.8
27.7
0.3
148.7
$ (1.02) $ (0.76) $ (1.37)
(0.10)
0.25
—
Corporation
$ (1.02) $ (0.51) $ (1.47)
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 EPS 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. Potentially dilutive shares from convertible debentures and notional units have been excluded from fully
diluted shares for the years ended December 31, 2016, 2015 and 2014, respectively, because their impact would be anti-
dilutive.
21. Discontinued operations
On June 26, 2015, APT, our wholly-owned, direct subsidiary, sold our Wind Projects under a definitive
agreement (the “Purchase Agreement”) with TerraForm AP Acquisition Holdings, LLC (“TerraForm”), an affiliate of
SunEdison, Inc. (an affiliate of TerraForm Power, Inc.). The sale was completed for aggregate cash proceeds of
approximately $335 million after transaction fees, exclusive of transaction-related taxes. We recorded an approximate
$46.8 million gain on sale, which is included as a component of income from discontinued operations in the consolidated
statements of operations for the year ended December 31, 2015.
Terraform acquired from APT, 100% of APT’s direct membership interests in a holding company formed to
facilitate the sale, thereby acquiring our indirect interests in our portfolio of Wind Projects consisting of five operating
wind projects in Idaho and Oklahoma and representing 521 MW net ownership: Goshen (12.5% economic interest),
Idaho Wind (27.6% economic interest), Meadow Creek (100% economic interest); Rockland Wind Farm (50%
economic interest, but consolidated on a 100% basis); and Canadian Hills (99% economic interest). As a result of the
sale, we deconsolidated approximately $249 million of project debt (or approximately $274 million as adjusted for our
F-49
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
proportional ownership of Rockland, Goshen North and Idaho Wind) and approximately $224 million of non-controlling
interest related to tax equity interests at Canadian Hills and the minority ownership interests at Rockland and Canadian
Hills.
The Wind Projects were designated as assets held for sale and discontinued operations on March 31, 2015, the
date we established a firm commitment to a plan to sell the wind assets. Our determination to designate the Wind
Projects as discontinued operations was based on the impact the sale would have on our operations and financial results
and because the Wind Projects made up the entirety of our Wind reportable segment. We stopped depreciating the
property, plant and equipment of the Wind Projects on the designation date.
On March 6, 2014, we sold our outstanding membership interests in Greeley for approximately $1.0 million and
recorded a $2.1 million non-cash gain on the sale related to the write off of asset retirement obligations. Greeley is
accounted for as a component of discontinued operations in the consolidated statements of operations for the years ended
December 31, 2015, 2014, and 2013, respectively.
The following tables summarize the revenue, loss from operations, and income tax expense of the Wind
Projects and Greeley for the years ended December 31, 2015 and 2014:
2015
2014
Revenue
Project expenses:
Fuel
Operations and maintenance
Depreciation and amortization
Project other income (expense):
Change in fair value of derivatives
Equity in earnings of unconsolidated affiliates
Interest expense, net
Gain on sale of asset
Income (loss) from operations of discontinued businesses
Income tax expense
Income (loss) from operations of discontinued businesses, net of tax
Net loss attributable to noncontrolling interests of discontinued businesses
Income (loss) from operations of discontinued businesses, net of noncontrolling
$
34.8
$
—
10.8
10.3
21.1
(0.7)
(0.5)
(6.7)
46.8
38.9
52.6
33.1
19.5
(11.0)
79.3
—
21.1
40.3
61.4
(15.5)
0.3
(14.2)
2.0
(27.4)
(9.5)
19.5
(29.0)
(16.4)
interests
$
30.5
$
(12.6)
The following table summarizes the operating and investing cash flows of the Wind Projects for the years ended
December 31, 2015 and 2014:
December 31,
Cash provided by operating activities
Cash (used in) provided by investing activities
$
2014
2015
21.9 $ 48.3
4.8
(12.8)
Basic and diluted loss per share related to income (loss) from discontinued operations for the Wind Projects and
Greeley was $0.25 and ($0.10) for the years ended December 31, 2015 and 2014, respectively.
F-50
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
22. Segment and geographic information
We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. We revised our
reportable business segments in the second quarter of 2015 as a result of significant project asset sales and in order to
align our reportable business segments with changes in management’s structure, resource allocation and performance
assessment in making decisions regarding our operations. Our financial results for the year ended December 31, 2014
have been presented to reflect these changes in operating segments. 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). Wind projects, which were
components of the former Wind segment and Greeley, which was a component of the West U.S. segment, are excluded
in the income (loss) from continuing operations line item in the table below. We have adjusted prior periods to reflect
this reclassification.
A reconciliation of Project Adjusted EBITDA to net income (loss) from continuing operations to is included in
the tables below:
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
Income (loss) from continuing operations before income
taxes
Income tax benefit
Net income (loss) from continuing operations
East U.S. West U.S. Canada
Un-Allocated
Corporate
Consolidated
$ 134.5 $ 101.3 $ 162.5 $
313.6
—
—
754.2
32.4
6.2
291.8
3.6
0.9
$ 92.4 $
(9.2)
44.1
10.9
15.4
—
31.2
—
—
—
—
51.2 $ 58.8 $
—
39.4
—
—
—
11.8
—
—
—
—
(25.5)
49.5
—
70.5
—
(35.7)
—
—
—
—
0.9 $
97.2
—
0.1
(0.2) $
(3.2)
0.5
—
—
(0.3)
2.8
22.6
106.0
13.9
(3.9)
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)
31.2
—
11.8
—
(35.7)
—
$ 31.2 $
11.8 $ (35.7) $
(135.8)
(14.6)
(121.2) $
(128.5)
(14.6)
(113.9)
F-51
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
East U.S. West U.S. Canada
Un-Allocated
Corporate
Consolidated
Year Ended December 31, 2015
Project revenues
Segment assets
Goodwill
Capital expenditures
Project Adjusted EBITDA
$ 150.0 $ 104.6 $ 164.7 $
228.6
—
0.5
819.9
47.8
7.0
423.8
86.7
3.4
$ 104.8 $
46.9 $ 59.7 $
Change in fair value of derivative instruments
Depreciation and amortization
Interest, net
Impairment
Other project expense (income)
Project income (loss)
Administration
Interest, net
Foreign exchange gain
Other income, net
Income (loss) from continuing operations before income
taxes
Income tax benefit
Net income (loss) from continuing operations
—
42.5
9.8
13.7
0.1
38.7
—
—
—
—
38.7
—
$ 38.7 $
—
39.3
—
—
7.6
—
—
—
—
(16.0)
47.2
—
114.1
0.1
(85.7)
—
—
—
—
0.9 $
198.9
—
0.4
(2.5) $
0.6
1.1
—
—
(2.2)
(2.0)
29.4
107.1
(60.3)
(3.1)
420.2
1,671.2
134.5
11.3
208.9
(15.4)
130.1
9.8
127.8
(2.0)
(41.4)
29.4
107.1
(60.3)
(3.1)
(85.7)
—
7.6
—
7.6 $ (85.7) $
(75.1) $
(30.4)
(44.7) $
(114.5)
(30.4)
(84.1)
Year Ended December 31, 2014
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 gain
Other income, net
Income (loss) from continuing operations before income
taxes
Income tax benefit
Net income (loss) from continuing operations
East U.S.
West U.S. Canada
Un-Allocated
Corporate Consolidated
$ 167.1 $ 123.6 $ 198.3 $
396.7
—
0.4
1,103.2
61.5
3.1
676.8
135.7
7.8
$ 106.4 $ 54.2 $ 76.3 $
—
40.3
(0.1)
50.3
(8.7)
(11.7)
59.9
—
38.5
0.1
4.3
55.0
20.6
17.9
(0.1)
8.7 $ (27.6) $ (10.5) $
—
—
—
—
—
—
—
—
—
—
—
—
0.9 $
676.5
—
1.1
(7.5) $
1.2
0.7
—
(0.1)
0.2
(9.5)
37.9
146.7
(38.3)
(0.6)
489.9
2,853.2
197.2
12.4
229.4
(6.2)
155.9
20.5
106.6
(8.5)
(38.9)
37.9
146.7
(38.3)
(0.6)
(27.6)
8.7
—
—
8.7 $ (27.6) $ (10.5) $
(10.5)
—
(155.2)
(31.4)
(123.8) $
(184.6)
(31.4)
(153.2)
$
The table below provides information, by country, about our consolidated operations for each of the years
ended December 31, 2016, 2015 and 2014 and Property, Plant & Equipment as of December 31, 2016 and 2015,
F-52
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which
they are located.
2016
Revenue
2015
2014
Property, Plant and
Equipment, net of
accumulated
depreciation
2016
2015
United States
Canada
Total
$ 236.7 $ 255.5 $ 291.6 $ 499.2 $ 529.6
248.1
$ 399.2 $ 420.2 $ 489.9 $ 733.2 $ 777.7
234.0
162.5
164.7
198.3
Ontario Electric Financial Corporation (“OEFC”), BC Hydro, and San Diego Gas & Electric provided 29.2%,
11.5%, and 10.9%, respectively, of total consolidated revenues for the year ended December 31, 2016. OEFC, San Diego
Gas & Electric, and BC Hydro provided 29.2%, 11.0%, and 10.0%, respectively, of total consolidated revenues for the
year ended December 31, 2015. OEFC, San Diego Gas & Electric, and BC Hydro provided 25.8%, 15.1%, and 9.1%,
respectively, of total consolidated revenues for the year ended December 31, 2014. IESO and OEFC purchase electricity
from the Calstock, Kapuskasing, Nipigon, North Bay and Tunis projects in the Canada segment, respectively. San Diego
Gas & Electric purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the
West U.S. segment, Georgia Power Company purchases electricity from the Piedmont 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 2022.
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 excludes leased properties
where the net rent expense results in rental income for the company. Lease expense under operating leases was $0.6
million, $1.5 million and $1.0 million for the years ended December 31, 2016, 2015, and 2014, respectively. Future
minimum lease commitments under operating leases for the years ending after December 31, 2016, are as follows:
2017
2018
2019
2020
2021
Thereafter
$
$
0.7
0.6
0.3
0.1
—
—
1.7
F-53
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, 2016, our commitments under this agreement is estimated as follows:
2017
2018
2019
2020
2021
Thereafter
$
$
0.4
0.4
0.4
0.4
0.4
0.2
2.2
Fuel Supply and Transportation Commitments
We have entered into long-term contractual arrangements to procure fuel and transportation services for our
projects. The commitments listed below include only contracts for fuel contracts that are not reimbursed or passed
though under the terms of the relevant PPAs. As of December 31, 2016, our commitments under such outstanding
agreements are estimated as follows:
2017
2018
2019
2020
2021
Thereafter
Guarantees
$
$
2.2
3.8
12.7
10.8
10.7
21.4
61.6
We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a
routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint
venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and
other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental
liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these
agreements.
Contingencies
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,
2016.
F-54
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
24. Unaudited selected quarterly financial data
Unaudited selected quarterly financial data are as follows:
Project revenue
Project income (loss)
Loss from continuing operations
Net loss attributable to Atlantic Power Corporation
Loss per share from continuing operations attributable
to Atlantic Power Corporation
Loss per share attributable to Atlantic Power
Corporation
Weighted average number of common shares
outstanding-basic
Diluted loss per share from continuing operations
attributable to Atlantic Power Corporation
Diluted loss per share attributable to Atlantic Power
Corporation
Weighted average number of common shares
outstanding-diluted(1)
Quarter Ended
2016
December 31, September 30,
$
93.4 $
13.3
(4.4)
(6.6)
June 30,
March 31,
Total
101.2 $ 98.2 $ 106.4 $ 399.2
10.1
(57.1)
(113.9)
(80.3)
(122.4)
(82.4)
25.2
(16.3)
(18.5)
28.7
(12.9)
(14.9)
$
(0.06) $
(0.69) $ (0.15) $ (0.12) $ (1.02)
$
(0.06) $
(0.69) $ (0.15) $ (0.12) $ (1.02)
115.5
119.3
121.6
121.9
119.5
$
(0.06) $
(0.69) $ (0.15) $ (0.12) $ (1.02)
$
(0.06) $
(0.69) $ (0.15) $ (0.12) $ (1.02)
115.5
119.3
121.6
121.9
119.5
F-55
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Quarter Ended
2015
Project revenue
Project (loss) income
(Loss) income from continuing operations
(Loss) income from discontinued operations
Net (loss) income attributable to Atlantic Power
Corporation
(Loss) income per share from continuing operations
attributable to Atlantic Power Corporation
(Loss) income per share from discontinued operations
(Loss) income per share attributable to Atlantic Power
Corporation
Weighted average number of common shares
outstanding-basic
Diluted (loss) income per share from continuing
operations attributable to Atlantic Power Corporation
Diluted (loss) income per share from discontinued
operations
Diluted (loss) income per share attributable to Atlantic
Power Corporation
Weighted average number of common shares
outstanding-diluted(1)
Dividends declared per common share
December 31, September 30, June 30,
$
98.4 $
March 31, Total
107.4 $ 103.1 $ 111.3 $ 420.2
(41.4)
(84.1)
19.5
17.2
(20.0)
33.6
21.5
24.6
(12.3)
24.2
(3.3)
(0.5)
(104.3)
(85.4)
(1.3)
(88.6)
(6.0)
14.7
17.5
(62.4)
$
(0.71) $
(0.01)
(0.05) $ (0.18) $
—
0.30
0.18 $ (0.76)
0.25
(0.04)
$
(0.72) $
(0.05) $ 0.12 $
0.14 $ (0.51)
122.1
122.1
121.9
121.5
121.9
$
(0.71) $
(0.05) $ (0.18) $
0.18 $ (0.76)
(0.01)
—
0.30
(0.04)
0.25
$
(0.72) $
(0.05) $ 0.12 $
0.14 $ (0.51)
122.1
0.02
122.1
0.02
122.1
0.02
122.4
0.03
121.9
0.09
(1) The calculation excludes potentially dilutive shares from convertible debentures and LTIP notional units
because their impact would be anti-dilutive.
25. Subsequent Event
On February 27, 2017, we received notification from the OEFC that we will receive a payment of
approximately Cdn$8.4 million for our North Bay and Kapuskasing plants representing the application of the price
escalator calculation under their respective PPAs for power sold to the OEFC in 2016. The OEFC’s interpretation and
application of such price escalator calculation is a result of the Superior Court of Ontario’s decision in N-R Power and
Energy Corporation v. Ontario Electricity Financial Corporation.
On January 19, 2017, the Supreme Court of Canada denied the OEFC leave to appeal the Ontario Court of
Appeal Decision concerning the interpretation of the price escalator for power sold to the OEFC under certain power
purchase agreements with non-utility generators. We were not party to that litigation. We did, however, enter into a
standstill agreement with the OEFC in 2015, with respect to our North Bay, Kapuskasing and Tunis projects, arising out
of our disagreement with the OEFC over the interpretation of the price escalator calculation in our PPAs. Under the
standstill agreement we reserved our right to bring claims against the OEFC and suspended the running of any applicable
limitation period to bring such claims.
The OEFC’s payment is an adjustment for power sold by our North Bay and Kapuskasing plants only during
2016 and not any prior period. Prior to receipt of the payment, we notified the OEFC that we are reviewing their
F-56
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
calculation of the price escalator and reserving our right to contest the payment amount. We will record the payment for
this contingent gain as revenue when we settle our dispute with the OEFC and all contingencies have been resolved.
F-57
ATLANTIC POWER CORPORATION
SCHEDULE I—CONDENSED BALANCE SHEETS (PARENT COMPANY ONLY)
(in millions of U.S. dollars)
Assets
Current assets:
Cash and cash equivalents
Accounts receivable
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
Total current liabilities
Convertible debentures
Other long-term liabilities
Total liabilities
Shareholders' equity
Total liabilities and shareholders' equity
December 31,
2016
2015
$
$
$
$
$
$
49.2
—
2.3
51.5
116.1
167.6
1.5
1.5
100.4
1.1
103.0
11.5
0.1
3.1
14.7
480.8
495.5
3.1
3.1
277.7
0.8
281.6
64.6
167.6
$
213.9
495.5
$
See accompanying notes to condensed financial statements.
F-58
SCHEDULE I—CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)
ATLANTIC POWER CORPORATION
(in millions of U.S. dollars)
Year Ended December 31,
2015
2016
2014
Administrative and other expenses:
Administrative expense
Interest expense, net
Foreign exchange loss (gain)
Other income
Loss from parent company
$
5.9 $
7.3
10.6
(3.6)
(20.2)
6.3 $
25.6
(33.0)
(2.6)
3.7
12.3
29.2
(21.0)
—
(20.5)
Equity losses of subsidiaries, net of income tax benefit
(93.7)
(87.8)
(132.7)
Net loss from continuing operations
Net income (loss) from discontinued operations, net of tax
Net loss
(113.9)
—
$ (113.9) $
(153.2)
(84.1)
19.5
(29.0)
(64.6) $ (182.2)
See accompanying notes to condensed financial statements.
F-59
SCHEDULE I—CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)
ATLANTIC POWER CORPORATION
(in millions of U.S. dollars)
Years Ended December 31,
2015
2014
2016
Cash provided by operating activities:
Net loss
Adjustments to reconcile net loss to net cash provided by operating activities:
Non-cash losses from subsidiaries, net of taxes
Dividends received from subsidiaries
Unrealized foreign exchange loss (gain)
Gain on purchase and cancellation of convertible debentures
Change in other operating balances
Accounts receivable
Prepayments and other assets
Accounts payable and accrued liabilities
Cash provided by operating activities
Cash provided by investing activities:
Advances to / from and investments in subsidiaries
Cash provided by investing activities
Cash used in financing activities:
Common share repurchases
Dividends paid to common shareholders
Repayment of convertible debentures
Payments received from intercompany note
Repayment of intercompany note
Repayment of long-term debt
Cash used in financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental cash flow information
Interest paid
$
(113.9)
$
(64.6)
$
(182.2)
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
$
87.8
32.5
(33.0)
(3.1)
(14.9)
13.3
(23.4)
(5.4)
330.4
330.4
—
(11.1)
(18.9)
29.6
—
(319.9)
(320.3)
4.7
6.8
11.5
$
132.7
31.2
(21.0)
(0.6)
(7.9)
12.7
23.7
(11.4)
122.0
122.0
—
(34.9)
(43.0)
106.6
—
(140.1)
(111.4)
(0.8)
7.6
6.8
$
$
11.5
$
51.1
$
68.0
See accompanying notes to condensed financial statements
F-60
SCHEDULE I—NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)
ATLANTIC POWER CORPORATION
(in millions of U.S. dollars)
1. Nature of business
Atlantic Power Corporation (the “Parent Company”) is a holding company that conducts substantially all of its
business through its subsidiaries. As specified in certain of its subsidiaries' credit agreements, there are restrictions on the
Parent Company's ability to obtain funds from certain of its subsidiaries through dividends (refer to Note 11, “Long-term
debt”, to the consolidated financial statements). As of December 31, 2016, total Atlantic Power Corporation
shareholders’ equity was $64.6 million and approximately $79.7 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 25% of our consolidated net assets, thus requiring this Schedule I, “Condensed Financial Information of the
Registrant.” Accordingly, the balance sheets as of December 31, 2016 and 2015, and the statements of operations and
cash flows for the years ended December 31, 2016, 2015 and 2014, 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. Restricted net assets were approximately $85.2 million at December 31, 2015. We had no
undistributed earnings from our unconsolidated investments for the years ended December 31, 2016, 2015 and 2014,
respectively.
As disclosed in Note 11, 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. APLP Holdings has made principal payments to meet the targeted debt balance
requirement as of December 31, 2016 and is not prohibited from making dividends to the Parent Company. The
consolidated equity of APLP Holdings was approximately $127 million at December 31, 2016 and includes the
subsidiaries with restricted net assets of $79.7 million at December 31, 2016 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 $33.6 million, $32.5 million and $31.2 million in 2016, 2015 and
2014, respectively, from its consolidated and unconsolidated subsidiaries.
F-61
ATLANTIC POWER CORPORATION
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
(in millions of U.S. dollars)
Balance at Charged to
Beginning of Costs and
Expenses
Period
Charged to
Other Accounts Deductions End of Period
Balance at
Income tax valuation allowance, deducted from
deferred tax assets:
Year ended December 31, 2016
Year ended December 31, 2015
Year ended December 31, 2014
$
175.2 $
168.6
128.1
10.8 $
6.6
40.5
— $
—
—
— $
—
—
186.0
175.2
168.6
F-62
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, 855.280.4737
or by email at info@atlanticpower.com.
CORPORATE INFORMATION
Corporate Headquarters
3 Allied Drive, Suite 220
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 20, 2017.
14SEP201110485170