14SEP201110485170
2015
Annual Report
Report to Shareholders
Dear Shareholder,
I’m pleased to report that 2015 was an eventful and productive year. I’ll begin with the
conventional review of our financial and operational results and then proceed to a lengthier discussion
of our business. I view this letter as an opportunity to talk to my fellow shareholders, who are likely
not following the business day-to-day, and therefore would like a more detailed update.
PAST: 2015
Financial and Operating Results
In 2015, we achieved financial results within our guidance ranges for Project Adjusted EBITDA(i),
Adjusted Cash Flow from Operating Activities(ii) and Adjusted Free Cash Flow(iii). I’ll discuss each of
these in turn, but first would note that both our 2015 and 2014 results exclude our Wind business,
which we sold in June 2015, and debt redemption and refinancing costs that we incurred in both years.
Project Adjusted EBITDA of $208.9 million decreased from the 2014 level of $229.4 million. This
decline was expected and results were in the upper half of our 2015 guidance range of $200 to
$215 million. The lower level of Project Adjusted EBITDA was attributable to expirations of power
purchase agreements (contracts to sell the power and steam output from our plants to utilities and
industrial customers, or PPAs) at our Selkirk and Tunis plants in 2014, a scheduled gas turbine
maintenance outage at our Manchief plant, lower water flows at our Curtis Palmer and Mamquam
hydro facilities, and the adverse impact of a stronger U.S. dollar relative to the Canadian dollar. These
factors were partially offset by increases at other plants, higher waste heat generation that benefited
some of our Ontario gas-fired plants and lower project-level administrative and development expenses.
Adjusted Cash Flows from Operating Activities increased to $105.3 million from $92.4 million in
2014 and was at the upper end of our 2015 guidance range of $95 to $105 million. Lower cash interest
payments resulting from significant debt reduction and lower corporate general and administrative
expenses more than offset the decline in Project Adjusted EBITDA.
Adjusted Free Cash Flow increased to $1.8 million from $(0.3) million in 2014. Although our
Adjusted Cash Flows from Operating Activities increased in 2015, the benefit to Adjusted Free Cash
Flow was mostly offset by higher levels of debt repayment. The $1.8 million result was at the lower end
of our 2015 guidance range of $0 to $10 million, although that was primarily due to a delay in a
$6 million payment that we received in February 2016.
Our plants continued to perform well in 2015. We achieved average fleet availability of 95%, which
was improved from the 93% level of 2014. The majority of our plants achieved substantially all of their
respective capacity payments in 2015. We also maintained a strong focus on the safety of our
operations personnel and our plants, and our 2015 recordable injury rates were well below the industry
average.
Management Approach
Before turning to what I view as the key accomplishments of 2015, I want to confirm what I said
last year about our management philosophy. I hope that you will agree that we have followed that
approach so far:
(cid:129) Capital allocation is a CEO’s most important job.
(cid:129) What counts in the long run is the increase in per share value, not overall growth or size.
(cid:129) Cash flow, not reported earnings, is what determines long-term value.
(cid:129) Decentralized organizations release entrepreneurial energy and keep both costs and ‘‘rancor’’
down.
(cid:129) Independent thinking is essential to long-term success, and interactions with outside advisers
(Wall Street, the press, etc.) can be distracting and time-consuming.
(cid:129) Sometimes the best investment opportunity is your own stock.
(cid:129) With acquisitions, patience is a virtue . . . as is occasional boldness.
Again, thanks to William N. Thorndike for his marvelous book The Outsiders(iv) and the set of
principles that he identifies above.
Significant Accomplishments
In last year’s letter I indicated that we would focus on three key levers to increase our intrinsic
value per share: increasing our free cash flow by reducing our overhead costs, optimizing our capital
structure and lowering our interest expense, and making smart decisions on capital allocation. We made
significant progress in 2015 on all three fronts by
(cid:129) capitalizing on high market values for renewable assets by executing a very timely sale of our
wind plants at a good valuation and using the proceeds to redeem our most expensive debt,
which resulted in a slight increase to our resulting discretionary cash flow;
(cid:129) reducing our financial risk by lowering our debt, improving our cost structure, and resolving
pending litigation;
(cid:129) enhancing our cash flow by investing in internal growth projects that we expect to yield high
cash returns;
(cid:129) executing our first PPA extension in more than two years, with expected accretion to Project
Adjusted EBITDA and net present value; and
(cid:129) revising our capital allocation priorities in favor of equity and debt repurchases and additional
internal growth investments, all of which we expect to increase our intrinsic value per share.
Sale of Wind business.
In June, we closed the sale of our Wind business (521 megawatts of net
ownership in five operating wind plants) for approximately $350 million (or $335 million net of
transaction fees). This represented a valuation of approximately 13 times our expected 2015 cash
distributions from the business. The sale also resulted in the deconsolidation of $249 million of wind
project debt from our balance sheet. Although the assets that we sold accounted for approximately one
quarter of our Project Adjusted EBITDA, because we used the proceeds to redeem our highest-cost
debt (the $311 million of remaining 9.0% Senior Unsecured Notes), our discretionary cash flow
remains in line with the level prior to the sale.
Debt reduction.
In 2015, we reduced debt by $743 million as a result of the sale of our Wind
business, debt amortization and discretionary debt repurchases. Since year-end 2013, we have reduced
debt by a total of $833 million and lowered our annual interest expense by more than $65 million or
approximately 50%. Our leverage ratio has been reduced considerably to 5.8 times at year-end 2015
from 8.9 times at year-end 2013. Further debt reduction remains an important priority for us, and we
expect to achieve this through continued amortization and discretionary repurchases.
Overhead cost reduction.
In last year’s letter, I discussed our corporate overhead being both a
problem and an opportunity. In 2015, we reduced our overhead costs another $13.5 million or 30%, to
$31.9 million. We expect to reduce them another $5 million in 2016, to approximately $27 million,
which would represent a cumulative reduction of approximately 50% from $53.8 million in 2013.
Investments in fleet. We continued our program of making attractive optimization investments in
our fleet and have now made $22 million of such investments since 2013. In 2015, we realized a cash
return on these investments of approximately 26% or $6 million, which we expect will increase to
$10 million in 2016. We continue to identify and move forward with similar additional investments,
including approximately $4 million planned for 2016.
PPA extensions.
In December, we announced our first significant PPA extension in more than
two years (cid:2) an 11-year extension of the energy services agreement with the primary customer for our
Morris plant, from November 2023 to December 2034. We also agreed to changes to the Morris energy
services agreement that are expected to increase our Project Adjusted EBITDA modestly. We continue
to work with our customers at other plants for which the PPAs are scheduled to expire in the next few
years, with a goal of achieving extensions on terms that make sense for both the customer and the
Company. In some cases we are considering making additional investments in our plants to facilitate
these extensions, and we have budgeted approximately $7 million in 2016 for investments at Tunis, for
which we already have a new contract, and at Williams Lake.
Shareholder litigation. Between December 2015 and April 2016, the pending shareholder actions
in the United States and the Provinces of Ontario and Quebec were all dismissed by the respective
courts without any payments by us.
Credit rating upgrades.
In recognition of the significant debt and cost reductions that we have
achieved, we received an upgrade of our corporate family rating from Moody’s to B1 from B2 in
October 2015, and in March 2016, Moody’s changed our outlook from ‘‘stable’’ to ‘‘positive.’’ In
February 2016, Standard & Poor’s upgraded our corporate credit rating to B+ from B and now has a
‘‘stable’’ outlook for our credit.
Revised capital allocation strategy.
In December, we implemented a normal course issuer bid
(NCIB) for up to 10% of each of our convertible debentures and common shares and up to 5% of
Atlantic Power Preferred Equity Ltd.’s preferred shares, subject to the limitations described in our
December 22, 2015 press release. In February 2016, we announced the elimination of our common
dividend as part of changes to our overall capital allocation strategy, which will prioritize repurchases
of our convertible debentures and our common shares as long as they are trading at compelling
price-to-value levels, and investments in our existing fleet at attractive returns, either optimization
projects or related to PPA extensions. We expect that the approximately $10 million of annual cash flow
previously allocated to payment of a common dividend will be redirected to these higher-return
purposes.
Intrinsic Value per Share
I spend a lot of time talking with investors and our employees about intrinsic value per share. The
key concept is that we want to focus on growing per share value, not the absolute size of the business.
If we issue shares worth $1 to buy assets worth 50 cents, we have increased our asset base but we have
reduced our intrinsic value per share. If we use 50 cents to buy shares worth $1, then we have reduced
our assets (by using cash) but we have increased the value per share of the remaining shares.
We use a few different methods to estimate our intrinsic value (which is not a precise number).
The inputs to these models require some judgments on management’s part. One approach that we take
is to estimate the net present value of the future cash flows that we expect to receive from our business
and then divide by shares outstanding. Although calculating the cash flow generated under existing
PPAs is fairly straightforward, determining the level of cash flows in the post-PPA periods is trickier.
We use forecasts of future energy prices (forward curves) in our analysis, but those forecasts have a
high degree of volatility. Today the forecasts are low by historical standards. In estimating future cash
flows, we try to take a conservative view in order to avoid fooling ourselves. Developing realistic
estimates of our intrinsic value is important as these are a significant consideration in capital allocation
and other decisions. We don’t disclose these estimates for competitive reasons and because we don’t
want people to rely too much on what are inherently fluid estimates within a range.
Share Buybacks
As I write this letter in April, the 52-week range of our share price on the NYSE was $3.34 to
$1.57. At $3.34, we believed that we were trading at a discount to intrinsic value, and at $1.57, we
believed the discount was huge. Unfortunately we couldn’t buy back shares as aggressively as we would
have liked due to limited cash availability beyond what we require for working capital purposes.
There has been a lot of commentary over the years on whether buybacks are a good use of capital
or if they are overdone. We believe that it depends on the price-to-value relationship. We won’t buy
shares to send a message to the market, and we don’t have stock option plans so there is no need to
buy shares to offset dilution.
When our stock was at $1.68 this past February, we announced a shift from paying a dividend to
our shareholders to emphasizing debt and share repurchases, because we saw that as the best
opportunity we had for deploying capital given the price-to-value levels of our common shares and our
debt securities. As a still highly leveraged company, we need to prioritize debt repurchases but when
the price-to-value proposition presents a compelling opportunity to increase intrinsic value per share,
we want to use capital for buying back shares as well.
PRESENT: 2016
Refinancing
In April 2016, we completed another significant step in the reshaping of our balance sheet and
debt maturity profile by closing a new senior secured term loan in the amount of $700 million and a
new revolving credit facility in the amount of $200 million. We used the proceeds of the new term loan
to redeem our existing term loan, which had an outstanding principal amount of $448 million. We also
called our March and June 2017 convertible debentures for redemption, which will occur in May of this
year and use another $112 million of the proceeds. Following this redemption, we will have no
corporate debt maturities prior to June 2019. The new term loan has a maturity of April 2023, which is
more than two years later than that of the term loan that we redeemed. The new revolver, which gives
us additional flexibility, has a maturity of April 2021, which is more than three years later than the
maturity date of the revolver that it replaced.
Net proceeds from the refinancing transaction, after fees and redemption of the existing term loan
and our 2017 convertible debentures, are approximately $106 million, which are available to us for
additional repurchases of debt and repurchase of preferred and common shares. Although the
transaction increased our debt, we expect debt to be reduced over time through amortization and
allocation of a portion of the remaining proceeds to discretionary debt repurchases.
People and Culture
In 2015 and the early part of 2016, we focused our efforts on restructuring the Company, including
selling assets, reducing costs, reshaping our balance sheet and revising our capital allocation strategy.
Now we need to pivot to the more mundane but crucial jobs of building the business, building a strong
culture and focusing on the details of execution. Capital allocation may be the most important job of
the CEO but it is not the only one. Paying attention to people is important and fulfilling. Getting the
people wrong will swamp rational capital allocation.
We had two big people initiatives in 2015:
(cid:129) We commenced building a culture of servant leadership and excellence. Servant leadership
means leading by example in terms of putting others’ needs ahead of your own, being patient
with others, listening to others, acting with integrity and humility at all times and always treating
others with respect.
(cid:129) We have had a significant headcount reduction at the corporate level over the past three years,
taking us from 109 employees at the beginning of 2013 to 48 currently.
We were able to eliminate some work, but now our remaining employees have bigger workloads.
Cutting overhead in half sounds like a great way to increase free cash flow but it comes at a cost.
Cutting people means sending them home to break the bad news to their families. It also means
anxiety and sleepless nights for those making tough decisions and imparting bad news to those losing
their jobs. But in some cases you have to cut half the jobs to save the remaining half. This is the worst
part of being in business.
Also, as you close four offices, cut more than half the staff, and engage in major restructuring
initiatives, execution risk increases. We have emerged from this period of enormous change even more
committed to developing a culture of excellence where we are open and honest, communicate bad news
in nanoseconds, stay away from legal and ethical boundaries, pay attention to details and learn from
our mistakes.
FUTURE
Now that we are well along in the restructuring effort and have succeeded in putting the Company
on a much more stable foundation, the obvious questions are: What next? How do we grow with so
much leverage?
What I might call ‘‘Plan A’’ is to continue doing what we have been doing (cid:2) focusing on intrinsic
value per share, reducing debt, keeping overhead costs low, optimizing our plants, working to extend
PPAs where economically feasible and trying to make rational business decisions every day. As we do
so, we expect our value per share to increase while our business risks are mitigated.
While focused on these initiatives, we are very aware that macro factors, particularly the energy
price environment, will greatly impact the valuation of our business. The independent power business is
capital-intensive and cyclical. Pricing is often tied to volatile commodities and short-term capacity
markets. Over our three-plus decade careers, members of the management team have delivered results
for shareholders by being disciplined capital allocators and taking a countercyclical approach to this
business. We expect to do the same at Atlantic Power. We want to use volatility to create value.
Most of our current EBITDA is underpinned by PPAs. As I mentioned previously, we were able to
extend the PPA at Morris well ahead of its scheduled expiration because of the plant’s favorable
location, in proximity to a customer with whom we have a strong relationship and who depends on the
reliable service we continue to provide. In other cases, though, it may not be possible or economically
feasible to extend or renew an expiring PPA because of the very low energy price environment in which
we find ourselves currently. This was the case at our Selkirk project, which operates on a merchant
basis and contributes only very modest levels of Project Adjusted EBITDA.
Our goal has been to structure the Company so that the debt and overhead costs allow us to
withstand a down market. We never want to be a forced seller of power or assets. We want to be
opportunistically investing when the cycle has turned down precipitously and we want to be cautious
when times are good. By surviving the bottom we can be there to extend PPAs on more favorable
terms and to hedge or contract out our assets when markets are in an up cycle. We can’t control or
even predict market prices, so we need to build the Company to ride out the troughs while knowing
that markets can stay low longer than we expect.
So Plan A would be to grind away at increasing intrinsic value per share mostly through internal
efforts, preparing to survive downturns such as the present one, capturing value where we see it, as
with our Wind sale and Morris PPA extension, and ensuring that we are in a position to capitalize on a
higher energy price environment when it materializes.
‘‘Plan B’’ adds value to Plan A by being opportunistic when asset valuations are favorable for
buyers. That is currently not the case but there is a lot of distress in power markets, which usually leads
to greater opportunity down the road. We talk regularly with potential partners about helping to
provide capital alongside us when opportunities emerge.
Another potential external growth avenue is to be an early mover in one or more sub-sectors of
the IPP industry. In the 1980s, members of this management team were early movers in developing
Qualifying Facility power plants under the Public Utility Regulatory Policies Act of 1978. In the late
1990s, we did the same with merchant combined-cycle gas turbine plants. In 2001, we launched a wind
energy IPP strategy. Each time we were able to sell assets, de-merge a larger business or sell an entire
business with good results for the shareholders.
Today we are evaluating the potential for investing in things such as energy storage around our
plants and perhaps beyond. Anything we do will of necessity be capital-light in this area. We have a
long track record of making disciplined but timely early mover investments within our circle of
competence.
In a year or two we may have fixed the business as well as we can. It may be operating at a high
level. Energy prices, particularly power and gas prices, may or may not have recovered. We may or may
not have good ideas for growing the business. We could reach a point where we decide that the best
way to realize value for shareholders is to sell the Company. Under those circumstances, our guide in
evaluating any offers would be price-to-value. In 2015, Directors and officers of the Company bought
slightly more than one million shares at an average price of $2.31. We want to be aligned with our
shareholders and to avoid the agency problem often associated with small capitalization companies
(where, for example, management salaries are more important than equity ownership). In my previous
company I became CEO in 2001 and we sold the business in 2005 and again in 2008 at good prices.
Last year we sold one quarter of Atlantic Power’s business at approximately 13 times expected cash
distributions before the collapse in the energy sector. When the best value for shareholders is to sell,
you will not need to pick up the phone and call me with that advice.
We are not, however, preparing the Company for sale. I simply lay that out as an option. We think
that greater value can be realized by building the business. We have 23 plants in the United States and
Canada in areas where it is difficult to build new plants. The Not in My Backyard (NIMBY) factor
provides a barrier to entry in these markets. (For a book that captures how we think about strategy and
barriers to entry, see the brilliant Competition Demystified(v) by Bruce Greenwald and Judd Kahn.) In
some areas public policy has led to very high levels of penetration of intermittent power generation
sources such as wind and solar. Those assets come with costs, not all of which are necessarily
considered in the economic analysis (cid:2) carbon break-even points that may be at least questionable,
aesthetic concerns, bird and bat kill concerns, toxic waste from used solar panels, impact on mining
communities, reduced efficiency of more reliable gas plants and higher production costs if tax subsidies
are normalized.
My point isn’t to debate public policy here. It is merely to lay out different scenarios. In some
scenarios, such as higher gas prices or the implementation of a carbon tax, nuclear power might have a
renaissance. In others, public policy support for natural gas plants might increase through changes to
capacity markets or other means. In yet other scenarios, very little new generating capacity would be
built beyond wind and solar, which would increase the value of energy storage. If public policy starts to
value clean and reliable gas plants more, we have 14 of them. If it supports non-fossil fuel plants, we
have four biomass and four hydro facilities ready to serve our customers.
In summary, 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 with the occasional bold move.
Thank you for your investment in Atlantic Power Corporation, and thank you for your continued
support.
21APR201521422407
James J. Moore, Jr.
President and Chief Executive Officer
April 27, 2016
(i, ii, iii) Project Adjusted EBITDA, Adjusted Cash Flows from Operating Activities and Adjusted Free
Cash Flow are not recognized measures under Generally Accepted Accounting Principles
(GAAP) and do not have any standardized meaning prescribed by GAAP, and may not be
comparable to similar measures presented by other companies. Please refer to Item 7,
‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations—
Supplementary Non-GAAP Financial Information’’ in the accompanying Annual Report on
Form 10-K for reconciliations of Project Adjusted EBITDA to GAAP project income (loss).
Please refer to the tables in Annex A for reconciliations of Adjusted Cash Flows from
Operating Activities and Adjusted Free Cash Flow to GAAP Cash flows from operating
activities.
(iv)
(v)
Thorndike, William N., Jr. The Outsiders: Eight Unconventional CEOs and Their Radically
Rational Blueprint for Success. Boston: Harvard Business Review Press, 2012.
Greenwald, Bruce and Khan, Judd. Competition Demystified: A Radically Simplified Approach
to Business Strategy. New York: Penguin Group (USA) Inc., 2005.
Annex A
ATLANTIC POWER CORPORATION
RECONCILIATION FROM CASH FLOWS FROM OPERATING ACTIVITIES (A GAAP MEASURE)
TO ADJUSTED CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FREE CASH
FLOW FOR THE YEAR ENDED DECEMBER 31, 2015 (UNAUDITED)
Project Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustment for equity method projects(1) . . . . . . . . . . . . . . . . . . . .
Corporate G&A expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash interest payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, including changes in working capital . . . . . . . . . . . . . . . . . .
Year ended December 31, 2015
Continuing
Operations
Discontinued
Operations
Total
$ 208.9
$ 28.1
$ 237.0
2.2
(29.4)
(98.3)
(3.9)
(7.8)
(2.7)
—
(1.5)
(6.2)
(2.0)
(0.5)
(29.4)
(99.8)
(10.1)
(9.8)
Cash flows from operating activities . . . . . . . . . . . . . . . . . . . . . . .
$ 71.7
$ 15.7
$ 87.4
Changes in other operating balances . . . . . . . . . . . . . . . . . . . . . . .
Severance charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restructuring and other charges . . . . . . . . . . . . . . . . . . . . . . . . . .
Shareholder litigation expenses . . . . . . . . . . . . . . . . . . . . . . . . . . .
Refinancing transaction costs . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt redemption costs (9.0% Notes) (Q3 2015) . . . . . . . . . . . . . . .
Adjusted Cash Flows from Operating Activities . . . . . . . . . . . . . . .
Term loan facility repayments(2)
. . . . . . . . . . . . . . . . . . . . . . . . . .
Project-level debt repayments . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of property, plant and equipment
. . . . . . . . . . . . . . . . .
Distributions to noncontrolling interests(3) . . . . . . . . . . . . . . . . . . .
Dividends on preferred shares of a subsidiary company . . . . . . . . .
7.8
3.9
0.6
0.6
1.1
19.5
2.0
—
—
—
—
—
9.8
3.9
0.6
0.6
1.1
19.5
$ 105.3
$ 17.7
$ 123.0
(68.3)
(15.1)
(11.3)
—
(8.8)
—
—
—
(3.7)
—
(68.3)
(15.1)
(11.3)
(3.7)
(8.8)
Adjusted Free Cash Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1.8
$ 14.0
$ 15.8
Additional GAAP cash flow measures:
Cash flows from investing activities . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from financing activities . . . . . . . . . . . . . . . . . . . . . . . .
$ 333.7
($432.8)
($12.8)
($13.0)
$ 320.9
($445.8)
(1) Represents difference between Project Adjusted EBITDA and cash distributions from equity
method projects.
(2)
Includes 1% mandatory annual amortization and 50% excess cash flow repayments by the Atlantic
Power Limited Partnership.
(3) Distributions to noncontrolling interests primarily include distributions, if any, to the tax equity
investors at Canadian Hills and to the other 50% owner of Rockland. These projects were sold in
June 2015.
RECONCILIATION FROM CASH FLOWS FROM OPERATING ACTIVITIES (A GAAP MEASURE)
TO ADJUSTED CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FREE CASH
FLOW FOR THE YEAR ENDED DECEMBER 31, 2014 (UNAUDITED)
Project Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustment for equity method projects(1)
. . . . . . . . . . . . . . . . . . . .
Corporate G&A expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash interest payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . .
Other, including changes in working capital
Year ended December 31, 2014
Continuing
Operations
Discontinued
Operations
Total
$ 229.4
$ 69.8
$ 299.2
(0.8)
(37.9)
(154.9)
(2.1)
(17.0)
(6.1)
—
(13.8)
—
(1.6)
(6.9)
(37.9)
(168.7)
(2.1)
(18.6)
Cash flows from operating activities . . . . . . . . . . . . . . . . . . . . . . .
$ 16.7
$ 48.3
$ 65.0
Changes in other operating balances . . . . . . . . . . . . . . . . . . . . . . .
Severance charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restructuring and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shareholder litigation expenses . . . . . . . . . . . . . . . . . . . . . . . . . . .
Refinancing transaction costs (Q1 2014) . . . . . . . . . . . . . . . . . . . . .
17.0
6.1
1.7
1.4
49.4
1.6
—
—
—
—
18.6
6.1
1.7
1.4
49.4
Adjusted Cash Flows from Operating Activities . . . . . . . . . . . . . . .
Term loan facility repayments(2) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Project-level debt repayments(3)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of property, plant and equipment(4) . . . . . . . . . . . . . . . . .
Distributions to noncontrolling interests(5) . . . . . . . . . . . . . . . . . . . .
Dividends on preferred shares of a subsidiary company . . . . . . . . . .
$ 92.4
$ 49.9
$ 142.3
(58.4)
(11.7)
(11.1)
—
(11.6)
—
(6.4)
(2.3)
(11.0)
—
(58.4)
(18.1)
(13.4)
(11.0)
(11.6)
Adjusted Free Cash Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
($
0.3)
$ 30.2
$ 29.9
Additional GAAP cash flow measures:
Cash flows from investing activities . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from financing activities . . . . . . . . . . . . . . . . . . . . . . . .
$ 73.5
($131.6)
($ 4.8)
($50.8)
$ 68.7
($182.4)
(1) Represents difference between Project Adjusted EBITDA and cash distributions from equity
method projects.
(2)
Includes 1% mandatory annual amortization and 50% excess cash flow repayments by the Atlantic
Power Limited Partnership.
(3) Excludes $8.1 million principal repayment at Piedmont on term loan conversion (February 2014).
(4) Excludes construction costs related to the Company’s Canadian Hills project in 2014.
(5) Distributions to noncontrolling interests primarily include distributions, if any, to the tax equity
investors at Canadian Hills and to the other 50% owner of Rockland. These projects were sold in
June 2015.
26APR201113105954
FOLLOWING IS THE COMPANY’S ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015
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, 2015
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, 2015, the aggregate market value of the voting and nonvoting common equity held by non-affiliates of the registrant was $374.0 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 March 3, 2016, 121,624,829 of the registrant’s Common Shares were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for its 2016 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
16
38
38
38
41
42
45
47
84
87
88
88
89
90
90
90
90
90
91
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
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. 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:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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 plan, including the objective of enhancing the value of our
existing assets through optimization 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;
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 ability to renew or enter into new power purchase agreements on favorable terms or at all after the
expiration of our current agreements;
our ability to meet the financial covenants under our Senior Secured Credit Facilities 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.
1
These risks include, without limitation:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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
Senior Secured 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 outcome of certain shareholder class action lawsuits in Canada;
the expiration or termination of power purchase agreements and our ability to renew or enter into new
power purchase agreements on favorable terms or at all;
the dependence of our projects on their electricity and thermal energy customers;
exposure of certain of our projects to fluctuations in the price of electricity or natural gas;
the dependence of our projects on third-party suppliers;
projects not operating according to plan;
the effects of weather, which affects demand for electricity and fuel as well as operating conditions;
(cid:120) U.S., Canadian and/or global economic conditions and uncertainty;
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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;
2
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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;
our ability to retain, motivate and recruit executives and other key employees; and
our ability to remediate the reported material weakness in our internal control over financial reporting.
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
power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of
December 31, 2015, our power generation projects in operation 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 operational power generation projects across nine states in the
United States and two provinces in Canada. 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:
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 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
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
4
(“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 growth projects, external 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 Power Purchase Agreements. We evaluate external growth opportunities on a regular basis, and
have a highly disciplined and opportunistic approach that favors capital-light projects in the United States and Canada.
We will prioritize the use of discretionary cash for repurchases of our debt and equity securities 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 focus on generating stable operating margins via contracted cash
flows from our existing assets, and we use our depth of asset management experience to enhance the operating,
contractual and financial performance of our current portfolio of projects.
In 2015, we successfully executed on several key initiatives. Through consolidation of our corporate operations
to a single location as well as a reduction in workforce, we lowered our corporate overhead expenses from $54 million in
2013 to $32 million in 2015. We have utilized proceeds from asset sales at attractive valuations, as well as cash flow
from our existing projects, to pay down debt, including our highest-cost debt. In total, we have reduced debt by
approximately $833 million in the past two years and reduced our annual cash interest payments by approximately $65
million or more than 50%. We invested $22 million in our existing fleet in 2013 through 2015 and realized a cash return
on these investments of approximately $6 million in 2015, which is expected to grow to $10 million in 2016.
5
On February 9, 2016, the Board of Directors, consistent with management’s recommendation, eliminated the
common share dividend, effective immediately. Previously, we paid a dividend of Cdn$0.03 per share quarterly, with the
most recent payment on December 31, 2015. This change to our capital allocation strategy is designed to create value for
shareholders in a tax-efficient manner, while also improving our financial flexibility and strengthening our balance sheet.
As part of this strategy, we will prioritize allocation of our discretionary capital to equity and debt repurchases, each
under the normal course issuer bid (“NCIB”) implemented in December 2015, with a goal of capturing value arising
from price-to-value opportunities in our publicly traded securities. In addition, the additional liquidity can be used for
organic growth through high-return investments in existing projects, as well as potential repowering of projects linked to
extensions of PPAs.
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,
“reverse” request for proposals 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. When a PPA expires or is
terminated, it is possible that the price received by the project for power under subsequent arrangements may be reduced
and in some cases, significantly. Our projects may not be able to secure a new agreement and could be exposed to 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. See Item 1A. “Risk Factors—Risk Related to Our Business and
Our Projects—The expiration or termination of our power purchase agreements 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:
(cid:120)
(cid:120)
(cid:120)
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 and the acquisition of other partners’ interests in our existing portfolio.
Acquisition and investment strategy
We believe that new electricity generation projects will continue to be required in selective markets in the
United States and Canada as a result of lower projected reserve margins and the retirement of older generation projects
due to obsolescence or environmental concerns. In addition, renewable portfolio standards in more than 33 U.S. states as
well as renewable initiatives in several Canadian provinces have greatly facilitated attractive PPAs and financial returns
for renewable project opportunities. 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 and there is also a very
active secondary market for the purchase and sale of existing projects.
6
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 predictable cash flows are attractive.
OUR COMPETITIVE STRENGTHS
We believe we distinguish ourselves from other independent power producers through the following
competitive strengths:
(cid:120) Diversified projects. Our power generation projects have an aggregate gross electric generation capacity of
approximately 2,138 MW, and our net ownership interest in these projects is approximately 1,500 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 provinces
of Ontario and British Columbia.
(cid:120) 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.
(cid:120) Stability of project cash flow. Many of our power generation projects currently in operation have been in
operation for over 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.
(cid:120) Strong in-house operations and asset management teams. We manage the operations of eighteen of our
power generation projects, which represent 64% of our portfolio’s 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 optimally manage our physical assets and commercial relationships to
increase shareholder value. Our preference is to own the majority of, and operate all of our businesses. We proactively
seek scale opportunities and to establish best practices that result in EBITDA and cash flow growth across all of our
twenty-three operating plants. Our asset management group works to ensure that our projects receive appropriate
preventative and corrective maintenance and incur capital expenditures, if justified, 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 recognized leaders 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 March 3,
2016, including our interest in each facility. We believe our portfolio is well diversified in terms of electricity and steam
7
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
operations. Our financial results for the year ended December 31, 2014 and 2013 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 35.7%, 34.1% and 30.9% of consolidated revenue in 2015, 2014 and
2013, respectively, and total net generation capacity of 592 MW at December 31, 2015. Niagara Mohawk Power
Corporation and Equistar Chemicals, LP accounted for 8% and 8% of total consolidated revenues, respectively, and 24%
and 23% of total revenues from the East U.S. segment, respectively, for the year ended December 31, 2015.
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
2015
2014
2013
Set forth below is a list of our East U.S. projects in operation:
Project income
($ in millions)
Revenue
($ in millions)
$
150.0 $
167.1
146.1
Gross Economic Net
Fuel
MW Interest
MW Primary Electric Purchasers
Project
Orlando(1)
Piedmont
Morris
Cadillac
Chambers(1)
Location
Florida
Georgia
Illinois
Natural Gas
Biomass
Natural Gas
129
55
177
50.00 %
100.00 %
100.00 %
Michigan
New Jersey
Biomass
Coal
40
262
100.00 %
40.00 %
Kenilworth
Curtis Palmer(3)
Selkirk(1)
New Jersey
New York
New York
Natural Gas
Hydro
Natural Gas
29
60
345
100.00 %
100.00 %
17.70 %
65
55
120
57
40
89
16
29
60
61
Progress Energy Florida
Georgia Power
Merchant
Equistar Chemicals, LP(4)
Consumers Energy
Atlantic City Electric (2)
DuPont
Merck & Co., Inc.
Niagara Mohawk Power Corperation
Merchant
(1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated
affiliates.
(2) 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.
8
38.7
8.7
1.6
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)
BBB+
A
NR
BBB+
BBB
BBB+
A-
AA
A-
NR
(3) 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, 2015, the facility has generated 6,691 GWh under its PPA.
(4) Represents the credit rating of LyondellBasell, the parent company of Equistar Chemicals, as Equistar is not rated.
West U.S. Segment
Our West U.S. segment accounted for 24.9%, 25.2% and 25.2% of consolidated revenue in 2015, 2014 and
2013, respectively, and total net generation capacity of 592 MW at December 31, 2015. San Diego Gas & Electric
provided for 11% of total consolidated revenues and 45% of total revenues from the West U.S. segment for the year
ended December 31, 2015.
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
2015
2014
2013
Set forth below is a list of our West projects in operation:
Revenue
($ in millions)
$
104.6 $
123.6
119.1
Project income (loss)
($ in millions)
7.6
(27.6)
41.7
Project
Naval Station
Naval Training Center
North Island
Oxnard
Manchief
Frederickson(1)
Location Fuel
MW Interest
MW Primary Electric Purchasers
Gross Economic Net
Power
Contract
Expiry
Customer
Credit
Rating
(S&P)
California
California
California
California
Colorado
Washington
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
47
25
40
49
300
250
100.00 %
100.00 %
100.00 %
100.00 %
100.00 %
50.15 %
47
25
40
49
300
50
45
30
6
San Diego Gas & Electric
San Diego Gas & Electric
San Diego Gas & Electric
Southern California Edison
Public Service Company of Colorado
Benton Co. PUD
Grays Harbor PUD
Franklin Co. PUD
Puget Sound Energy
December 2019
December 2019
December 2019
May 2020
April 2022
August 2022
August 2022
August 2022
December 2037
A
A
A
BBB+
A-
A+
A
A
BBB
Koma Kulshan(1)
Washington
Hydro
13
49.80 %
(1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated
affiliates.
Canada Segment
Our Canada segment accounted for 39.2%, 40.5% and 44.1% of consolidated revenue in 2015, 2014 and 2013,
respectively, and total net generation capacity of 317 MW at December 31, 2015. Ontario Electric Financial Corporation
(“OEFC”) and BC Hydro provided for 29% and 10% of total consolidated revenues, respectively, and 74% and 26% of
total revenues from the Canada segment, respectively, for the year ended December 31, 2015.
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
2015
2014
2013
Set forth below is a list of our Canada projects in operation:
Gross Economic Net
Project (loss) income
($ in millions)
Revenue
($ in millions)
$
164.7 $
198.3
208.6
(85.7)
(10.5)
18.1
Power
Contract
Expiry
Project
Mamquam
Moresby Lake
Williams Lake
Calstock
Kapuskasing
Nipigon
North Bay
Tunis(1)
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
MW Interest
MW
50
6
66
35
40
40
40
40
100.00 % 50
100.00 %
6
100.00 % 66
100.00 % 35
100.00 % 40
100.00 % 40
100.00 % 40
100.00 % 40
Primary Electric Purchasers
British Columbia Hydro and Power Authority
British Columbia Hydro and Power Authority
British Columbia Hydro and Power Authority
Ontario Electric Financial Corporation
Ontario Electric Financial Corporation
Ontario Electric Financial Corporation
Ontario Electric Financial Corporation
Independent Electricity System Operator
September 2027
August 2022
March 2018
June 2020
December 2017
December 2022
December 2017
NA
Customer
Credit
Rating
(S&P)
AAA
AAA
AAA
AA
AA
AA
AA
AA
(1) On January 20, 2015, we entered into an agreement with the Ontario Power Authority and its successor, the
Independent Electricity System Operator (“IESO”), for the future operations of the Tunis facility. Subject to
meeting certain technical modifications to the plant, gas delivery and other requirements, Tunis will operate under a
15-year agreement with the IESO commencing between November 2017 and June 2019. The new contract will
require the plant to become fully dispatchable as opposed to its current baseload configuration. As such, Tunis will
only provide electricity to the Ontario grid when required, thereby assisting to reduce the incidents of surplus
baseload generation in the market. 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 is called upon to operate.
POWER INDUSTRY OVERVIEW
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, energy prices and uncertainty resulting
from environmental regulations.
According to the North American Electric Reliability Corporation’s (“NERC”) Long-Term Reliability
Assessment (“LTRA”), published in December 2015, 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 0.99% and 0.92% for the summer and winter seasons, respectively. 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
10
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 that operate in
the North American electric power generation industry. The electric power industry is one of the largest industries in the
United States, generating retail electricity sales of approximately $359 billion though November 2015, 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 38% of total net generation in 2014. 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.
Generating projects
(cid:120) 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
11
granted authority to charge market-based rates 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 review the prudency of utilities
entering into PPAs entered into by 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 NERC. NERC is a self-regulatory non-governmental organization
which has statutory responsibility to regulate bulk power system users, generation and transmission owners and
operators through the adoption and enforcement of standards for fair, ethical and efficient practices.
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 liability standards and an outside law firm specializing in this area advises us on
FERC and NERC compliance, including annual compliance training for relevant employees.
(cid:120) British Columbia, Canada
The vast majority of British Columbia’s power is generated or procured by the British Columbia Hydro and
Power Authority (“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.
The BCUC has adopted the NERC standards 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 (British Columbia), 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, achieve electricity self-sufficiency by
2016, promote economic development and job creation and continue to work toward the reduction of greenhouse gas
emissions. This Act also explicitly states that British Columbia will encourage the use of waste heat, biogas and biomass
to reduce waste. This Act is consistent with the BC Energy Plan: A Vision for Clean Energy Leadership, introduced by
the Government of British Columbia in 2009, which favors clean and renewable energy sources such as hydroelectric,
12
wind and wood waste electricity 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.
(cid:120) 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:
(cid:120) Determination of the rates charged for regulated services in the electricity sector;
(cid:120) Licensing of market participants;
(cid:120)
Inspections, particularly with respect to compelling production of records and information;
(cid:120) Market monitoring and reporting, including on anti-competitive practice;
(cid:120) Consumer advocacy; and
(cid:120) Enforcement and compliance.
The OEB has the authority effectively to modify licenses by adopting “codes” that are deemed to form part of
the licenses. Furthermore, any violations of the license or other irregularities in the relationship with the OEB can result
in fines. While the OEB provides reports to the Ontario Minister of Energy, it generally operates independently from the
government. However, the Minister may issue policy directives (with Cabinet approval) concerning general policy and
the objectives to be pursued by the OEB, and the OEB is required to implement such policy directives.
A number of other regulators and quasi-governmental entities play a role in electricity regulation in Ontario,
including the Independent Electricity System Operator, 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
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.
13
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), the Electrical Safety Authority, and Ontario Electricity
Financial Corporation. 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% of the entity in future years.
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.
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.
At the federal level, President Obama has identified climate change as a major priority. 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
14
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 is 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. Oral arguments are scheduled to begin in June 2016.
In Canada, British Columbia and Ontario have implemented greenhouse gas reporting regulations and are
developing additional programs to address greenhouse gas emissions.
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 (British Columbia) (“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.
Other related, key pieces of legislation include the Carbon Tax Act (British Columbia) (“CTA”) and the
Greenhouse Gas Industrial Reporting and Control Act (British Columbia) (“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 (British Columbia) (“GGERR”), the Greenhouse Gas Emission Administrative Penalties
and Appeals Regulation (British Columbia) (“GGEAPAR”) and the Greenhouse Gas Emission Control Regulation
(British Columbia) (“GGECR”). GGERR establishes compliance reporting requirements and ensures that industrial
operations that emit over 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.
The government of Ontario has released preliminary plans for its proposed carbon emissions “cap and trade”
system. The system, if implemented, would impose emission caps on businesses in key industries, including the
electricity sector starting on January 1, 2017. Businesses that expect to exceed the emissions cap would be able to
purchase emissions allowances through an auction process. The province proposes to impose financial penalties on those
exceeding the emission caps. Draft legislation has been made available for public review; however, details of the
proposed caps, costs of emission allowances and financial penalties are not available. Distribution of natural gas has also
been identified by the province as a sector which will be subject to the cap and trade regulation.
15
Additionally, more than half of the U.S. states and most Canadian provinces have set mandates requiring certain
levels of renewable energy production and/or energy efficiency during target timeframes. This includes generation from
wind, solar and biomass. In order to meet CO2 reduction goals, changes in the generation fuel mix are forecasted to
include a reduction in existing coal resources, higher reliance on natural gas and renewable energy resources and an
increase in demand-side resources. Investments in new or upgraded transmission lines will be required to move
increasing renewable generation from more remote locations to load centers.
In December 2015, 195 countries participating in the United Nations Framework Convention on Climate
Change (“UNFCC”), at its 21st Conference of the Parties meeting (“COP21”) held in Paris, adopted a new global
agreement on the reduction of climate change (the “Paris Agreement”). The Paris Agreement 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). The Paris Agreement may result in
additional regulations to reduce carbon emissions in the United States and Canada in coming years.
EMPLOYEES
As of March 3, 2016, we had 291 employees, 195 in the United States and 96 in Canada. Of our Canadian
employees, 60 are covered by two collective bargaining agreements, which expire on December 31, 2016. During 2015,
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
16
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, including pursuant to the mandatory
amortization feature of the Senior Secured Credit Facilities (as defined herein), as well as the 50% cash sweep, 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 Cdn$67.3 million aggregate principal amount of our 6.25% convertible debentures is due March 2017, the
Cdn$75.8 million aggregate principal amount of our 5.60% convertible unsecured subordinated debentures is due June
2017, the $117.0 million aggregate principal amount of our 5.75% convertible unsecured subordinated debentures is due
June 2019 and the Cdn$90.0 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 Senior Secured Credit Facilities, as well as the 50% cash sweep, 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 Senior Secured Credit Facilities, as well as the 50% cash sweep, 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
17
general economic conditions. We cannot provide any assurance that we will be able to access the credit or capital
markets on acceptable terms or timing, or at all.
Our Senior Secured 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 Senior Secured Credit Facilities contain certain terms, covenants and restrictions, including a mandatory
amortization feature and customary prepayment provisions, including, among others, using 50% of the cash flow of the
Partnership and its subsidiaries that remains after the application of funds, in accordance with customary priority, to
certain items, including, but not limited to, the operations and maintenance expenses of the Partnership and its
subsidiaries, debt service on the Senior Secured Credit Facilities and other specified indebtedness and funding of a debt
service reserve account. 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 Senior Secured 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 Senior Secured Credit Facilities include a requirement that the Partnership and its
subsidiaries, maintain certain leverage and interest coverage ratios (each, as defined in the credit agreement governing
the Senior Secured Credit Facilities). The Senior Secured 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:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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
placing us at a competitive disadvantage to our competitors that are not as highly leveraged.
As of December 31, 2015, our consolidated long-term debt represented approximately 70% of our total
capitalization, comprised of debt and balance sheet equity.
18
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 77% of our debt, including our share of the project-level debt
associated with equity investments in affiliates, either bears interest at fixed rates or is financially hedged through the use
of interest rate swaps.
As of December 31, 2015, we had (i) no amount outstanding and $104.0 million issued in letters of credit under
our revolving credit facility, (ii) $285.4 million of outstanding convertible debentures, and (iii) $733.3 million of
outstanding senior secured term loan 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 Senior Secured Credit Facility, 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. 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.
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
19
revaluation of our Canadian dollar-denominated debt. Although we currently generate sufficient revenues in Canadian
dollars to fund our Canadian dollar obligations, future exchange rate volatility or changes to our Canadian dollar
revenues could expose us to currency exchange rate risks, against which we do not typically hedge. Any arrangements to
mitigate this exchange rate risk may not be sufficient to fully protect against this risk. If hedging transactions do not fully
protect against this risk, changes in the currency exchange rate between U.S. and Canadian dollars could adversely affect
our available cash flow and results of operations.
A downgrade in our credit rating or in the credit rating of our outstanding debt securities, or any deterioration in
credit quality could negatively affect our ability to access capital and our ability to hedge, and could trigger
termination rights under certain contracts
A downgrade in our credit rating, a downgrade in the credit rating of our outstanding debt securities, or any
deterioration in credit quality could adversely affect our ability to renew existing, or obtain access to new, credit
facilities and could increase the cost of such facilities, restrict access to our revolving credit facility and/or trigger
termination rights or enhanced disclosure requirements under certain contracts to which we are a party. Any downgrade
of our corporate credit rating could also cause counterparties to require us to post letters of credit or other additional
collateral, make cash prepayments, or obtain a guarantee agreement, all of which would expose us to additional costs
and/or could adversely affect our ability to comply with covenants or other obligations under any of our revolving credit
facility, convertible debentures or unsecured notes or any other financing arrangements, borrowings or indebtedness (or
could constitute an event of default under any such financing arrangements, borrowings or indebtedness that we may be
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 on-going 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.”
20
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:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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
(cid:120)
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 25 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) 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:
(cid:120) 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;
(cid:120) 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
(cid:120) 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 Senior Secured Credit Facilities, the Partnership will be required to offer each electing lender to prepay such lender’s
21
term loans under the Senior Secured 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:
(cid:120) 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;
(cid:120) 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
(cid:120) 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
its 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.
22
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.
Atlantic Power Preferred Equity Ltd. is subject to Canadian tax, as is Atlantic Power’s income from the Partnership
As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes. See “Risks
Related to Our Structure—We are subject to Canadian tax.” We are required to include in computing our taxable income
any income earned by the Partnership. In addition, Atlantic Power Preferred Equity Ltd., a subsidiary of the Partnership,
is also a Canadian corporation and is generally subject to Canadian federal, provincial and other taxes. Atlantic Power
Preferred Equity Ltd. is liable to pay its applicable Canadian taxes.
We are subject to significant pending civil litigation, which if decided against us, could require us to pay substantial
judgments or settlements and incur expenses that could have a material adverse effect on our business, results of
operations, financial condition and liquidity.
Litigation may be time consuming, expensive and distracting from the conduct of our daily business. Due to the
nature of these proceedings, the lack of precise damage claims and the type of claims we are subject to, we are unable to
23
determine the ultimate or maximum amount of monetary liability or financial impact, if any, to us in these legal matters,
which unless otherwise described in "Item 3. Legal Proceedings", seek damages from the defendants of material or
indeterminate amounts. As a result, we are also unable to reasonably estimate the possible loss or range of losses, if any,
arising from these litigations. Although we are unable at this time to estimate what our ultimate liability in these matters
may be, it is possible that we will be required to pay substantial judgments or settlements and incur expenses that could
have a material adverse effect on our business, results of operations, financial condition and liquidity. We intend to
defend vigorously against these actions. For additional information with respect to these unresolved matters, see "Item 3.
Legal Proceedings".
Risks Related to Our Business and Our Projects
The expiration or termination of our power purchase agreements 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. Approximately 25% of our projects,
on a net MW basis, and 33% on a Project Adjusted EBITDA basis, have PPAs that will expire in the next five years,
including North Bay, Kapuskasing, Calstock, Williams Lake, Oxnard, North Island, Naval Training Center, Naval
Station and Kenilworth. 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. If this occurs, the affected project may temporarily or
permanently cease operations and 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”.
The loss of significant PPAs, our inability to secure new PPAs on favorable terms or at all, or the breach by the
other parties to such contracts that prevents us from fulfilling our obligations thereunder, could have a material adverse
impact on our business, results of operations and financial condition.
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 2015, the largest customers of our
power generation projects, including projects recorded under the equity method of accounting, are IESO, San Diego
Gas & Electric, and BC Hydro which purchase approximately 29%, 11% and 10%, 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
24
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, should any of the long-term
PPAs expire or terminate, the relevant project will be required to either negotiate a new PPA or sell into the electricity
wholesale market, in which case the prices for electricity will depend on market conditions at the time, which may not be
favorable. The open market wholesale prices for electricity are very volatile. Long and short-term power prices may
fluctuate substantially due to other factors outside of our control, including:
(cid:120)
(cid:120)
(cid:120)
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;
(cid:120) weather conditions;
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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,
25
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, none of the capacity of the facility is contracted and is therefore sold at market prices or not sold at
all if market prices do not support the profitable operation of that portion 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.
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:
(cid:120) weather conditions;
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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
26
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
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 $210 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.
27
Revenues from hydropower projects are highly dependent on suitable 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 climatic conditions, particularly precipitation
patterns, which are variable and difficult to predict for any given year. We base our investment decisions with respect to
each hydro energy project on the historical stream flow records for the area. However, actual climatic conditions in any
given year may not meet the historical averages which would impair our ability to meet anticipated production levels,
which could adversely affect our forecasted revenues.
U.S., Canadian and/or global economic conditions and uncertainty could adversely affect our business, results of
operations and financial condition
Our business may be affected by changes in U.S., Canadian and/or global economic conditions, including
inflation, deflation, interest rates, availability of capital, consumer spending rates and the effects of governmental
initiatives to manage economic conditions. Uncertainty about global economic conditions may cause consumers to alter
behaviors that may directly or indirectly reduce energy spending, which could have a material adverse effect on demand
for our product. Volatility in the financial markets and the deterioration of national and global economic conditions may
have a material adverse effect on our business, results of operations and financial condition.
Financial markets can also be, and have been in the past, affected by concerns over U.S. fiscal policy, federal
deficit and related budget and tax issues. These concerns continue to raise discussions relating to the stability of the
long-term sovereign credit rating of the United States. Any actions taken by the U.S. federal government regarding the
federal deficit or any action taken or threatened by ratings agencies, could significantly impact the global and U.S.
economies and financial markets. Any such economic downturn could have a material adverse effect on our business,
results of operations and financial condition.
Risks that are beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of
war, natural disasters or other catastrophic events could have a material adverse effect on our business, results of
operations, ability to raise capital and financial condition
Man-made events, such as acts of terror and governmental responses to acts of terror, could adversely affect
general economic conditions, which could have a material impact on our business, results of operations and financial
condition. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other
domestic targets. Our projects may be targets of terrorist activities, as well as events occurring in response to or in
connection with them, that could cause environmental repercussions and/or result in full or partial disruption of the
ability of the projects to generate and/or transmit electricity. Any such environmental repercussions or other disruption
could result in a decline in energy consumption and significant decrease in revenues or significant reconstruction or
remediation costs, which could have a material adverse effect on our business, results of operations and financial
condition.
Our projects could also be impacted by natural disasters, such as earthquakes, floods, lightning activity,
hurricanes, tropical storms, winter storms, tornadoes, wind, seismic activity, more frequent and more extreme weather
events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise
and other related phenomena. Severe weather or other natural disasters could be destructive or otherwise disrupt our
operations or compromise the physical or cyber security of our facilities, which could result in increased costs and could
adversely affect our ability to manage our business effectively. We maintain standard insurance against catastrophic
losses, which are subject to deductibles, limits and exclusions; however, our insurance coverage may not be sufficient to
cover all of our losses. Additionally, future significant weather-related events, natural disasters and other similar events
that have an adverse effect on the economy could have a material adverse effect on our business, results of operations,
ability to raise capital and financial condition.
28
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.
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
29
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 U.S., 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.
(i) 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 (British Columbia) 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 govering conditions to be contained in agreements entered into
by public utilities for electricity. Consequently, power procurement is controlled by the BCUC and, as a result, our
potential contracts with BC Hydro may be subject to terms that adversely affect us.
The Clean Energy Act (British Columbia), which became law in 2010, 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 resource plans outlining how it will meet these objectives and requires the
province to be electricity self-sufficient by 2016. BC Hydro is generally required to acquire all new power (beyond what
30
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 only undertaking development of new generation
facilities/projects 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.
(ii) 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.
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,
31
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. Other more stringent EPA air emission regulations currently being implemented include the
more stringent national ambient air quality standards for sulfur dioxide, issued in June 2010, and for fine particulate
matter, issued in December 2012. Additionally, EPA’s new mercury and air toxics emissions standards for power plants,
issued in December 2011, are undergoing reconsideration after they were overturned by the Supreme Court. 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
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.
32
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. In the United States, President Obama has declared action addressing climate change to be a major priority, and
the EPA has taken several recent actions for the regulation of greenhouse gas emissions. See “Item 1. Business—
Industry Regulation—Carbon Emissions.” We expect that additional EPA regulations, and possibly additional legislation
and/or regulation by other regulatory authorities, may be issued, resulting in the imposition of additional limitations on
greenhouse gas emissions or requiring efficiency improvements from fossil fuel-fired electric generating units.
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,
regulatory restrictions may arise in the event the government of Ontario implements its plans for a carbon emissions cap
and trade system, proposed to take effect in January 2017. This 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.
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, 2015, we had $134.5 million of goodwill, which represented approximately 7.8% 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), negative or declining cash flows, loss of a key contract or customer (particularly
when we are unable to replace it on equally favorable terms), 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
33
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.
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.”
We have limited control over management decisions at certain projects
Six 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 six 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
34
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.”
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.
35
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, from one plant in British Columbia and 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, 2015, 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
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
36
Securities and Exchange Commission (the “SEC”) 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.”
As a result of the sale of our Wind Projects, our business has become more concentrated, subjecting it to increased
risk from each individual portion of the business
As a result of the sale of the Wind Projects on June 26, 2015, our operations have become more concentrated in
our remaining East U.S., West U.S. and Canada segments, our portfolio of projects has become less diversified
geographically and by fuel type, we have fewer renewable energy projects in our portfolio and our customer base is
more concentrated. As a result, each of the risks that affected our projects prior to the sale of the Wind Projects,
including, without limitation, our exposure to market prices of electricity and risks associated with equipment failure or
frequent and/or larger than forecasted downtimes for equipment maintenance and repair, will now pose a greater risk to
our overall business, financial condition and results of operations. Further, new laws or other regulatory developments
that favor renewable energy and in particular, wind energy, may have a more significant adverse impact on our business
than in the past. In addition, approximately 25% of our PPAs on a MW-weighted basis are scheduled to expire over the
next five years, beginning in December 2017, and our weighted average remaining PPA life after the close of the sale of
our Wind Project is approximately 8 years, down from 10 years previously. This increases our reliance on each of our
existing PPAs and the potential adverse effect that could result from the expiration or termination of any single PPA. In
addition, the increased concentration of our business in our remaining East U.S, West U.S. and Canada segments also
increases our dependence on our remaining customers. For the year ended December 31, 2015, OEFC, San Diego Gas &
Electric and BC Hydro accounted for 29%, 11% and 10%, respectively, of our revenue. If any such 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, which may adversely impact our business.
We reported a material weakness in our internal control over financial reporting, which if not remedied, could
continue to adversely affect our internal controls and financial reporting and could lead to materially inaccurate
financial reports.
In connection with our management's assessment of the effectiveness of our internal control over financial
reporting as of December 31, 2015, we identified a material weakness in our internal control over financial reporting, as
described in "Item 9A. Controls and Procedures." Although we believe we are taking the steps necessary to remediate
the material weakness, we cannot assure you that the processes, procedures and controls we implement will result in full
remediation of the material weakness. Failure to remediate the material weakness, or additional material weaknesses in
our internal control over financial reporting, could result in material misstatements in our financial statements or cause
37
us to fail to timely meet our reporting obligations. The occurrence of these events could in turn potentially negatively
impact our share price or divert management’s attention.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We have included descriptions of the locations and general character of our principal physical operating
properties, including an identification of the segments that use such properties, in “Item 1. Business,” which is
incorporated herein by reference. A significant portion of our equity interests in the entities owning these properties is
pledged as collateral under our Senior Secured 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
Shareholder class action lawsuits
Massachusetts District Court Actions
On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints
were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of
Massachusetts (the “District Court”) against Atlantic Power and Barry E. Welch, our former President and Chief
Executive Officer and a former Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or
all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer,
and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the “Proposed Individual
Defendants,” and together with Atlantic Power, the “Proposed Defendants”) (the “U.S. Actions”).
The District Court complaints differed in terms of the identities of the Proposed Individual Defendants they
named, as noted above, the named plaintiffs, and the purported class period they alleged (July 23, 2010 to March 4, 2013
in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions),
but in general each alleged, among other things, that in Atlantic Power’s press releases, quarterly and year-end filings
and conference calls with analysts and investors, Atlantic Power and the Proposed Individual Defendants made
materially false and misleading statements and omissions regarding the sustainability of Atlantic Power’s common share
dividend that artificially inflated the price of Atlantic Power’s common shares. The District Court complaints assert
claims under Section 10(b) and, against the Proposed Individual Defendants, under Section 20(a) of the Securities
Exchange Act of 1934, as amended.
The parties to each District Court action filed joint motions requesting that the District Court set a schedule in
the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class
action complaint (the “Amended Complaint”), after the appointment of lead plaintiff and counsel; (ii) setting a deadline
for Proposed Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for
subsequent briefing regarding any such motion to dismiss); and (iii) confirming that the Proposed Defendants need not
answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the
Amended Complaint. On May 7, 2013, each of six groups of investors (the “U.S. Lead Plaintiff Applicants”) filed a
motion (collectively, the “U.S. Lead Plaintiff Motions”) with the District Court seeking: (i) to consolidate the five U.S.
Actions (the “Consolidated U.S. Action”); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to
have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed
oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed
replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address
certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and
38
directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of
those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file
additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13
and September 18, 2013.
On March 31, 2014, the Court entered an order consolidating the five individual U.S. Actions, appointing the
Feldman, Shapero, Carter and Smith investor group (one of the six U.S. Lead Plaintiffs Applicants) as Lead Plaintiff and
approving Lead Plaintiff’s selection of counsel. The Court also granted the parties’ joint motion regarding initial case
scheduling and directed the parties to resubmit a proposed schedule that contains specific dates. In response to that
directive, on April 7, 2014, Lead Plaintiff filed an application and proposed order, which sought an extension of the
schedule contained in the joint motion. The application and proposed order requested that: (i) Lead Plaintiff be permitted
to file an amended complaint on or before May 30, 2014, (ii) the Proposed Defendants be permitted to move to dismiss
or otherwise respond to the amended complaint on or before July 29, 2014, (iii) Lead Plaintiff be permitted to file an
opposition, if any, on or before September 24, 2014, and (iv) the Proposed Defendants be permitted to file a reply to
Lead Plaintiff’s opposition on or before November 13, 2014. Proposed Defendants did not object to the schedule
proposed by Lead Plaintiff. On May 29, 2014, Lead Plaintiff filed a renewed application and proposed order, which
sought another extension of the schedule, and on June 3, 2014, Lead Plaintiff and the Proposed Defendants jointly filed a
stipulation and proposed order requesting the following revised schedule: (i) Lead Plaintiff be permitted to file an
amended complaint on or before June 6, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or
otherwise respond to the amended complaint on or before August 5, 2014, (iii) Lead Plaintiff be permitted to file an
opposition, if any, on or before October 6, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead
Plaintiff’s opposition on or before November 20, 2014. On June 3, 2014, the Court entered an order setting this
requested schedule.
On June 6, 2014, Lead Plaintiff filed the amended complaint (the “Amended Complaint”). The Amended
Complaint names as defendants Barry E. Welch and Terrence Ronan (the “Individual Defendants”) and Atlantic Power
(together with the Individual Defendants, the “Defendants”) and alleges a class period of June 20, 2011 to March 4, 2013
(the “Class Period”). The Amended Complaint makes allegations that are substantially similar to those asserted in the
five initial complaints. Specifically, the Amended Complaint alleges, among other things, that in Atlantic Power’s press
releases, quarterly and year-end filings and conference calls with analysts and investors, Defendants made materially
false and misleading statements and omissions regarding the sustainability of Atlantic Power’s common share dividend,
which artificially inflated the price of Atlantic Power’s common shares during the class period. The Amended Complaint
continues to assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the
Securities Exchange Act of 1934, as amended. It also asserts a claim for unjust enrichment against the Individual
Defendants. In accordance with the schedule referenced above, Defendants filed their motion to dismiss the consolidated
(the “Motion to Dismiss”) U.S. Action on August 5, 2014.
On September 30, 2014, citing Atlantic Power’s September 16, 2014 announcement of changes to its dividend
and its President and CEO transition, Lead Plaintiff filed a motion (the “Extension Motion”) requesting a thirty-day
extension of its October 6, 2014 deadline for filing its brief in opposition to the Motion to Dismiss, in which to
determine whether to file a second amended complaint. On October 2, 2014, the Court entered an order (i) extending
Lead Plaintiff’s deadline to file its opposition to the Motion to Dismiss to October 10, 2014 and (ii) requiring Defendants
to file their opposition to the Extension Motion by October 2, 2014. In accordance with this order, on October 2, 2014,
Defendants filed their opposition to the Extension Motion. On October 10, 2014, Lead Plaintiff filed its opposition to the
Motion to Dismiss (the “Opposition”) and also filed a motion for leave to amend the Amended Complaint, attaching a
proposed second amended complaint. On October 21, 2014, Lead Plaintiff and Defendants filed a joint scheduling
motion requesting (i) November 7, 2014 as the deadline for Defendants to file their opposition to Lead Plaintiff’s motion
for leave to amend the Amended Complaint; (ii) November 24, 2014 as the deadline for Defendants to file their reply in
further support of the Motion to Dismiss; and (iii) November 24, 2014 as the deadline for Lead Plaintiff to file its reply
in further support of its motion for leave to amend the Amended Complaint. On October 22, 2014, the Court entered an
order setting this requested schedule. Pursuant to that order, the Motion to Dismiss and Extension Motion were fully
briefed on November 24, 2014. On January 22, 2015, the Court held oral argument on the Motion to Dismiss and
Extension Motion.
39
On January 30, 2015, Lead Plaintiff filed a motion for leave to file a supplemental submission in opposition to
Defendants’ motion to dismiss (the “Motion for Leave”). The Court denied the Motion for Leave in an order entered on
February 5, 2015, but permitted Lead Plaintiff to submit a brief letter identifying supplemental authorities. Lead Plaintiff
filed that letter on February 9, 2015, and Defendants filed a response on February 10, 2015.
On March 13, 2015, the District Court entered an order granting Defendants’ motion to dismiss and denying
Lead Plaintiff’s motion to amend the Amended Complaint, and on March 18, 2015, the District Court entered an order
dismissing the Amended Complaint with prejudice.
On April 16, 2015, Lead Plaintiff filed a notice of appeal to the United States Court of Appeals for the First
Circuit (the “First Circuit”). On August 19, 2015, Lead Plaintiff filed with the First Circuit its brief appealing the
dismissal of its securities fraud claims.
On September 4, 2015, while appellate proceedings were still on-going, Lead Plaintiff filed with the District
Court a Rule 60(b)(2) motion to vacate the judgment based on evidence cited in the Ontario Superior Court’s decision
dismissing the Canadian action (for more information on that litigation, see below under “Canadian Actions”). On
September 17, 2015, Atlantic Power opposed Lead Plaintiff’s motion.
On September 18, 2015, Lead Plaintiff requested a stay of the appellate proceedings in the First Circuit pending
resolution of the District Court’s decision on its Rule 60(b)(2) motion. On September 21, 2015, Atlantic Power opposed
Lead Plaintiff’s request for a stay and tendered to the First Circuit its opposition brief to Lead Plaintiff’s appeal. On
October 5, 2015, the First Circuit granted Lead Plaintiff’s request for a stay in the appellate proceeding pending the
District Court’s decision on the Rule 60(b)(2) motion.
On October 21, 2015, the District Court entered an order denying Lead Plaintiff’s Rule 60(b)(2) motion to
vacate the judgment.
On October 29, 2015, pursuant to Federal Rule of Appellate Procedure 42(b), the parties jointly stipulated to the
voluntary dismissal of the appeal before the First Circuit with prejudice. On November 30, 2015, the First Circuit
ordered that the case be voluntarily dismissed.
Canadian Actions
On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities
class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common
shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of
Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power
common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of
Quebec in the Province of Quebec (the “Canadian Actions”).
On April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the
Ontario Superior Court of Justice in the Province of Ontario.
On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being
issued on behalf of Jacqeline Coffin and Sandra Lowry. As in the U.S. Action, this claim named the Company, Barry E.
Welch and Terrence Ronan as Defendants. The Plaintiffs sought leave to commence an action for statutory
misrepresentation under the Ontario Securities Act and asserted common law claims for misrepresentation.
The Plaintiffs’ motions for leave and certification were heard on May 20-21, 2015.
On July 24, 2015, the Ontario Superior Court of Justice issued a decision denying the Plaintiffs’ motion for
leave and certification. The Superior Court granted leave to reconstitute a claim for debenture holders but required that
there be a debenture holder as plaintiff, that the claim be amended and that the Plaintiffs pay the Defendants partial
indemnity costs of responding to the Plaintiffs’ motion.
40
The Plaintiffs appealed the July 24 decision on leave and certification to the Ontario Court of Appeal.
The appeal was subsequently abandoned by the Plaintiffs, and the Ontario action was dismissed by Order dated
December 2, 2015, the Defendants agreeing not to claim costs from the Plaintiffs.
The proposed Quebec class action was suspended by the Superior Court of Quebec pending the outcome of the
motions for leave and certification of the Ontario action as a class proceeding. Following the result in Ontario, the
petitioner in the Quebec proceedings has agreed in principle with the Defendants to discontinue the Quebec proceedings
without costs. The discontinuance will require the authorization of the Superior Court of Quebec. The parties are
preparing materials to obtain this authorization.
The petitioner in the Quebec proceedings did not estimate the alleged damages of the proposed class. Because
the Quebec proceedings were suspended and then an agreement to discontinue was made in its early stages, Atlantic
Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation, if it were
to continue. If the action were to continue, Atlantic Power intends to defend against it vigorously.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
41
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 permits the
Company to repurchase shares 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 will expire on December
28, 2016 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB.
Under the NCIB, we may 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 are limited to daily purchases of
22,600 common shares per day. During the year ended December 31, 2015, we repurchased 47,300 common shares
under the NCIB at a total cost of $0.1 million and through March 3, 2016, we repurchased a cumulative 575,553
common shares at a total cost of $1.0 million.
The following table presents information regarding repurchases made by the Company of its common shares for
the year ended December 31, 2015.
Repurchase Period
12/17/2015 - 12/31/2015(1)
Total
Total Number of
Shares Purchased
Average Price Paid
Per Share
Total Number of Shares
Dollar Value of Maximum Number
as Part of a Publicly Announced of Shares to be Purchased Under
Purchase Plan
the Plan
47,300 Cdn$
47,300
2.50
47,300 Cdn$
47,300
27,923,337
(1) 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. Under the NCIB, we
may purchase up to a total of 12,139,215 common shares (Cdn$28.0 million based on the Cdn$2.31 closing
share price of our common shares on the TSX on December 31, 2015) and are limited to daily purchases of
22,600 common shares per day. The NCIB will expire on December 28, 2016 or such earlier date as the
Company and/or APPEL complete their respective purchases pursuant to the NCIB.
Market Information and Holders
Our common shares trade on the NYSE under the symbol “AT” and on the TSX under the symbol “ATP”.
The following table sets forth the price ranges of our outstanding common shares, as reported by the NYSE for
the periods indicated:
Period
Quarter ended December 31, 2015
Quarter ended September 30, 2015
Quarter ended June 30, 2015
Quarter ended March 31, 2015
Quarter ended December 31, 2014
Quarter ended September 30, 2014
Quarter ended June 30, 2014
Quarter ended March 31, 2014
High (US$) Low (US$)
1.57
1.83
2.59
2.51
1.91
3.15
2.82
2.11
2.26
3.27
3.34
3.12
2.93
4.15
4.13
3.60
42
The following table sets forth the price ranges of our common shares, as applicable, as reported by the TSX for
the periods indicated:
Period
Quarter ended December 31, 2015
Quarter ended September 30, 2015
Quarter ended June 30, 2015
Quarter ended March 31, 2015
Quarter ended December 31, 2014
Quarter ended September 30, 2014
Quarter ended June 30, 2014
Quarter ended March 31, 2014
High (Cdn$) Low (Cdn$)
2.19
2.46
3.26
3.04
2.14
2.43
3.11
2.41
2.95
4.08
4.10
4.00
3.40
4.44
4.40
3.88
The number of common shares outstanding was approximately 121,624,829 on March 3, 2016.
Dividends
Dividends declared per common share in 2015 and 2014 were as follows (Cdn$):
Month
January
February
March
April
May
June
July
August
September
October
November
December
2015
2014
Amount
$ — $ 0.0333
0.0333
0.0333
0.0333
0.0333
0.0333
0.0333
0.0333
—
—
0.0300
—
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
per share quarterly, with the most recent payment on December 31, 2015. In conjunction with the elimination of the
common share dividend, the Company’s dividend reinvestment plan was terminated.
43
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of December 31, 2015 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
865,601 $
367,246
1,232,847 $
—
—
—
478,000
232,754
710,754
(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(t), Equity compensation plans.
(2) The maximum aggregate number of common shares that may be issued under our Long-Term Incentive Plan upon
redemption of notional shares is 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(t), Equity compensation plans.
Performance Graph
The performance graph below compares the cumulative total shareholder return on our common shares for the
period December 31, 2010, through December 31, 2015, 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, 2010, 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.
44
Comparison of Cumulative Total Return
AT
S&P
S&P / TSX
$
Dec-2010
100.00
100.00
100.00
Dec-2011
$
104.44
102.09
89.41
$
Dec-2012
Dec-2013
Dec-2014
Dec-2015
91.88 $
118.31
97.81
32.07 $
156.21
103.19
27.46 $
177.32
104.34
20.91
179.76
80.53
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, 2015 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, 2015.
Year Ended December 31,
(in millions of U.S. dollars, except as otherwise stated)
Project revenue
Project (loss) income
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(e)
(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
2015(a)(f)
$
2014(a)(b)(f) 2013(a)(b)( c) 2012(b)(c )(f) 2011(c )(d)
93.9
(3.6)
(69.9)
34.3
(38.4)
429.8 $
(31.2)
(116.0)
15.7
(112.8)
489.9 $
(38.9)
(153.2)
(29.0)
(177.4)
473.4 $
45.0
(23.6)
(0.2)
(33.0)
420.2 $
(41.4)
(84.1)
19.5
(62.4)
$
(0.76) $
0.25
(1.37) $
(0.10)
(0.30) $
0.02
(1.10) $
0.13
(0.94)
0.44
(0.51) $
0.09 $
(0.50)
$
1.11
$
$ 1,717.1 $ 2,916.0 $ 3,395.0 $ 4,002.7 $ 3,248.4
$ 1,189.6 $ 1,719.4 $ 1,909.6 $ 2,280.8 $ 1,940.2
(0.97) $
1.10 $
(1.47) $
0.29 $
(0.28) $
0.54 $
(a) Excludes the Wind Projects, which are classified as discontinued operations for the years ended December 31, 2015,
2014 and 2013.
45
(b) Excludes Greeley, which is classified as discontinued operations for the years ended December 31, 2014, 2013 and
2012.
(c) Excludes the Florida Projects, Path 15 and Rollcast, which are classified as discontinued operations for the years
ended December 31, 2013, 2012 and 2011.
(d) The acquisition of the Partnership was completed on November 5, 2011.
(e) Diluted earnings (loss) per share is computed including dilutive potential shares, which include those issuable upon
conversion of convertible debentures and under our long term incentive plan. 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.
(f)
Includes $127.8 million, $106.6 million and $34.9 million of goodwill and long-lived asset impairment for the years
end December 31, 2015, 2014 and 2013, respectively.
46
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 2015 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 2015 Results and Recent Events
Management is focused on the following priorities:
(cid:120) Debt reduction: By strengthening our balance sheet we will improve our financial flexibility and become
more competitive to pursue external growth opportunities.
(cid:120) Overhead cost reduction: Improving our cost structure provides additional flexibility for debt reduction,
external growth and other value-accretive investments.
(cid:120) Fleet optimization: By making capital investments in our existing projects we are able to achieve cash
returns that are higher than what is available in the external markets and at lower risk.
(cid:120) PPA renewals: We will leverage the strength of our operations, diversity and location of our projects to
renew or extend our contracts in a challenging market.
(cid:120) External growth: We will take a creative, disciplined and value-oriented approach to external development
or acquisitions.
In 2015, we made substantial progress in strengthening the Company. Our key achievements in the execution of
our strategy during 2015 were:
(cid:120)
Sale of the Wind Projects – On June 26, 2015, we completed the sale of the Wind Projects for aggregate
cash proceeds of approximately $335 million after transaction fees and recorded a $46.8 million gain on
sale as discussed in more detail in Item 15 – Note 3, Divestments.
(cid:120) Extension of the Morris Energy Service Agreement – On December 22, 2015, we entered into an agreement
with Equistar Chemicals, LP, a subsidiary of LyondellBasell, to modify and extend the Energy Services
Agreement (“ESA”) for our Morris project from November 2023 to December 2034.
(cid:120) Debt repayment – During 2015, we reduced our corporate and project-level debt by approximately $652
million. We achieved this primarily with the $319.9 million redemption of our 9.0% Senior Unsecured
Notes due November 2018 (“9.0% Notes”) with proceeds from the sale of the wind projects, $248.8 million
of project-level debt that was disposed with the sale of the wind projects and $83.2 million of amortization
of our Senior Secured Credit Facility and other non-recourse project-level debt. Additionally, during 2015
we repurchased and cancelled $21.8 million aggregate principal of convertible debentures.
(cid:120) Overhead cost reduction – We have cut our corporate overhead expense from approximately $54 million in
2013 to $32 million for 2015, which represents a cumulative reduction from 2013 of approximately 41%.
We did this by consolidating our offices in Boston, the Chicago area, Toronto, Seattle and Portland into our
new headquarters location in Dedham, Massachusetts, as well as through other cost reductions.
47
(cid:120)
(cid:120)
Improved Credit Rating – Recognizing the considerable amount of debt reduction as well as the reduction
in corporate overhead over the past three years, in October 2015, Moody’s upgraded our corporate family
rating from B2 to B1 and in February 2016, S&P upgraded our corporate credit rating from B to B+.
Investment in our fleet – During 2015 we invested $10.7 million in our fleet for optimization projects and a
total of $22 million since 2013. These investments returned approximately $6 million in cash during 2015.
(cid:120) External growth – In September 2015, Joe Cofelice joined Atlantic Power Corporation as EVP of
Commercial Development to focus on exploring external opportunities.
In 2016, we have continued to focus on the above-discussed priorities. On February 9, 2016, we announced
changes to our capital allocation strategy designed to create value for our shareholders in a tax-efficient manner, while
also improving our financial flexibility and strengthening our balance sheet.
As part of this strategy, we will prioritize allocation of our discretionary capital (after mandatory debt
repayment) to equity and debt repurchases, each under the normal course issuer bid (“NCIB”) implemented in December
2015, with a goal of capturing value arising from price-to-value opportunities in our publicly traded securities. In
addition, we will continue to make high-return investments in our existing projects, as well as potential repowering of
projects linked to extensions of PPAs.
As a result of this redirection of capital to expected higher-return purposes, 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 most recent payment on December 31, 2015.
In conjunction with the elimination of the common share dividend, our dividend reinvestment plan was terminated.
Performance highlights
Project revenue
Project (loss) income
Loss from continuing operations
Income (loss) 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 (loss) per share from discontinued operations—basic and diluted
Loss per share attributable to Atlantic Power Corporation—basic and diluted
Project Adjusted EBITDA(1)
Free Cash Flow(1)
2013
2015
Year Ended December 31,
2014
$ 420.2 $ 489.9 $ 473.4
$ (41.4) $ (38.9) $
45.0
$ (84.1) $ (153.2) $ (23.6)
$
(0.2)
$ (62.4) $ (177.4) $ (33.0)
19.5 $ (29.0) $
0.25
(0.10)
$ (0.76) $ (1.37) $ (0.30)
0.02
$ (0.51) $ (1.47) $ (0.28)
$ 208.9 $ 229.4 $ 209.3
$ (19.8) $ (55.6) $ 108.8
(1) See reconciliation and definition below under Supplementary Non-GAAP Financial Information.
Revenue decreased from $489.9 million in the year ended December 31, 2014 to $420.2 million in the year
ended December 31, 2015, a decrease of 14.2%. The primary drivers of the decrease are as follows:
(cid:120) PPA expiration – a $24.8 million decrease resulting from the PPA expiration at Tunis on December 31,
(cid:120)
2014;
Impact of lower fuel costs – energy revenue pricing at several of our projects is impacted by changes in fuel
cost. Lower fuel prices during 2015 resulted in a $31.4 million decrease in revenue from 2014. These
decreases in revenue are offset by lower fuel expense so the net impact on project income is not material;
(cid:120) Hydrological conditions – a $5.8 million decrease from lower water flows and maintenance outages at our
hydro projects; and
(cid:120) Currency – an approximate $24.5 million impact at our Canadian projects resulting from the weakening of
the Canadian Dollar against the U.S. dollar during 2015. The decrease in revenue due to currency is
48
partially offset by the benefit of lower expenses also from currency at our Canadian projects. Currency had
a net negative impact of $3.1 million to consolidated project income.
Consolidated project loss was $(41.1) million for the year ended December 31, 2015, an increase of
$2.5 million from the prior year. The primary drivers of the increase are as follows:
(cid:120) Revenue – revenue decreased $69.7 million as discussed above; and
(cid:120)
Impairment of goodwill and long-lived assets – goodwill and long–lived asset impairment increased $21.2
million from $106.6 million in 2014 to $127.8 million in 2015.
These increases in project loss were partially offset by increases in project income resulting from:
(cid:120) Fuel expense – fuel expense decreased from $210.4 million in 2014 to $165.1 million in 2015 primarily
due to lower natural gas prices; and
(cid:120) Equity earnings – equity earnings increased from $25.5 million in 2014 to $36.7 million in 2015 due
primarily to higher revenues and lower fuel expenses at our 50% ownership interest in the Orlando project
and lower depreciation at our 17.7% ownership interest in Selkirk, which recorded accelerated depreciation
in 2014 due to the expiration of its PPA in August 2014.
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 64.
Factors 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:
(cid:120) 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 do not occur until year end 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
power purchase agreements could have a material adverse impact on our business, results of operations and
financial condition.”
(cid:120) While approximately 35% of our power generation revenue in 2015 was related to contractual capacity
payments, commodity prices do influence our variable revenues and the cost of fuel. Our PPAs are
generally structured to minimize our risk to fluctuations in commodity prices by passing the cost of fuel
through to the utility and its customers, but some of our projects do have exposure to market power and
fuel prices. See Item 1A. “Risk Factors—Risks Related to Our Business and Our Projects—Our projects
depend on third-party suppliers under fuel supply agreements, and increases in fuel costs may adversely
49
affect the profitability of the projects” and Item 7A. “Quantitative and Qualitative Disclosures About
Market Risk” for additional details about our hedging arrangements.
(cid:120) 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, none of the capacity of the facility is currently 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.
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 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.”
(cid:120) 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 our power purchase
agreements 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.
(cid:120) 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.”
(cid:120) The performance of our projects is impacted by a variety of operational and other factors, including
planned and unplanned outages and maintenance requirements, delays in start-up, sourcing of fuel from
suppliers and wind, water and waste heat levels, 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.”
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.
50
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 $127.8 million, $106.6 million and $34.9 million of goodwill and long-lived asset impairments for
the years ended December 31, 2015, 2014 and 2013, respectively.
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. Our previously reported financial results for the year ended
December 31, 2013 and 2014 have been presented to reflect these changes in operating segments. 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.
51
2015 compared to 2014
The following tables and discussion summarizes our consolidated results of operations and provides an analysis
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 gain
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
Years Ended December 31,
2015
2014
$ change
% chang
e
$ 191.5 $ 236.9 $
149.3
79.4
420.2
165.1
103.5
1.1
110.0
379.7
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)
161.3
91.7
489.9
210.4
109.0
3.7
122.3
445.4
6.8
25.5
8.6
(17.7)
(106.6)
—
(83.4)
(38.9)
37.9
146.7
(38.3)
(0.6)
145.7
(184.6)
(31.4)
(153.2)
(29.0)
(182.2)
(16.4)
(45.4)
(12.0)
(12.3)
(69.7)
(45.3)
(5.5)
(2.6)
(12.3)
(65.7)
8.6
11.2
(8.6)
9.5
(21.2)
2.0
1.5
(2.5)
(8.5)
(39.6)
(22.0)
(2.5)
(72.6)
70.1
1.0
69.1
48.5
117.6
5.4
(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) %
8.8
(2.8)
11.6
(62.4) $ (177.4) $ 115.0
(24.1) %
(64.8) %
$
52
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 investments
Interest expense, net
Impairment
Year Ended December 31, 2015
Un-Allocated Consolidated
East U.S.
West
U.S.
Canada
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
—
3.3
8.6
—
(50.3)
(38.4)
(27.6) $ (10.5) $
11.6
—
—
—
(38.5)
(26.9)
(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.
53
East U.S.
Project income for 2015 increased $30.0 million from 2014 primarily due to:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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, 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:
(cid:120)
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 the 2014 period. This
was partially offset by a $6.2 million decrease in interest expense.
West U.S.
Project income for 2015 increased $35.2 million from 2014 primarily due to:
(cid:120)
(cid:120)
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:
(cid:120)
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:
(cid:120)
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
54
(cid:120)
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:
(cid:120)
(cid:120)
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
55
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.
56
2014 compared to 2013
The following tables and discussion summarize our consolidated results of operations and provide an analysis
Years Ended December 31,
2014
2013
$ change % change
$ 236.9 $ 231.7 $
161.3
91.7
489.9
163.7
78.0
473.4
5.2
(2.4)
13.7
16.5
2.2 %
(1.5) %
17.6 %
3.5 %
210.4
109.0
3.7
122.3
445.4
194.3
130.0
7.2
124.3
455.8
16.1
(21.0)
(3.5)
(2.0)
(10.4)
8.3 %
(16.2) %
(48.6) %
(1.6) %
(2.3) %
6.8
25.5
8.6
(17.7)
(106.6)
—
(83.4)
(38.9)
37.9
146.7
(38.3)
(0.6)
145.7
(184.6)
(31.4)
(153.2)
(29.0)
(182.2)
(16.4)
25.5
25.8
30.4
(19.9)
(34.9)
0.5
27.4
45.0
35.2
104.1
(27.4)
(10.5)
101.4
(56.4)
(32.8)
(23.6)
(0.2)
(23.8)
(3.4)
(18.7)
(0.3)
(21.8)
2.2
(71.7)
(0.5)
(110.8)
(83.9)
(73.3) %
(1.2) %
(71.7) %
(11.1) %
NM
(100.0) %
NM
(186.4) %
2.7
42.6
(10.9)
9.9
44.3
(128.2)
1.4
(129.6)
(28.8)
(158.4)
(13.0)
7.7 %
40.9 %
39.8 %
(94.3) %
43.7 %
NM
(4.3) %
NM
NM
NM
NM
(7.9) %
NM
11.6
(1.0)
$ (177.4) $ (33.0) $ (144.4)
12.6
by reportable 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
Gain on sale of equity investments
Interest expense, net
Impairment
Other income, net
Project (loss) income
Administrative and other expenses (income):
Administration
Interest, net
Foreign exchange gain
Other income, net
Loss from continuing operations before income taxes
Income tax benefit
Loss from continuing operations
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
57
Project income (loss)
$
8.7 $
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
Gain on sale of equity investment
Interest expense, net
Impairment
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
Other (expense) income, net
Year Ended December 31, 2014
East U.S. West U.S.(3) 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
—
3.3
8.6
—
(50.3)
(38.4)
(27.6) $ (10.5) $
11.6
—
—
—
(38.5)
(26.9)
(1.2)
(0.1)
—
—
0.1
(1.2)
(9.5) $
6.8
25.5
8.6
(17.7)
(106.6)
(83.4)
(38.9)
Year Ended December 31, 2013
East U.S.(2) West U.S.(3)(4) Canada
Un-Allocated Consolidated
Corporate(5)
Total(1)
$
76.8 $
49.4
19.9
146.1
48.4 $ 106.5 $
45.6
25.1
119.1
68.9
33.2
208.6
— $
(0.2)
(0.2)
(0.4)
0.1
10.8
7.2
0.5
18.6
50.5
28.7
—
29.0
108.2
85.9
57.1
—
64.7
207.7
—
4.5
30.4
—
(4.1)
—
30.8
41.7 $ 18.1 $
19.2
—
—
(0.2)
—
(1.8)
17.2
—
—
—
(0.1)
—
2.7
2.6
(16.4) $
57.8
33.4
—
30.1
121.3
6.3
21.3
—
(19.6)
(30.8)
(0.4)
(23.2)
236.9
161.3
91.7
489.9
210.4
109.0
3.7
122.3
445.4
231.7
163.7
78.0
473.4
194.3
130.0
7.2
124.3
455.8
25.5
25.8
30.4
(19.9)
(34.9)
0.5
27.4
45.0
Project income (loss)
$
1.6 $
(1) Excludes the Wind Projects, which were sold in June 2015 and classified as discontinued operations.
(2) Excludes the Florida Projects, which were sold in 2013 and are classified as discontinued operations.
(3) Excludes Greeley, which was sold in 2014 and is classified as discontinued operations.
(4) Excludes Path 15, which was sold in 2013 and is classified as discontinued operations.
(5) Excludes Rollcast, which was sold in 2013 and is classified as discontinued operations.
58
East U.S.
Project income for 2014 increased $7.1 million from 2013 primarily due to:
(cid:120)
(cid:120)
(cid:120)
increased project income from Kenilworth of $11.4 million due primarily to a $17.9 million goodwill
impairment charge recorded during the year ended December 31, 2014 as compared to a $30.7 million
goodwill impairment charge recorded during 2013;
increased project income from Orlando of $9.5 million due primarily to $15.3 million in lower fuel costs
than 2013. Orlando operated under an above-market fuel supply agreement that expired in the fourth
quarter of 2013; and
increased project income from Morris of $6.6 million due primarily to a $14.4 million increase in energy
revenues. Energy payments were escalated under the terms of the project’s PPA due to higher natural gas
prices. This increase was offset by higher fuel expenses compared to 2013.
These increases were partially offset by:
(cid:120)
decreased project income from Selkirk of $11.9 million due primarily to lower energy revenue resulting
from lower generation from mild weather conditions, as well as accelerated depreciation resulting from the
expiration of the project’s PPA in August 2014. Selkirk is operating as a 100% merchant facility
subsequent to the expiration of the project’s PPA; and
(cid:120)
decreased project income from Piedmont of $9.2 million due primarily to a negative $9.7 million non-cash
change in the fair value of interest rate swap agreements that are accounted for as derivatives.
Project income for the East U.S. segment excludes the Florida Projects as these projects were sold in April
2013, and are accounted for as a component of discontinued operations. Project loss for the Florida Projects was
$1.1 million for the year ended December 31, 2013.
West U.S.
Project loss for 2014 increased $69.3 million from 2013 primarily due to:
(cid:120)
(cid:120)
decreased project income from Manchief of $52.3 million due primarily to a $50.2 million goodwill
impairment charge recorded during the year ended December 31, 2014; and
decreased project income from Gregory of $32.0 million due to the sale of the project in August 2013,
which resulted in a gain on sale of $31.0 million.
These decreases were partially offset by:
(cid:120)
(cid:120)
increased project income from Naval Station of $3.9 million due primarily to $2.8 million of increased
revenue due primarily to higher generation and energy prices resulting from higher gas prices during the
2014 period: and,
increased project income from Naval Training of $3.6 million due primarily to decreased maintenance
expenses as compared to the comparable 2013 period, during which the project underwent a scheduled
turbine overhaul.
Project income for the West U.S. segment excludes the Path 15 and Greeley projects which are accounted for as
components of discontinued operations. Project income for Path 15 was $2.1 million for the years ended December 31,
2013. Project (loss) income for Greeley was ($0.1) million and $0.6 million for the years ended December 31, 2014 and
2013, respectively.
59
Canada
Project loss for 2014 decreased $28.6 million from 2013 primarily due to:
(cid:120)
(cid:120)
(cid:120)
decreased project income from Williams Lake of $23.0 million due primarily to a $23.7 million goodwill
impairment charge recorded during the year ended December 31, 2014;
decreased project income from Tunis of $12.0 million due primarily to a $14.8 million non-cash goodwill
and long-lived asset impairment charge recorded during the year ended December 31, 2014; and
decreased project income from North Bay of $2.8 million due primarily to a negative $9.7 million non-cash
change in the fair value of interest rate swap agreements that are accounted for as derivatives.
These decreases were partially offset by:
(cid:120)
(cid:120)
increased project income from Nipigon of $6.4 million due primarily to a positive $4.0 million non-cash
change in the fair value of a gas purchase agreement that is accounted for as a derivative, as well as a $2.4
million decrease in maintenance expenses as compared to the 2013 period, during which the project
underwent a scheduled turbine outage. Nipigon also underwent a five-week outage during the third quarter
of 2014 to upgrade its steam generator; and
increased project income from Mamquam of $3.6 million due primarily to decreased maintenance expenses
as compared to the comparable 2013 period, during which the project underwent a scheduled turbine
overhaul.
Un-allocated Corporate
Total project loss decreased $6.9 million from 2013 primarily due to a $3.5 million decrease in development
and administrative costs, as well as administrative reduction initiatives undertaken during the year ended December 31,
2014.
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 increased $2.7 million or 7.7% from 2013 primarily due to a $3.9 million increase in
labor costs primarily due to $6.0 million of employee severance expenses incurred during the third and fourth quarters of
2014 which are expected to result in lower administrative costs on a go-forward basis.
60
Interest, net
Interest expense increased $42.6 million or 40.9% from the comparable 2013 period primarily due to $23.3
million of make-whole premiums paid to redeem the Series A Notes and Series B Notes, 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.
Foreign exchange loss (gain)
Foreign exchange gain increased $10.9 million or 39.8% from the comparable 2013 period primarily due to a
$7.4 million increase in unrealized gain in the revaluation of instruments denominated in Canadian dollars and a $18.4
million decrease in unrealized loss on foreign exchange forward contracts, offset by a $14.9 million decrease in realized
gains on the settlement of foreign currency forward contracts. The U.S. dollar to Canadian dollar exchange rate was 1.16
to 1.06 at December 31, 2014 and 2013, respectively, an increase of 9.4% in 2014 compared to an increase of 6.9% in
2013.
Income tax benefit
Income tax benefit for the year ended December 31, 2014 was $31.4 million. Expected income tax benefit for
the same period, based on the Canadian enacted statutory rate of 26%, was $47.5 million. The primary items impacting
the tax rate for the year ended December 31, 2014 were $40.5 million relating to a change in the valuation allowance,
$33.9 million relating to goodwill impairment and $4.2 million of other permanent differences. These items were
partially offset by $19.2 million relating to operating in higher tax rate jurisdictions, $15.8 million of intra-period
allocations from the wind projects, $10.2 million of capital losses recognized on tax restructuring, $7.4 million relating
to foreign exchange, $5.8 million relating to changes in tax rates and $4.1 million relating to return to provision
adjustments.
Income tax benefit for the year ended December 31, 2013 was $32.8 million. Expected income tax benefit for
the same period, based on the Canadian enacted statutory rate of 26%, was $14.7 million. The primary items impacting
the tax rate for the twelve months ended December 31, 2013 were $23.0 million relating to return to provision
adjustments, $13.6 million relating to goodwill impairment, $12.3 million relating to a change in the valuation
allowance, $3.7 million of dividend withholding and state taxes and $1.5 million of other permanent differences. These
items were partially offset by $30.9 million of intra-period allocations from the wind projects, $18.9 million of treasury
grants, $9.9 million relating to foreign exchange, $5.3 million relating to operating in higher tax rate jurisdictions, $4.4
million related to tax credits and $2.8 million relating to changes in tax rates.
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 megawatt hours.
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.
61
Generation
(in thousands of Net MWh)
Segment
East U.S.(1)
West U.S.(2)
Canada
Total(3)
Year ended December 31,
2015
2014
2013
% change
2015 vs. 2014 2014 vs. 2013
% change
2,628.0 2,671.3 2,617.7
1,835.9 1,639.1 1,662.8
1,889.4 2,088.5 2,064.4
6,353.3 6,398.9 6,344.9
(1.6)%
12.0 %
(9.5)%
(0.7)%
2.0 %
(1.4) %
1.2 %
0.9 %
(1) Excludes the Florida Projects, which were sold in April 2013 and are classified as discontinued operations.
(2) Excludes (i) Delta-Person, which was sold in July 2014; (ii) Gregory, which was sold in August 2013, and
(iii) Greeley, which was sold in March 2014 is designated as discontinued operations.
(3) Excludes the Wind Projects, which were sold in June 2015 and are classified as discontinued operations.
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:
(cid:120)
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:
(cid:120)
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.
Year ended December 31, 2014 compared with Year ended December 31, 2013
Aggregate power generation for 2014 increased 0.9% from 2013 primarily due to:
(cid:120)
increased generation in the East U.S. segment due to a 123.5 net MWh increase in generation at Piedmont,
which achieved commercial operations in April 2013, resulting in an additional quarter of generation in
2014, and a 45.4 MWh increase in generation at Orlando, which was due to the expiration of an
unfavorable natural gas contract in the comparable 2013 period, partially offset by a 151.6 net MWh
decrease at Selkirk due to mild summer weather, resulting in lower dispatch for the 2014 period; and
(cid:120)
increased generation in the Canada segment due to a 43.2 MWh increase in generation at Mamquam due to
an extended outage in September 2013.
These increases were partially offset by:
(cid:120)
decreased generation in the West U.S. segment due to a 156.8 MWh decrease in generation at Manchief
due to lower dispatch, partially offset by a 139.9 MWh increase at Frederickson due to lower hydro energy
supply and higher market pricing.
62
Availability
Segment
East U.S.(1)
West U.S. (2)
Canada
Weighted average(3)
Year ended December 31,
% change
% change
2015
2014
2013
2015 vs. 2014
2014 vs. 2013
96.9 % 93.3 % 94.7 %
92.8 % 92.4 % 95.5 %
93.9 % 93.1 % 92.8 %
95.2 % 93.0 % 94.4 %
3.9 %
0.4 %
0.9 %
2.4 %
(1.5) %
(3.2) %
0.3 %
(1.5) %
(1) Excludes the Florida Projects, which were sold in April 2013 and are classified as discontinued operations.
(2) Excludes (i) Delta-Person, which was sold in July 2014; (ii) Gregory, which was sold in August 2013, and
(iii) Greeley, which was sold in March 2014 and is classified as discontinued operations.
(3) Excludes the Wind Projects, which were sold in June 2015 and are classified as discontinued operations.
Weighted average availability for 2015 increased to 95.2% from 93.0% in 2014 primarily due to:
(cid:120)
(cid:120)
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:
(cid:120)
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, offset by increased availability at Nipigon, which had extensive outages in the 2014
period.
Year ended December 31, 2014 compared with Year ended December 31, 2013
Weighted average availability for 2014 decreased to 93.0% from 94.4% from 2013 primarily due to:
(cid:120)
(cid:120)
decreased availability in the East U.S. segment resulting from decreased availability at Chambers and
Orlando, each of which experienced planned maintenance outages in the year ended December 31, 2014;
and
decreased availability in the West U.S. segment resulting from decreased availability at North Island and
Naval Station, which had unbudgeted repairs and extended outages in the year ended December 31, 2014.
These decreases were partially offset by:
(cid:120)
increased availability in the Canada segment resulting from increased availability at Moresby Lake, Morris
and Mamquam due to their scheduled outage occurrences in the year ended December 31, 2013.
63
Supplementary Non-GAAP Financial Information
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 use Project Adjusted
EBITDA to provide comparative information about project performance without considering how projects are
capitalized or whether they contain derivative contracts that are required to be recorded at fair value. A reconciliation of
Project Adjusted EBITDA to project income (loss) is provided under “Project Adjusted EBITDA” below and a
reconciliation of Project Adjusted EBITDA by segment to project income (loss) by segment is provided in Note 22 to the
consolidated financial statements of this Annual Report on Form 10-K. Project Adjusted EBITDA for our equity
investments in unconsolidated affiliates is presented on a proportionately consolidated basis in the table below. Investors
are cautioned that we may calculate this measure in a manner that is different from other companies.
Year ended December 31,
2014
2013
2015
$ change
2015
2014
Project Adjusted EBITDA by segment(4)
East U.S.(1)
West U.S.(2)
Canada
Un-Allocated Corporate(3)
Total
Reconciliation to project (loss) income
Depreciation and amortization
Interest expense, net
Change in the fair value of derivative instruments
Impairment and other expense
Project (loss) income
$ 104.8 $ 106.4 $ 105.2 $ (1.6) $
46.9
59.7
(2.5)
208.9
54.2
76.3
(7.5)
229.4
57.1
65.6
(18.6)
209.3
(7.3)
(16.6)
5.0
(20.5)
1.2
(2.9)
10.7
11.1
20.1
130.1
9.8
(15.4)
125.8
(5.6)
1.5
18.2
89.9
$ (41.4) $ (38.9) $ 45.0 $ (2.5) $ (83.9)
(25.8)
(10.7)
(9.2)
27.7
155.9
20.5
(6.2)
98.1
161.5
19.0
(24.4)
8.2
(1) Excludes the Florida Projects, which were sold in April 2013 and are classified as discontinued operations.
(2) Excludes Path 15, which was sold in April 2013, and Greeley, which was sold in March 2014, and are classified as
discontinued operations.
(3) Excludes Rollcast, which was sold in November 2013 and is classified as discontinued operations.
(4) Excludes the Wind Projects, which were sold in June 2015 and are classified as discontinued operations.
East U.S.
The following table summarizes Project Adjusted EBITDA for our East U.S. segment for the periods indicated:
East U.S.
Project Adjusted EBITDA
$ 104.8 $ 106.4 $ 105.2
(2) %
1 %
Year ended December 31,
2015
2014
2013
% change
2015 vs. 2014
% change
2014 vs. 2013
64
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:
(cid:120)
$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
(cid:120)
$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:
(cid:120)
(cid:120)
$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.
Year ended December 31, 2014 compared with Year ended December 31, 2013
Project Adjusted EBITDA for 2014 increased $1.2 million or 1% from 2013 primarily due to increases in
Project Adjusted EBITDA of:
(cid:120)
(cid:120)
(cid:120)
$6.4 million at Morris due primarily to a $14.4 million increase in energy revenues. Energy payments were
escalated under the terms of the project’s PPA due to higher natural gas prices. This increase was partially
offset by higher fuel expenses compared to the 2013 period;
$6.4 million at Orlando primarily attributable to increased generation and higher energy revenues due to a
change in revenue escalators in the amended off-taker contract as well as lower fuel expenses than the
comparable 2013 period. Orlando operated under an above-market fuel agreement that expired in the fourth
quarter of 2013; and
$4.4 million at Piedmont due primarily to $7.0 million of increased revenues offset by $3.5 million of
increased fuel expense resulting from a full year of operation in 2014 as compared to the eight months in
2013 when it became commercially operational in April 2013.
These increases were partially offset by decreases in Project Adjusted EBITDA of:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
$10.4 million at Selkirk primarily attributable to lower energy revenue resulting from decreased generation
due to lower dispatch from mild weather conditions during the 2014 period and expiration of its PPA in
August 2014;
$2.0 million at Chambers due to increased maintenance costs, partially offset by higher energy revenues
resulting from increased dispatch than in the comparable 2013 period;
$1.4 million at Kenilworth primarily attributable to lower steam revenue resulting from lower steam prices
in the comparable 2013 period; and
$1.3 million at Cadillac due to increased maintenance expenses resulting from a scheduled turbine
maintenance outage in the 2014 period.
Project Adjusted EBITDA for the East U.S. segment excludes the Florida Projects, as these projects were sold
in April 2013, and are accounted for as a component of discontinued operations. Project Adjusted EBITDA for the
Florida Projects was $27.2 million for the year ended December 31, 2013.
65
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
2015 vs 2014 2014 vs 2013
% change
2013
2014
2015
West U.S.
Project Adjusted EBITDA
$ 46.9 $ 54.2 $ 57.1
(13)%
(5)%
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:
(cid:120)
$9.2 million at Manchief attributable to higher project operations and maintenance cost due to a
maintenance overhaul during the second quarter of 2015; and
(cid:120)
$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:
(cid:120)
$3.0 million at North Island, which underwent a turbine maintenance outage in the first quarter in 2014.
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.
Year ended December 31, 2014 compared with Year ended December 31, 2013
Project Adjusted EBITDA for 2014 decreased by $2.9 million or (5)% from 2013 primarily due to decreases in
Project Adjusted EBITDA of:
(cid:120)
$2.2 million at Oxnard attributable to higher maintenance costs due to scheduled turbine maintenance than
in the comparable 2013 period; and
(cid:120)
$1.9 million at Manchief attributable to lower dispatch than in the comparable 2013 period.
These decreases were partially offset by increases in Project Adjusted EBITDA of:
(cid:120)
$3.6 million at Naval Training Center, which underwent a scheduled turbine maintenance outage in the
comparable 2013 period; and
(cid:120)
$2.2 million at Gregory, which was sold in August 2013.
Project Adjusted EBITDA for the West U.S. segment excludes the Path 15 and Greeley projects, which are
accounted for as components of discontinued operations. Project Adjusted EBITDA for Path 15 was $9.0 million for the
year ended December 31, 2013. Project Adjusted EBITDA for Greeley was $0.1 million and $1.5 million for the years
ended December 31, 2014 and 2013, respectively.
66
Canada
The following table summarizes Project Adjusted EBITDA for our Canada segment for the periods indicated:
Canada
Project Adjusted EBITDA
Year Ended December 31,
2015
2014
2013
% change
2015 vs. 2014
% change
2014 vs. 2013
$ 59.7 $ 76.3 $ 65.6
(22) %
16 %
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:
(cid:120)
(cid:120)
(cid:120)
$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 escalation 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:
(cid:120)
$3.1 million at Nipigon, which had an outage to upgrade its steam generator in September 2014.
Year ended December 31, 2014 compared with Year ended December 31, 2013
Project Adjusted EBITDA for 2014 increased by $10.7 million or 16% from 2013 primarily due to increases in
Project Adjusted EBITDA of:
(cid:120)
(cid:120)
(cid:120)
$3.5 million at Mamquam due to $0.9 million in higher revenues resulting from increased water flows as
well as a $2.5 million decrease in maintenance expense compared to the 2013 period, during which the
project underwent turbine maintenance;
$2.2 million at Kapuskasing primarily attributable to a steam turbine maintenance outage that occurred in
the comparable 2013 period; and
$2.0 million at North Bay and $1.9 million at Nipigon primarily attributable to lower maintenance costs
and increased energy revenue resulting from higher waste heat generation than the comparable 2013
period.
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
2015
2014
Year Ended December 31,
% change
2015 vs. 2014
2013
% change
2014 vs. 2013
$ (2.5) $ (7.5) $ (18.6)
(67) %
(60)%
67
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.
Year ended December 31, 2014 compared with Year ended December 31, 2013
Project Adjusted EBITDA for 2014 increased by $11.1 million or 60% from the comparable 2013 period
primarily due to decreased development costs and decreased administrative costs related to a reduction in workforce
during the year ended December 31, 2014.
Free Cash Flow
A key measure we use to evaluate the results of our business is Free Cash Flow. Free Cash Flow is not a
measure recognized under GAAP, does not have a standardized meaning prescribed by GAAP and therefore may not be
comparable to similar measures presented by other issuers. We believe Free Cash Flow is a relevant supplemental
measure of our ability to pay for additional debt reduction, fund internal or external growth, or many other allocations of
any available cash. A reconciliation of Free Cash Flow to cash flows from operating activities, the most directly
comparable GAAP measure, is set out in the table below.
The primary factor influencing Free Cash Flow is cash distributions received from projects. These distributions
are generally funded from Project Adjusted EBITDA generated by the projects, reduced by project-level debt service,
capital expenditures, dividends paid on preferred shares of a subsidiary company, distributions to noncontrolling
interests and adjusted for changes in project-level working capital and cash reserves. For discussion of changes in the
components of Free Cash Flow, refer to Refer to Item 7— Management’s Discussion and Analysis of Financial
Condition — Consolidated Cash Flow.
The table below presents our calculation of Free Cash Flow for the years ended December 31, 2015, 2014, and
2013, and the reconciliation to cash flows from operating activities, the most directly comparable GAAP measure:
Cash flows from operating activities
Term loan facility repayments(1)
Project-level debt repayments
Purchases of property, plant and equipment(2)
Distributions to noncontrolling interests(3)
Dividends on preferred shares of a subsidiary company
Free Cash Flow(4)
Year Ended December 31,
2015
2014
2013
$ 87.4 $ 65.0 $ 152.4
—
(58.4)
(15.6)
(26.2)
(6.5)
(13.4)
(8.9)
(11.0)
(12.6)
(11.6)
$ (19.8) $ (55.6) $ 108.8
(68.3)
(15.1)
(11.3)
(3.7)
(8.8)
(1)
Includes mandatory 1% annual amortization and 50% excess cash flow repayments by the Partnership under the
Senior Secured Credit Facilities.
(2) Excludes construction costs related to our Canadian Hills and Piedmont projects in 2014 and our Canadian Hills,
Piedmont and Meadow Creek projects in 2013.
(3) Distributions to noncontrolling interests include distributions to the tax equity investors at Canadian Hills and to the
other 50% owner of Rockland.
(4) Free Cash Flow is not a recognized measure under GAAP and does not have any standardized meaning prescribed
by GAAP. Therefore, this measure may not be comparable to similar measures presented by other companies. See
“Supplementary Non-GAAP Financial Information” above. This table should be read together with the below table
under “Consolidated Cash Flows” that sets forth Net cash provided by investing activities and Net cash used in
financing activities for the years ended December 31, 2015, 2014, and 2013.
68
Consolidated Cash Flow
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.
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:
(cid:120) 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
(cid:120) 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:
(cid:120)
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
Cash flow from investing activities includes changes in restricted cash. Restricted cash fluctuates from period to
period in part because certain of our non-recourse project-level financing arrangements require all operating cash flow
from the project to be deposited in restricted accounts and then released at the time that principal payments are made and
project-level debt service coverage ratios are met. As a result, the timing of principal payments on certain of our
project-level debt causes significant fluctuations in restricted cash balances, which typically benefits investing cash flow
in the second and fourth quarters of the year and decreases investing cash flow in the first and third quarters of the year.
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:
(cid:120) Asset sale proceeds – an increase of $326.3 million for cash received for the sale of the Wind Projects
and the Frontier Solar Development project; and
69
(cid:120) 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:
(cid:120) 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;
(cid:120) 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;
(cid:120) 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;
(cid:120) 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;
(cid:120) 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
(cid:120) 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.
2014 compared to 2013
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
$
2014
65.0 $
68.7
(182.4)
Change
2013
152.4 $
147.1
(207.6)
(87.4)
(78.4)
25.2
For the year ended December 31, 2014, the net decrease in cash flows provided from operating activities of
$87.4 million was primarily the result of the following:
(cid:120) 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, the Curtis Palmer
Notes and the repurchase of $140.1 million of our 9.0% Notes; and
(cid:120) Changes in working capital – in 2014, there was a $65.7 million decrease in cash outflows for working
capital. The decrease in cash flows from working capital was primarily due to a $39.4 million decrease
70
in working capital from the 2013 collection of security deposits related to our completed Piedmont,
Canadian Hills and Meadow Creek construction projects.
Investing Activities
For the year ended December 31, 2014, the net decrease in cash flows provided by investing activities of $78.4
million was primarily the result of the following:
(cid:120) Treasury grant proceeds – in 2013, we received $103.2 million of treasury grant proceeds for the
Meadow Creek and Piedmont projects. In 2014, we did not receive any treasury grant proceeds; and
(cid:120) Asset sale proceeds – a decrease of $173.1 million for cash received for asset sales. In 2013, we
received $182.6 million for sale of the Florida Projects, Path 15 and Gregory as compared to $9.5
million received for the sale of Delta-Person and Greeley in 2014.
These decreases were partially offset by increases in net cash used in investing activities primarily the result of
the following:
(cid:120) 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; and
(cid:120) Construction and purchases of property, plant and equipment – a decrease of $31.4 million primarily
due to costs incurred at Piedmont and Canadian Hills, which completed construction and achieved
commercial operations in 2013.
Financing Activities
For the year ended December 31, 2014, the net decrease in cash flows used in financing activities of $25.2
million was primarily the result of the following:
(cid:120) Repayment of corporate and project-level debt – our debt repayment increased to $639.8 million in
2014 from $118.8 million in 2013. 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 2013 repayments included $89.7 million of project-level debt
repayments at Piedmont and Meadow Creek primarily with proceeds received from treasury grants;
(cid:120) Repayment of revolving credit facility – in 2013, we repaid the outstanding $67.0 million of
borrowings under our revolving credit facilities. No borrowings or repayments were made under our
revolving credit facilities in 2014;
(cid:120) Convertible debenture repayments – in 2014, we repaid our $43.0 million 6.5% Debentures due
October 2014 with cash on hand. In 2013, no repayments were made on our convertible debentures;
and
(cid:120) Deferred financing costs – cash paid for deferred financing costs decreased $36.2 million from 2013.
We incurred the $39.0 million of deferred financing costs in connection with the issuance of our
Senior Secured Credit Facilities in February 2014.
These decreases were partially offset by increases in net cash used in investing activities primarily the
result of the following:
(cid:120) 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 as compared to $20.8
million of proceeds of from the issuance of project-level debt in 2013;
(cid:120) Dividends paid to common shareholders – dividends paid to our common shareholders decreased
$30.2 million from 2013 due to a dividend reduction from Cdn$1.15 to Cdn$0.40 per share on an
71
annual basis in February of 2013 and then from Cdn$0.40 to Cdn$0.12 per share on an annual basis in
the third quarter of 2014; and
(cid:120) Proceeds from noncontrolling interests – in 2013, we received $44.6 million in proceeds for the sale of
our remaining tax equity at Canadian Hills.
Liquidity and Capital Resources
December 31,
Cash and cash equivalents
Restricted cash
Total
Revolving credit facility availability
Total liquidity
2014
$
2015
72.4 $ 106.0
22.5
15.2
128.5
87.6
104.3
106.0
$ 193.6 $ 232.8
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 $73 million in our portfolio in the form of project capital expenditures and
maintenance expenses in 2016. 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 2016 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.
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$0.03 per share
quarterly, with the most recent payment on December 31, 2015. In conjunction with the elimination of the common
share dividend, our dividend reinvestment plan was terminated.
With the additional liquidity provided by this action, we will prioritize allocation of our discretionary capital
(after mandatory debt repayment) to equity and debt repurchases, each under the normal course issuer bid implemented
in December 2015, with a goal of capturing price-to-value opportunities in our publicly traded securities. In addition, we
will continue to pursue external growth opportunities and make high-return investments in our existing projects, as well
as potential repowering projects linked to extensions of PPAs.
Normal Course Issuer Bid
On December 17, 2015, our Board of Directors approved an NCIB for each series of our convertible unsecured
subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred
Equity Ltd (“APPEL”), our wholly-owned subsidiary. Under the NCIB, our broker may purchase up to 10% of the
public float of our convertible debentures and common shares and up to 5% of the amount issued and outstanding of
APPEL’s preferred shares, determined as of December 17, 2015, up to the following limits:
72
Convertible Debenture
Convertible Debenture
Convertible Debenture
Convertible Debenture
Common Shares
Series 1 Preferred Shares
Series 2 Preferred Shares
Series 3 Preferred Shares
Maturity
Date
March 2017
June 2017
June 2019
Interest
Rates
Limit on Purchase
(Principal Amount)
Total Limit
6.25 % Cdn$
5.60 % Cdn$
5.75 %
6,717,300
7,583,900
11,700,000
8,995,000
December 2019
6.00 % Cdn$
Limit on Purchase
(Number of Shares)
Total Limit (1)
12,139,215
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 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 was commenced on December 29, 2015 and will expire on December
28, 2016 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB.
During the year ended December 31, 2015, we repurchased 47,300 common shares under the NCIB at a total cost of
$0.1 million and through March 3, 2016, we repurchased a cumulative 575,553 common shares at a total cost of $1.0
million.
Corporate Debt Service Obligations
The following table summarizes the maturities of our corporate debt at December 31, 2015:
Maturity
Date
Interest
Rates
Remaining
Principal
Repayments 2016
2017
2018
2019
2020 Thereafter
Senior Secured Term Loan
Facility(1)
Atlantic Power Income LP Note
Convertible Debenture
Convertible Debenture
Convertible Debenture
Convertible Debenture
Total Corporate Debt
February 2021 4.75 % - 5.90 % $
June 2036
March 2017
June 2017
June 2019
5.95 %
6.25 %
5.60 %
5.75 %
December 2019 6.00 %
473.2 $ 4.7 $
151.7
48.6
54.8
117.0
65.0
—
—
—
—
—
—
48.6
54.8
—
—
—
—
—
—
—
—
—
—
117.0
65.0
—
—
—
—
—
4.7 $ 4.7 $
4.6 $ 4.5 $
$
910.3 $ 4.7 $ 108.1 $ 4.7 $ 186.6 $ 4.5 $
450.0
151.7
—
—
—
—
601.7
(1)
In addition to the annual principal payments described herein, the Credit Agreement requires payment of 50% of the
excess cash flow of the Partnership and its subsidiaries be used for debt repayment.
Senior Secured Credit Facilities
On February 24, 2014, the Partnership, our wholly-owned indirect subsidiary, entered into the a new senior
secured term loan facility (the “Term Loan Facility”), comprising $600 million in aggregate principal amount, and a new
senior secured revolving credit facility (the “Revolving Credit Facility”) with a capacity of $210 million (collectively,
the “Senior Secured Credit Facilities”). Borrowings under the Senior Secured 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, each as defined in the credit agreement governing the Senior Secured Credit Facilities (the “Credit
Agreement”), as applicable, plus an applicable margin between 2.75% and 3.75% that varies depending on whether the
loan is a Eurodollar Rate Loan, Base Rate Loan, or Canadian Prime Rate Loan. The applicable margin for term loans
73
bearing interest at the Adjusted Eurodollar Rate and the Base Rate is 3.75% and 2.75%, respectively (3.75% at
December 31, 2015). The Adjusted Eurodollar Rate cannot be less than 1.00% (1.00% at December 31, 2015).
The Term Loan Facility matures on February 24, 2021. The revolving commitments under the Revolving Credit
Facility terminate on February 24, 2018. Letters of credit are available to be issued under the revolving commitments
until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. The
Partnership is required to pay a commitment fee with respect to the commitments under the Revolving Credit Facility
equal to 0.75% times the average of the daily difference between the revolving commitments and all outstanding
revolving loans (excluding swing line loans) plus amounts available to be drawn under letters of credit and all
outstanding reimbursement obligations with respect to drawn letters of credit.
The Senior Secured Credit Facilities are secured by a pledge of the equity interests in the Partnership and its
subsidiaries, guaranties from the Partnership subsidiary guarantors and a limited recourse guaranty from the entity that
holds all of the Partnership equity, a pledge of certain material contracts and certain mortgages over material real estate
rights, an assignment of all revenues, funds and accounts of the Partnership and its subsidiaries (subject to certain
exceptions), and certain other assets. The Senior Secured Credit Facilities are not otherwise guaranteed or secured by us
or any of our subsidiaries (other than the Partnership subsidiary guarantors). The Senior Secured Credit Facilities also
have 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 debt service reserve requirement was funded with a $15.8 million
letter of credit.
The Partnership’s existing Cdn$210 million aggregate principal amount of 5.95% Medium Term Notes due
June 23, 2036 (the “MTNs”) prohibit the Partnership (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, the Partnership granted an
equal and ratable security interest in the collateral package securing the Senior Secured Credit Facilities 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 covenants include a requirement that the Partnership and its subsidiaries maintain a Leverage Ratio (as defined in
the Credit Agreement) ranging from 5.25:1.00 in 2014 to 4.00:1.00 in 2021, and an Interest Coverage Ratio (as defined
in the Credit Agreement) ranging from 2.50:1.00 in 2014 to 3.25:1.00 in 2021. In addition, the Credit Agreement
includes 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.
Under the Credit Agreement, if a change of control (as defined in the Credit Agreement) occurs, unless the
Partnership elects to make a voluntary prepayment of the term loans under the Senior Secured Credit Facilities, it will be
required to offer each electing lender to prepay such lender’s term loans under the Senior Secured Credit Facilities at a
price equal to 101% of par. In addition, in the event that the Partnership elects to repay, prepay or refinance 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 or refinanced.
The Credit Agreement contains a mandatory amortization feature and customary mandatory prepayment
provisions, including: (i) from proceeds of assets sales, insurance proceeds, and incurrence of indebtedness, in each case
subject to applicable thresholds and customary carve-outs; and (ii) the payment of 50% of the excess cash flow, as
defined in the Credit Agreement, of the Partnership and its subsidiaries.
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 the Partnership and its
74
subsidiaries, bankruptcy, material judgments rendered against the Partnership or certain of its subsidiaries, certain
ERISA or regulatory events, a change of control of the Partnership, or defaults under certain guaranties and collateral
documents securing the Senior Secured 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, 2015. 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.
Non-Recourse Debt
The range of interest rates presented represents the rates in effect at December 31, 2015. 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 2016
2017
2018
2019 2020
Thereafter
January 2019
August 2018
August 2025
3.40 %
5.16 %
6.17 %
$
19.5 $ 6.0 $ 6.3 $ 6.5 $ 0.7 $
2.4
59.0
3.0
29.5
54.2
3.0
—
3.1
2.4
2.5
— $
—
3.1
—
—
14.8
December 2019 and 2023 4.50 % - 5.00 %
108.0
10.9
11.7
63.7
3.8
3.1
14.8
43.0
0.1
—
—
5.2
7.8
29.9
43.0
0.1
—
—
5.2
7.8
29.9
$
151.0 $ 11.0 $ 11.7 $ 63.7 $ 9.0 $ 10.9 $
44.7
Consolidated Projects:
Epsilon Power Partners
Piedmont
Cadillac
Total Consolidated
Projects
Equity Method
Projects:
Chambers(1)
Total Equity Method
Projects
Total Project-Level
Debt
(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.
75
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 $8.8 million and $11.6 million on Series 1 Shares,
Series 2 Shares and Series 3 Shares for the years ended December 31, 2015 and 2014, respectively.
Capital and Maintenance Expenditures
Capital expenditures and maintenance expenses for the projects are generally paid at the project level using
project cash flows and project reserves. Therefore, the distributions that we receive from the projects are made net of
capital expenditures needed at the projects. The operating projects which we own consist of large capital assets that have
established commercial operations. On-going capital expenditures for assets of this nature are generally not significant
because most major expenditures relate to planned repairs and maintenance and are expensed when incurred.
We expect to reinvest approximately $73 million in 2016 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 2016 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 $67.0 million of project capital expenditures and maintenance expenses for the year
ended December 31, 2015. In all cases, scheduled maintenance outages during the year ended December 31, 2015
occurred at such times that did not adversely impact the facilities’ availability requirements under their respective PPAs.
Restricted Cash
At December 31, 2015, restricted cash totaled $15.2 million as compared to $22.5 million as of December 31,
2014.
76
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual obligations as of December 31, 2015:
Less than
Payment Due by Period
Long-term debt including estimated interest(1)(2)
Operating leases
Operations and maintenance commitments
Fuel purchase and transportation obligations
Other liabilities
Total contractual obligations
1 year
$
1-3 Years 4-5 Years Thereafter Total
66.6 $ 275.1 $ 255.9 $
1.1
0.6
0.8
0.4
35.2
54.0
—
1.1
0.2
0.8
20.8
—
$ 122.7 $ 312.2 $ 277.7 $
758.8 $ 1,356.4
1.9
2.6
130.8
1.9
781.0 $ 1,493.6
—
0.6
20.8
0.8
(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, 2015 was 2.9% to 6.2%.
(2)
Includes the mandatory amortization payments and an estimate of the 50% excess cash flow payments, as defined in
the Credit Agreement, of the Senior Secured Credit Facilities.
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.
In connection with the Purchase Agreement for the sale of the Wind Projects, on March 31, 2015, we entered
into a guaranty agreement (the “Guaranty Agreement”), under which we agreed to guarantee the full and prompt
payment of all payment obligations of APT under the Purchase Agreement as and when they shall become due. APT
and TerraForm have agreed to utilize the representation and warranty insurance for coverage of certain indemnification
obligations, subject to a cap and certain exclusion.
Off-Balance Sheet Arrangements
As of December 31, 2015, 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.
77
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.
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
78
is less than the carrying value for our reporting units, we have performed the two-step quantitative test for the years
ended December 31, 2015 and 2014.
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.
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 $134.5 million at December 31, 2015 and is allocated among seven of our reporting
units, of which two are included in the East U.S. segment ($47.9 million at December 31, 2015) and five are included in
the Canada segment ($86.6 million at December 31, 2015).
In the fourth quarter of 2015, we performed our annual goodwill impairment test as of November 30, 2015. Of
the total reporting units with goodwill recorded, only Morris ($3.3 million of goodwill at December 31, 2015), Nipigon
($3.6 million of goodwill at December 31, 2015) and Mamquam ($64.4 million of goodwill at December 31, 2015)
passed step 1 of the two-step test. The total fair value of these reporting units exceeded their carrying value by
approximately $118.0 million or 37%. The Williams Lake, Calstock, Curtis Palmer, North Bay, Kapuskasing and
Moresby Lake reporting units all failed step 1 of the two-step test.
79
Because these 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 each of the reporting units’ 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 Williams Lake and Calstock asset groups (Canada segment) failed the recoverability test. For these asset
groups, we estimated their fair value utilizing an income approach based on market participant assumptions. These
assumptions include estimated cash flows from both contracted and uncontracted periods over the remaining useful lives
of the Williams Lake and Calstock asset groups. We determined that the carrying value exceeded the fair value at both
asset groups and recorded an impairment of $74.1 million and $2.5 million to the property, plant and equipment of the
Williams Lake and Calstock asset groups, respectively, for the year ended December 31, 2015.
Subsequent to recording long-lived asset impairments, we completed our annual goodwill impairment
assessment. For each of the reporting units that failed step 1 of the two-step test, we performed a step 2 analysis. As a
result of this analysis, we recorded a $35.6 million full impairment at the Williams Lake reporting unit, a $13.7 million
partial impairment at the Curtis Palmer reporting unit and a $1.9 million full impairment at the Calstock reporting unit in
the year ended December 31, 2015. At the time of their acquisition in November 2011, the fair value of the assets
acquired and liabilities assumed for the Williams Lake, Curtis Palmer and Calstock 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 2011and 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. 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 fourth quarter of 2015 and not
earlier in the fiscal year because we did not identify any triggering events that would have required an event-driven
impairment assessment. The triggering event for testing long-lived assets was identified through our annual test of
goodwill. While declining oil prices over the past year have affected long-term power prices, the continued depressed
price of oil and the long-term outlook for sustained low oil prices in the fourth quarter of 2015 had the most significant
impact to the key inputs to our long-term forecasted cash flow models.
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
80
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.
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, 2015, we have recorded a valuation
allowance of $175.2 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.
Recent Accounting Developments
Adopted
In April 2014, the FASB issued changes to reporting discontinued operations and disclosures of disposals of
components of an entity. These changes require a disposal of a component to meet a higher threshold in order to be
reported as a discontinued operation in an entity’s financial statements. The threshold is defined as a strategic shift that
has, or will have, a major effect on an entity’s operations and financial results such as a disposal of a major geographical
area or a major line of business. Additionally, the following two criteria have been removed from consideration of
whether a component meets the requirements for discontinued operations presentation: (i) the operations and cash flows
of a disposal component have been or will be eliminated from the ongoing operations of an entity as a result of the
disposal transaction, and (ii) an entity will not have any significant continuing involvement in the operations of the
disposal component after the disposal transaction. Furthermore, equity method investments now may qualify for
discontinued operations presentation. These changes also require expanded disclosures for all disposals of components
of an entity, whether or not the threshold for reporting as a discontinued operation is met, related to profit or loss
information and/or asset and liability information of the component. These changes became effective on January 1, 2015
and were applied to the sale of the Wind Projects in June 2015.
In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating
loss carryforward, a similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an
unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax
loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to
settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the
81
applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to
settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized
tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating
loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no
explicit guidance existed. These changes became effective for us on January 1, 2014 and did not have a material impact
on the consolidated financial statements.
In March 2013, the FASB issued changes to a parent entity’s accounting for the cumulative translation
adjustment upon derecognition of certain subsidiaries or groups of assets within a foreign entity or of an investment in a
foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from
accumulated other comprehensive income (loss) into net income (loss) in the following circumstances: (i) a parent entity
ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity if
the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the
subsidiary or group of assets had resided; (ii) a partial sale of an equity method investment that is a foreign entity; (iii) a
partial sale of an equity method investment that is not a foreign entity whereby the partial sale represents a complete or
substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an
investment in a foreign entity. These changes became effective for us on January 1, 2014 and had no impact on the
consolidated financial statements.
In February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several
liability arrangements. These changes require an entity to measure such obligations for which the total amount of the
obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its
arrangement among its co- obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its
co-obligors. An entity will also be required to disclose the nature and amount of the obligation as well as other
information about those obligations. Examples of obligations subject to these requirements are debt arrangements and
settled litigation and judicial rulings. These changes became effective for us on January 1, 2014 and had no impact on
the consolidated financial statements.
On January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of
accumulated other comprehensive income. These changes require an entity to report the effect of significant
reclassifications out of accumulated other comprehensive income on the respective line items in net income if the
amount being reclassified is required to be reclassified in its entirety to net income. For other amounts that are not
required to be reclassified in their entirety to net income in the same reporting period, an entity is required to
cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be
applied to each component of accumulated other comprehensive income. Other than the additional disclosure
requirements, the adoption of these changes had no impact on the consolidated financial statements.
On January 1, 2013, we adopted changes issued by the FASB to the testing of indefinite-lived intangible assets
for impairment, similar to the goodwill changes issued in September 2011. These changes provide 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 an indefinite-lived intangible asset 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 an entity elects to
perform a qualitative assessment and determines that an impairment is more likely than not, the entity is then required to
perform the existing two-step quantitative impairment test, otherwise no further analysis is required. An entity also may
elect not to perform the qualitative assessment and, instead, proceed directly to the two-step quantitative impairment test.
The adoption of these changes had no impact on the consolidated financial statements.
In July 2012, the Financial Accounting Standards Board (“FASB”) issued changes to the testing of
indefinite-lived intangible assets for impairment, similar to the goodwill changes issued in September 2011. These
changes provide 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 an
indefinite-lived intangible asset 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
82
relevant entity-specific events. If an entity elects to perform a qualitative assessment and determines that an impairment
is more likely than not, the entity is then required to perform the existing two-step quantitative impairment test,
otherwise no further analysis is required. An entity also may elect not to perform the qualitative assessment and, instead,
proceed directly to the two-step quantitative impairment test. These changes became effective for us for any
indefinite-lived intangible asset impairment test performed on January 1, 2013 or later. The adoption of these changes
did not impact the consolidated financial statements.
In December 2011, the FASB issued changes to the disclosure of offsetting assets and liabilities. These changes
require an entity to disclose both gross information and net information about both instruments and transactions eligible
for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a
master netting arrangement. The enhanced disclosures will enable users of an entity’s financial statements to understand
and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the
effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments.
These changes became effective for us on January 1, 2013. Other than the additional disclosure requirements, the
adoption of these changes did not impact the consolidated financial statements.
Issued
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
and which implementation approach to select.
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
both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes become
effective for us on January 1, 2016. We have determined that the adoption of these changes will 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 variable interest entities 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 variable interest entities, 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 become
effective for us on January 1, 2016. We are currently evaluating the potential impact of these changes on the
consolidated financial statements.
In April 2015, the FASB issued changes to the presentation of debt issuance costs. Currently, such costs are
required to be presented as a noncurrent asset in an entity’s balance sheet and amortized into interest expense over the
83
term of the related debt instrument. 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. The amortization of debt issuance costs remains
unchanged. These changes become effective for us on January 1, 2016. Management has determined that the adoption of
these changes will result in a decrease of approximately $42.4 million based on the outstanding amount at December 31,
2015 to both deferred financing costs located in noncurrent assets and long-term debt on the accompanying consolidated
balance sheets.
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. Management has determined that the adoption of these changes will not have an impact on the
consolidated financial statements.
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 will be
effective for us beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is
permitted. We will apply this new guidance to any future business combinations.
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 us in fiscal years beginning after
December 15, 2016 and is not expected to have an impact on the consolidated financial statements.
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
84
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.
Our 50% owned Orlando project operates without a fuel contract and is exposed to changes in natural gas
prices. We have entered into various natural gas swaps to effectively fix the price of 6.3 million Mmbtu of future natural
gas purchases at Orlando, which is approximately 100% of our share of the expected on-peak natural gas purchases at
the project through 2016 or approximately 63% of our share of the expected base load natural gas purchases for each of
2015 and 2016. Because projected on-peak gas exposure is fully hedged, a $1.00 MMBtu change in the price of natural
gas would not impact estimated cash distributions for 2016.
In June 2014, the Partnership entered into contracts for the purchase of 2.9 million Gigajoules (“Gj”) of future
natural gas purchases beginning on November 1, 2014 and expiring on December 31, 2017 for our projects in Ontario.
These contracts effectively fix the price of approximately 98% of our expected uncontracted gas requirements for each
of 2014 and 2015 and 32% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively.
These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet
at fair value at December 31, 2015. Changes in the fair market value of these contracts are recorded in the consolidated
statement of operations.
Electricity Commodity Market Risk
Our current and future cash flows are impacted by changes in electricity prices when our projects operate with
no PPA or at projects that operate with PPAs that are based on spot market pricing. Our most significant exposure to
market power prices is at the Chambers, 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 2016, projected cash distributions from Chambers would change by approximately
$0.1 million per 10% change in the PJM-East spot price of electricity based on a forecasted around the clock (“ATC”)
price of $38.31 per MWh and certain other assumptions.
At Morris, where we own 100% of the project, the facility can sell approximately 120 MW above the
off-taker’s demand into the grid at market prices. If market prices do not justify the increased generation the project has
no requirement to sell power in excess of the off-taker’s demand which can negatively impact operating margins. In
2016, projected cash distributions from Morris would change by approximately $0.6 million per 10% change in the spot
price of electricity based on the current level of approximately 175,000 MWh 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 of that portion of
the facility. Forecasted distributions for 2016 would not change materially per 10% change in the forecasted spot price of
electricity.
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 power purchase agreements 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.
85
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 all but 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
counter-party’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, 2015, 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, 2015, 2014, and 2013:
Year Ended December 31,
2014
2015
2013
Unrealized foreign exchange (gain) loss:
Convertible debentures, MTN’s, and other
Foreign currency forwards
Realized foreign exchange loss on forward contract settlements
$
$
(60.5) $
—
(60.5)
0.2
(60.3) $
(39.9) $
1.1
(38.8)
0.5
(38.3) $
(32.4)
19.4
(13.0)
(14.4)
(27.4)
A 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar would have a
$29.1 million impact on the carrying value of the MTNs and convertible debentures denominated in Canadian dollars at
December 31, 2015.
Interest Rate Risk
Changes in interest rates impact cash payments that are required on our debt instruments as approximately
38.2% 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 at equity investments, by approximately $3.4 million at
December 31, 2015.
The Partnership
On May 5, 2014 the Partnership entered into interest rate swap agreements to mitigate exposure to changes in
the Adjusted Eurodollar Rate for $199.0 million notional amount ($153.7 million at December 31, 2015) of the
$600 million aggregate principal amount of borrowings ($473.2 million at December 31, 2015) under the Term Loan
Facility. Borrowings under the $600 million Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar
Rate plus an applicable margin of 3.75%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate
cannot be less than 1.00% resulting in a minimum of a 4.75% all-in rate on the Term Loan Facility. As a result of
entering into the swap agreements, the all-in rate for $199.0 million of the Term Loan Facility cannot be less than 4.91%
if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. If the Adjusted Eurodollar Rate is below 1.00%, we
will pay interest at a rate equivalent to the minimum 4.75% all-in rate plus any difference between the actual three month
Adjusted Eurodollar Rate and 1.16%.
86
The interest rate swap agreements were effective June 30, 2014 and terminate on December 29, 2017. The
interest rate swap agreements are not designated as hedges and changes in their fair market value will be recorded in the
consolidated statements of operations.
Epsilon Power Partners
Epsilon Power Partners, a wholly owned subsidiary, is exposed to changes in interest rates related to its
variable-rate non-recourse debt and previously had an interest rate swap to mitigate this exposure. The interest rate swap
agreement effectively converted the floating rate debt to a fixed interest rate of 7.37% and had a maturity date of July
2019. The notional amount of the swap matched the outstanding principal balance over the remaining life of Epsilon
Power Partners’ debt. On February 20, 2014, we paid $2.6 million to terminate this contract in connection with the
termination of our prior revolving credit facility. We recorded interest expense related to its settlement in the
consolidated statement of operations for the year ended December 31, 2014.
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 income (loss). 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 other
comprehensive income (loss), 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 income (loss). That is, for cash flow hedge, all effective components of the
derivative contract’s gains and losses are recorded in other comprehensive income (loss), pending occurrence of the
expected transaction. Other comprehensive income (loss) 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
income (loss). Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive
income (loss) changes by exactly as much as the derivative contracts and there is no impact on net income (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-rate debt. The interest rate swap agreement effectively converts the floating rate debt to a
fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From
February 2016 until the maturity of the debt in August 2018, the fixed rate of the swap is 4.47% and the applicable
margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.47% from the maturity of
the debt in August 2018 until November 2030. Prior to conversion of the Piedmont Construction loan facility to a term
loan, the notional amounts of the interest rate swap agreements matched the estimated outstanding principal balance of
Piedmont’s construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010
and expire on February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion
on February 14, 2014, these swap agreements were amended to reduce the notional amounts to match the outstanding
$68.5 million principal of the term loan. 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.
87
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. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our
disclosure controls and procedures were not effective as of the end of the fiscal year covered by this Annual Report on
Form 10-K because of the material weakness in internal control over financial reporting described below.
Notwithstanding the material weakness discussed below, 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 U.S. generally accepted accounting principles.
(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
generally accepted accounting principles 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, 2015 using the criteria
established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission (“COSO”).
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.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial
reporting such that there is a reasonable possibility that a material misstatement of a company's annual or interim
financial statements will not be prevented or detected on a timely basis.
88
Based on its evaluation, management has concluded that a material weakness existed in the Company's internal
control over financial reporting as of December 31, 2015 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 US 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 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.
These control deficiencies resulted in misstatements related to goodwill, property, plant and equipment, net,
deferred income taxes and impairment, within the preliminary consolidated financial statements that were corrected prior
to the issuance of the Company’s consolidated financial statements as of and for the fiscal year ended December 31,
2015.
These control deficiencies, if unremediated, could, in another reporting period, result in a material misstatement
to the annual or interim consolidated financial statements that would not be prevented or detected by the controls.
Accordingly, our management has determined that these control deficiencies constitute a material weakness.
(d)
Management's Remediation Plan
Management is actively engaged in the planning for, and implementation of, remediation efforts to address the
material weakness identified above. Management intends to take the following actions to address the material weakness:
Re-designing its controls, including the implementation of new controls, relating to the long-lived asset and
goodwill impairment analysis, including: (i) enhancing the design and documentation of management review controls in
order to enhance the precision at which management review controls operate, (ii) improving the documentation of
internal control procedures, and (iii) enhancing the evaluation of the components of carrying value and comparison to
the requirements of generally accepted accounting principles.
We are in the process of implementing our remediation plan. However, while we expect to take the necessary
steps to establish and enhance controls designed to address the material weakness in the coming year, because the
internal controls relate to impairment tests, which are event-driven or annual tests, we are unable at this time to estimate
when the remediation will be completed.
(e)
Attestation Report of the Registered Public Accounting Firm
The effectiveness of our internal control over financial reporting as of December 31, 2015 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.
(f)
Changes in Internal Control over Financial Reporting
Other than the material weakness described above, there has been no change in our internal control over
financial reporting during the fourth fiscal quarter ended December 31, 2015 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
89
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information concerning our directors and executive officers required by Item 10 will be included in the
Proxy Statement and is incorporated herein by reference.
We have adopted a code of ethics that applies to directors, managers, officers and employees. This code of
ethics, titled “Code of Business Conduct and Ethics,” is posted on our website. The internet address for our website is
www.atlanticpower.com, and the “Code of Business Conduct and Ethics” may be found from our main Web page by
clicking first on “About Us” and then on “Code of Conduct.”
We intend to satisfy any disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or
waiver from, a provision of the “Code of Business Conduct and Ethics” by posting such information on our website, on
the Web page found by clicking through to “Conduct of Conduct” as specified above.
ITEM 11. EXECUTIVE COMPENSATION
The information concerning our directors and executive officers required by Item 11 will be included in the
Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information concerning security ownership and other matters required by Item 12 will be included in the
Proxy Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information concerning certain relationships and related transactions required by Item 13 will be included
in the Proxy Statement and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information concerning principal accountant fees and services required by Item 14 will be included in the
Proxy Statement and is incorporated herein by reference.
90
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)
91
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)
92
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)
10.6+ Amended and Restated Employment Agreement, dated as of April 15, 2013 between Atlantic Power
Corporation and Barry Welch (incorporated by reference to our Quarterly Report on Form 10-Q filed on
August 8, 2013)
10.7+ Amended and Restated Employment Agreement, dated as of April 15, 2013 between Atlantic Power
Corporation and Paul Rapisarda (incorporated by reference to our Quarterly Report on Form 10-Q filed on
August 8, 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)
10.9+ Employment Agreement, dated April 15, 2013, between Atlantic Power Corporation and Edward C. Hall
(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)
93
Exhibit
No.
10.13+ Fourth Amended and Restated Long-Term Incentive Plan (incorporated by reference to our Annual Report on
Description
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)
10.16+ Participation Agreement and Confirmation between the Company and Paul H. Rapisarda, dated April 11,
2013 (incorporated by reference to our Quarterly Report on Form 10-Q filed on August 8, 2013)
10.17+ Participation Agreement and Confirmation (performance-based vesting) between the Company and Terrence
Ronan, dated April 11, 2013 (incorporated by reference to our Quarterly Report on Form 10-Q filed on
August 8, 2013)
10.18+ Participation Agreement and Confirmation between the Company and Edward C. Hall, dated April 2, 2013
(incorporated by reference to our Quarterly Report on Form 10-Q filed on August 8, 2013)
10.19+ Participation Agreement and Confirmation (time-vesting) between the Company and Terrence Ronan, dated
April 11, 2013 (incorporated by reference to our Quarterly Report on Form 10-Q filed on August 8, 2013)
10.20+ Offer Letter between the Company and Edward C. Hall, dated March 26, 2013 (incorporated by reference to
our Quarterly Report on Form 10-Q filed on August 8, 2013)
10.21 Amended and Restated Operating Agreement, dated as of March 30, 2012, between Atlantic Oklahoma
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)
10.25+ Executive Severance and Release Agreement by and between Atlantic Holdings, the Company, and Barry E.
Welch, dated September 22, 2014 (incorporated by reference to our Current Report on Form 8-K filed on
September 23, 2014)
10.26+ Employment Agreement between the Company and Kenneth Hartwick, dated September 22, 2014
(incorporated by reference to our Current Report on Form 8-K/A filed on September 23, 2014)
10.27+ Executive Severance and Release Agreement by and between Atlantic Holdings, the Company and Paul H.
Rapisarda, dated October 21, 2014 (incorporated by reference to our Current Report on Form 8-K filed on
October 22, 2014)
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
10.31+ Executive Severance and Release Agreement by and among Atlantic Power Holdings, Inc., the Company and
Edward C. Hall, dated February 12, 2015 (incorporated by reference to our Current Report on Form 8-K filed
on February 13, 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)
94
Exhibit
No.
10.33 Guaranty Agreement by Atlantic Power Corporation in favor of Terraform AP Acquisition Holdings, LLC,
Description
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)
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
32.1** Certification of the Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
32.2** Certification of the Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 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, 2015
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.
95
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 7, 2016
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 7, 2016
(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/ KENNETH M. HARTWICK Director
Kenneth M. Hartwick
/s/ KEVIN T. HOWELL
Kevin T. Howell
Director
/s/ HOLLI LADHANI
Holli Ladhani
Director
/s/ JOHN A. MCNEIL
John A. McNeil
Director
/s/ GILBERT S. PALTER
Gilbert S. Palter
Director
/s/ TERESA M. RESSEL
Teresa M. Ressel
Director
96
March 7, 2016
March 7, 2016
March 7, 2016
March 7, 2016
March 7, 2016
March 7, 2016
March 7, 2016
March 7, 2016
March 7, 2016
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 Statement of Comprehensive Loss
Consolidated Statements of Shareholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Financial Statement Schedules
Schedule II—Valuation and Qualifying Accounts
Page
F-2
F-4
F-5
F-6
F-7
F-8
F-9
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, 2015, 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.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that
there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be
prevented or detected on a timely basis. A material weakness related to the Company’s internal controls over its long-lived asset and
goodwill impairment tests has been identified and included in management’s assessment.
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, 2015 and 2014, and the related
consolidated statements of operations, comprehensive loss, shareholders’ equity, cash flows and related financial statement schedule
for each of the years in the three-year period ended December 31, 2015. This material weakness was considered in determining the
nature, timing, and extent of audit tests applied in our audit of the 2015 consolidated financial statements, and this report does not affect
our report dated March 7, 2016, which expressed an unqualified opinion on those consolidated financial statements.
In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the
control criteria, Atlantic Power Corporation has not maintained effective internal control over financial reporting as of December 31,
2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
/s/ KPMG LLP
New York, New York
March 7, 2016
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, 2015 and 2014, 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, 2015. In connection with our
audits of the consolidated financial statements, we also have audited financial statement schedule “Schedule II – Valuation and
Qualifying Accounts.” These consolidated financial statements and financial statement schedule are the responsibility of the
Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial
statement schedule 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, 2015 and 2014, and the results of their operations and
their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted
accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents 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, 2015, 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 7, 2016 expressed an adverse opinion on the effectiveness of the Company’s
internal control over financial reporting.
/s/ KPMG LLP
New York, New York
March 7, 2016
F-3
ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of U.S. dollars)
December 31,
2015
2014
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Inventory (Note 6)
Prepayments
Assets held for sale (Note 21)
Income taxes receivable
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 14)
Deferred financing costs (Note 2)
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 (Note 14)
Liabilities held for sale (Note 21)
Other current liabilities
Total current liabilities
Long-term debt (Note 11)
Convertible debentures (Note 12)
Derivative instruments liability (Note 14)
Deferred income taxes (Note 15)
Power purchase and fuel supply agreement liabilities, net (Note 9)
Other long-term liabilities (Note 10)
Total liabilities
$
72.4 $
15.2
39.6
16.9
8.3
—
3.5
4.4
160.3
777.7
286.2
308.9
134.5
0.3
42.5
6.7
106.0
22.5
46.2
19.3
10.6
790.4
0.2
3.3
998.5
962.9
306.9
377.1
197.2
1.1
62.8
9.5
$ 1,717.1 $ 2,916.0
$
6.9 $
1.6
28.8
15.8
36.7
—
2.5
92.3
717.5
285.4
20.8
85.7
27.0
53.2
1,281.9
9.4
5.3
30.7
20.0
36.1
271.8
6.8
380.1
1,145.9
340.6
47.5
92.4
33.4
59.6
2,099.5
Equity
Common shares, no par value, unlimited authorized shares; 122,153,082 and 121,323,614
issued and outstanding at December 31, 2015 and December 31, 2014
Accumulated other comprehensive loss (Note 4)
Retained deficit
Total Atlantic Power Corporation shareholders’ equity
Preferred shares issued by a subsidiary company (Note 19)
Noncontrolling interests
Total equity
Total liabilities and equity
1,290.6
(139.3)
(937.4)
213.9
221.3
—
435.2
1,288.4
(68.3)
(863.9)
356.2
221.3
239.0
816.5
$ 1,717.1 $ 2,916.0
See accompanying notes to consolidated financial statements.
F-4
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions of U.S. dollars, except per share amounts)
Year Ended December 31,
2014
2013
2015
Project revenue:
Energy sales
Energy capacity revenue
Other
Project expenses:
Fuel
Operations and maintenance
Development
Depreciation and amortization
Project other income (loss):
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 expense, net
Impairment (Note 8)
Other income, net (Note 3)
Project (loss) income
Administrative and other expenses (income):
Administration
Interest, net
Foreign exchange 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 income (loss) attributable to Atlantic Power Corporation
Basic and diluted (loss) income per share: (Note 20)
$ 191.5 $ 236.9 $ 231.7
163.7
78.0
473.4
149.3
79.4
420.2
161.3
91.7
489.9
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)
29.4
107.1
(60.3)
(3.1)
73.1
(114.5)
(30.4)
(84.1)
19.5
(64.6)
(11.0)
8.8
6.8
25.5
8.6
(17.7)
(106.6)
—
(83.4)
(38.9)
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) $
194.3
130.0
7.2
124.3
455.8
25.5
25.8
30.4
(19.9)
(34.9)
0.5
27.4
45.0
35.2
104.1
(27.4)
(10.5)
101.4
(56.4)
(32.8)
(23.6)
(0.2)
(23.8)
(3.4)
12.6
(33.0)
Loss from continuing operations attributable to Atlantic Power Corporation
Income (loss) from discontinued operations, net of tax
Net loss attributable to Atlantic Power Corporation
$
$
(0.76) $
0.25
(0.51) $
(1.37) $
(0.10)
(1.47) $
(0.30)
0.02
(0.28)
Weighted average number of common shares outstanding: (Note 20)
Basic
Diluted
121.9
121.9
120.7
120.7
119.9
119.9
Dividends per common share:
$
0.09 $
0.29 $
0.54
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) income, net of tax:
Unrealized (loss) income 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 (loss) income attributable to noncontrolling interests
Comprehensive loss attributable to Atlantic Power Corporation
$
$
Year Ended December 31,
2014
2015
(64.6) $ (182.2) $
2013
(23.8)
(0.6) $
0.8
0.2
(1.0) $
0.9
(0.1)
0.7
0.9
1.6
1.6
(72.8)
(71.0)
(135.6)
(2.2)
(1.7)
(44.1)
(45.9)
(228.1)
(4.8)
$ (133.4) $ (223.3) $
1.4
(34.8)
(31.8)
(55.6)
9.2
(64.8)
See accompanying notes to consolidated financial statements.
F-6
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in millions of U.S. dollars)
Common Common
Shares
(Shares)
Shares
(Amount)
Retained
Deficit
Accumulated
Other
Preferred
Shares of a
Total
Comprehensive Noncontrolling Subsidiary Shareholders’
Income (loss)
Company
Interests
Equity
December 31, 2012
Net (loss) income
Common shares issued for LTIP
Common shares issued for DRIP
Noncontrolling interests
Dividends declared on common shares
Dividends paid to noncontrolling
interests
Dividends declared on preferred shares
of a subsidiary company
Unrealized gain on hedging activities,
net of tax of $1.0 million
Foreign currency translation
adjustments
Defined benefit plan, net of tax of
$1.0 million
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
119.5 $ 1,285.5 $ (565.2) $
— (33.0)
—
0.6
—
—
—
—
— (57.2)
—
0.1
0.6
—
—
9.4 $
—
—
—
—
—
235.4 $ 221.3 $ 1,186.4
(23.8)
12.6
0.6
—
—
—
43.3
—
(57.2)
—
(3.4)
—
—
43.3
—
—
—
—
—
—
—
—
(8.9)
—
(8.9)
—
—
—
(12.6)
(12.6)
—
—
1.6
—
—
1.6
—
—
(34.8)
—
—
(34.8)
—
—
—
120.2 $ 1,286.1 $ (655.4) $
—
2.3
—
—
(177.4)
—
—
(31.1)
—
0.6
0.5
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
121.3 $ 1,288.4 $ (863.9) $
—
2.3
—
(0.1)
—
(62.4)
—
—
—
(11.1)
—
0.7
0.2
(0.1)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
122.1 $ 1,290.6 $ (937.4) $
—
1.4
(22.4) $
—
—
—
—
—
1.4
—
266.4 $ 221.3 $ 1,096.0
(182.2)
11.6
(16.4)
2.3
—
—
—
—
—
(31.1)
—
—
—
—
(0.1)
(44.1)
(1.7)
(68.3) $
—
—
—
—
—
—
—
—
0.2
(72.8)
1.6
(139.3) $
(11.0)
—
—
—
—
—
(11.6)
—
—
—
239.0 $ 221.3 $
(11.0)
—
—
—
—
8.8
—
—
—
—
(3.7)
—
—
(8.8)
(224.3)
—
—
—
—
—
—
— $ 221.3 $
—
(11.0)
(11.6)
(0.1)
(44.1)
(1.7)
816.5
(64.6)
2.3
—
(0.1)
(11.1)
(3.7)
(8.8)
(224.3)
0.2
(72.8)
1.6
435.2
See accompanying notes to consolidated financial statements.
F-7
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of U.S. dollars)
Years Ended December 31,
2014
2013
2015
Cash provided by operating activities:
Net loss
Adjustments to reconcile net loss to net cash provided by operating activities:
$
(64.6)
$
(182.2)
$
(23.8)
Depreciation and amortization
Loss from discontinued operations
Gain on sale of assets
Gain on sale of equity investments
Gain on purchase and cancellation of convertible debentures
Stock-based compensation expense
Long-lived asset and goodwill impairment charges
Equity in earnings from unconsolidated affiliates
Distributions from unconsolidated affiliates
Unrealized foreign exchange gain
Change in fair value of derivative instruments
Change in deferred income taxes
Change in other operating balances
Accounts receivable
Inventory
Prepayments, refundable income taxes and other assets
Accounts payable
Accruals and other liabilities
Cash provided by operating activities:
Cash provided by investing activities:
Change in restricted cash
Proceeds from sale of assets and equity investments, net
Contribution to unconsolidated affiliate
Proceeds from treasury grants
Development costs
Construction in progress
Purchase of property, plant and equipment
Cash provided by investing activities
Cash used in financing activities:
Proceeds from senior secured term loan facility
Proceeds from issuance of equity, net of offering costs
Proceeds from project-level debt
Repayment of corporate and project-level debt
Repayment of convertible debentures
Payments for revolving credit facility borrowings
Deferred financing costs
Equity contribution from noncontrolling interest
Dividends paid to common shareholders
Dividends paid to noncontrolling interests
Dividends paid to preferred shareholders
Cash used in financing activities
Net (decrease) increase 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
$
$
$
$
120.3
—
(48.7)
—
(3.1)
2.3
127.8
(36.2)
58.5
(60.5)
(14.7)
(3.5)
5.7
2.4
20.9
(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
—
$
$
$
$
176.4
32.8
(5.1)
(30.4)
—
2.2
39.7
(26.9)
40.9
(13.0)
(60.2)
(27.3)
3.4
0.8
51.5
(8.4)
(0.2)
152.4
(93.7)
182.6
—
103.2
(0.2)
(39.3)
(5.5)
147.1
—
(1.0)
20.8
(118.8)
—
(67.0)
(2.8)
44.6
(65.1)
(8.9)
(9.4)
(207.6)
91.9
6.5
60.2
158.6
130.4
5.9
8.9
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, 2015, our power generation projects in operation 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 operational power generation projects across eleven states in the
United States and two provinces in Canada. 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, through arrangements that do not involve controlling voting interests.
We apply the standard that requires consolidation of variable interest entities (“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
classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used
or when the restrictions are expected to lapse.
F-9
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(d)
Accounts receivable:
Accounts Receivable are carried at cost. We periodically assesses the collectability of accounts receivable,
considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts
receivable and other currently available evidence of the collectability, and record an allowance for doubtful accounts for
the estimated uncollectible amount as appropriate.
(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 4 to 22 years. The carrying amount of deferred
financing costs recorded on the consolidated balance sheets was $42.5 million and $62.8 million at December 31, 2015
and 2014, respectively. Interest expense from the amortization of deferred finance costs for the years ended
December 31, 2015, 2014, and 2013 was $20.5 million, $16.5 million, and $8.0 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 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.
Interest incurred on funds borrowed to finance capital projects are capitalized, until the project under
construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2015,
2014, and 2013 was $0.0 million, $0.0 million, and $1.9 million, respectively.
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, as well as capitalized development costs. PPAs are valued at the time of acquisition based on the contract
F-10
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
prices under the PPAs compared to projected market prices. Fuel supply agreements are valued at the time of acquisition
based on the contract prices under the fuel supply agreement compared to projected market prices. The balances are
presented net of accumulated amortization in the consolidated balance sheets. Amortization is recorded on a straight-line
basis over the remaining term of the agreement.
(j)
Investments accounted for by the equity method:
We have investments in entities that own power producing assets with the objective of generating cash flow.
The equity method of accounting is applied to such investments in affiliates, which include joint ventures, partnerships,
and limited liability companies because the ownership structure prevents us from exercising a controlling influence over
the operating and financial policies of the projects. Our investments in partnerships and limited liability companies with
50% or less ownership, but greater than 5% ownership in which we do not have a controlling interest are accounted for
under the equity method of accounting. We apply the equity method of accounting to investments in limited partnerships
and limited liability companies with greater than 5% ownership because our influence over the investment’s operating
and financial policies is considered to be more than minor.
Under the equity method, equity in pre-tax income or losses of our investments is reflected as equity in earnings
of unconsolidated affiliates. 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, non-amortizing 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.
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.
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.
F-11
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
(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
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.
F-12
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 are deferred and recorded as a component of accumulated other
comprehensive income (loss) 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 are measured at fair value with changes in fair value
recorded in the consolidated statements of operations. 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 Foreign exchange (gain) loss
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
Classification of changes in fair value
Foreign exchange (gain) loss
Classification of cash settlements
(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 lesser of (1) the amount billable under the
PPA or (2) an amount determined by the kilowatt hours made available during the period multiplied by the estimated
average revenue per kilowatt hour over the term of 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 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.
F-14
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Notional units granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards.
Notional units granted that are expected to be redeemed in common shares upon vesting are accounted for as equity
awards. Unvested notional units are entitled to receive dividends equal to the dividends per common share during the
vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the participant is not an
employee at the vesting date.
We initially recognize compensation expense on the estimated number of notional units for which the requisite
service is expected to be rendered. In 2015, we have estimated a weighted average forfeiture rate of 11% for LTIP
granted in 2015. 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
F-15
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity,
gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including
declines in the creditworthiness of our customers. We do not normally require collateral or other security to support
energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable
due to the credit worthiness and payment history of our customers. See Note 22, Segment and geographic information,
for a further discussion of customer concentrations.
(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)
Revision to the presentation of preferred shares issued by a subsidiary company:
The classification of preferred shares issued by a subsidiary company has been revised from total Atlantic
Power Corporation shareholders’ equity on the Consolidated Balance Sheets at December 31, 2014 to a separate line
item in the noncontrolling interests section of equity. The revision does not impact total equity in either period presented.
The revision was appropriate in order to properly present the preferred shares issued by a subsidiary company in the
consolidated balance sheet. The revision is not considered material to any previously issued financial statements.
(ab)
Recently adopted and issued accounting standards:
Adopted
In April 2014, the FASB issued changes to reporting discontinued operations and disclosures of disposals of
components of an entity. These changes require a disposal of a component to meet a higher threshold in order to be
reported as a discontinued operation in an entity’s financial statements. The threshold is defined as a strategic shift that
has, or will have, a major effect on an entity’s operations and financial results such as a disposal of a major geographical
area or a major line of business. Additionally, the following two criteria have been removed from consideration of
whether a component meets the requirements for discontinued operations presentation: (i) the operations and cash flows
of a disposal component have been or will be eliminated from the ongoing operations of an entity as a result of the
disposal transaction, and (ii) an entity will not have any significant continuing involvement in the operations of the
disposal component after the disposal transaction. Furthermore, equity method investments now may qualify for
discontinued operations presentation. These changes also require expanded disclosures for all disposals of components
of an entity, whether or not the threshold for reporting as a discontinued operation is met, related to profit or loss
information and/or asset and liability information of the component. These changes became effective on January 1, 2015
and were applied to the sale of the Wind Projects in June 2015.
F-16
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating
loss carryforward, a similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an
unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax
loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to
settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the
applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to
settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized
tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating
loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no
explicit guidance existed. These changes became effective for us on January 1, 2014 and did not have a material impact
on the consolidated financial statements.
In March 2013, the FASB issued changes to a parent entity’s accounting for the cumulative translation
adjustment upon derecognition of certain subsidiaries or groups of assets within a foreign entity or of an investment in a
foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from
accumulated other comprehensive income (loss) into net income (loss) in the following circumstances: (i) a parent entity
ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity if
the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the
subsidiary or group of assets had resided; (ii) a partial sale of an equity method investment that is a foreign entity; (iii) a
partial sale of an equity method investment that is not a foreign entity whereby the partial sale represents a complete or
substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an
investment in a foreign entity. These changes became effective for us on January 1, 2014 and had no impact on the
consolidated financial statements.
In February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several
liability arrangements. These changes require an entity to measure such obligations for which the total amount of the
obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its
arrangement among its co- obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its
co-obligors. An entity will also be required to disclose the nature and amount of the obligation as well as other
information about those obligations. Examples of obligations subject to these requirements are debt arrangements and
settled litigation and judicial rulings. These changes became effective for us on January 1, 2014 and had no impact on
the consolidated financial statements.
On January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of
accumulated other comprehensive income. These changes require an entity to report the effect of significant
reclassifications out of accumulated other comprehensive income on the respective line items in net income if the
amount being reclassified is required to be reclassified in its entirety to net income. For other amounts that are not
required to be reclassified in their entirety to net income in the same reporting period, an entity is required to
cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be
applied to each component of accumulated other comprehensive income. Other than the additional disclosure
requirements, the adoption of these changes had no impact on the consolidated financial statements.
On January 1, 2013, we adopted changes issued by the FASB to the testing of indefinite-lived intangible assets
for impairment, similar to the goodwill changes issued in September 2011. These changes provide 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 an indefinite-lived intangible asset 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 an entity elects to
perform a qualitative assessment and determines that an impairment is more likely than not, the entity is then required to
F-17
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
perform the existing two-step quantitative impairment test, otherwise no further analysis is required. An entity also may
elect not to perform the qualitative assessment and, instead, proceed directly to the two-step quantitative impairment test.
The adoption of these changes had no impact on the consolidated financial statements.
In July 2012, the Financial Accounting Standards Board (“FASB”) issued changes to the testing of
indefinite-lived intangible assets for impairment, similar to the goodwill changes issued in September 2011. These
changes provide 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 an
indefinite-lived intangible asset 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 an entity elects to perform a qualitative assessment and determines that an impairment
is more likely than not, the entity is then required to perform the existing two-step quantitative impairment test,
otherwise no further analysis is required. An entity also may elect not to perform the qualitative assessment and, instead,
proceed directly to the two-step quantitative impairment test. These changes became effective for us for any
indefinite-lived intangible asset impairment test performed on January 1, 2013 or later. The adoption of these changes
did not impact the consolidated financial statements.
In December 2011, the FASB issued changes to the disclosure of offsetting assets and liabilities. These changes
require an entity to disclose both gross information and net information about both instruments and transactions eligible
for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a
master netting arrangement. The enhanced disclosures will enable users of an entity’s financial statements to understand
and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the
effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments.
These changes became effective for us on January 1, 2013. Other than the additional disclosure requirements, the
adoption of these changes did not impact the consolidated financial statements.
Issued
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
and which implementation approach to select.
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
F-18
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 become effective for us for financial statements issued after December 15, 2016. We are currently
evaluating the potential impact of these changes on the consolidated financial statements. Subsequent to adoption, this
guidance will need to be applied by management at the end of each annual period and interim period therein to
determine what, if any, impact there will be on the consolidated financial statements in a given reporting period.
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
both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes become
effective for us on January 1, 2016. We have determined that the adoption of these changes will 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 variable interest entities 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 variable interest entities, 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 become
effective for us on January 1, 2016. We are currently evaluating the potential impact of these changes on the
consolidated financial statements.
In April 2015, the FASB issued changes to the presentation of debt issuance costs. Currently, such costs are
required to be presented as a noncurrent asset in an entity’s balance sheet and amortized into interest expense over the
term of the related debt instrument. 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. The amortization of debt issuance costs remains
unchanged. These changes become effective for us on January 1, 2016. Management has determined that the adoption of
these changes will result in a decrease of approximately $42.4 million based on the outstanding amount at December 31,
2015 to both deferred financing costs located in noncurrent assets and long-term debt on the accompanying consolidated
balance sheets.
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-19
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. Management has determined that the adoption of these changes will not have an impact on the
consolidated financial statements.
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 will be
effective for us beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is
permitted. We will apply this new guidance to any future business combinations.
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 us in fiscal years beginning after
December 15, 2016 and is not expected to have an impact on the consolidated financial statements.
3. Divestments
2015 Divestments
(a)
Wind Projects
On March 31, 2015, Atlantic Power Transmission (“APT”), our wholly-owned, direct subsidiary, entered into
the 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.
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
F-20
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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.
2013 Divestments
(a)
Rollcast
On November 5, 2013, we completed the sale of our 60% interest in Rollcast to its remaining shareholders. As
consideration for the sale, we were assigned asset management contracts valued at $0.5 million for the Cadillac and
Piedmont projects as well as the remaining 2% ownership interest in Piedmont bringing our total ownership to 100%. In
return, we paid $0.5 million in cash to the minority owner and forgave an outstanding $1.0 million loan that was
provided by us to Rollcast to fund working capital during 2013. We recorded a $1.0 million gain on sale in the
consolidated statements of operations for the year ended December 31, 2013. Rollcast’s net loss is recorded as loss from
discontinued operations in the consolidated statements of operations for the year ended December 31, 2013.
(b)
Gregory
On April 2, 2013, we and the other owners of Gregory entered into a purchase and sale agreement with an
affiliate of NRG Energy, Inc. to sell the project for approximately $274.2 million, including working capital adjustments.
F-21
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The sale of Gregory closed on August 7, 2013 resulting in a gain on sale of $30.4 million that was recorded in the
consolidated statements of operations for the year ended December 31, 2013. We received net cash proceeds for our
ownership interest of approximately $34.6 million in the aggregate, after repayment of project-level debt and transaction
expenses. As of December 31, 2015, approximately $0.4 million of these proceeds remain in escrow for any post-closing
adjustments that may arise subsequent to the closing date. We used the net proceeds from the sale for general corporate
purposes.
(c)
Auburndale, Lake and Pasco
On January 30, 2013, we entered into a purchase and sale agreement for the sale of our Auburndale Power
Partners, L.P. (“Auburndale”), Lake CoGen, Ltd. (“Lake”) and Pasco CoGen, Ltd. (“Pasco”) projects (collectively, the
“Florida Projects”) for approximately $140.0 million, with working capital adjustments. The sale closed on April 12,
2013 and we received net cash proceeds of approximately $117.0 million in the aggregate, after repayment of
project-level debt at Auburndale and settlement of all outstanding natural gas swap agreements at Lake and Auburndale.
This includes approximately $92.0 million received at closing and cash distributions from the Florida Projects of
approximately $25.0 million received since January 1, 2013. We used a portion of the net proceeds from the sale to fully
repay our senior credit facility, which had an outstanding balance of approximately $64.1 million on the closing date.
The remaining cash proceeds were used for general corporate purposes. The Florida Projects are accounted for as a
component of discontinued operations in the consolidated statements of operations for the year ended December 31,
2013. See Note 21, Discontinued operations, for further information.
(d)
Path 15
On March 11, 2013, we entered into a purchase and sales agreement with Duke Energy Corporation and
American Transmission Co., to sell our interests in the Path 15 transmission line (“Path 15”). The sale closed on
April 30, 2013 and we received net cash proceeds from the sale, including working capital adjustments, of
approximately $52.0 million, plus a management agreement termination fee of $4.0 million, for a total sale price of
approximately $56.0 million. The cash proceeds were used for general corporate purposes. All project-level debt issued
by Path 15, totaling $137.2 million, transferred with the sale. Path 15 is accounted for as a component of discontinued
operations in the consolidated statements of operations for the year ended December 31, 2013. See Note 21,
Discontinued operations, for further information.
F-22
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 other comprehensive loss by component were as follows:
Year Ended December 31,
2014
2015
2013
$
(66.3) $
(22.2) $
12.6
(72.8)
$ (139.1) $
(44.1)
(66.3) $
(34.8)
(22.2)
$
(2.1) $
(0.4) $
(1.8)
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 income (loss):
Unrecognized net actuarial gain (loss)
Tax benefit (expense)
2.2
(0.6)
1.6
0.1
—
(2.3)
0.6
(1.7)
—
—
2.4
(0.7)
1.7
(0.4)
0.1
(0.3)
1.4
(0.4)
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 income (loss):
Net change from periodic revaluations
Tax benefit (expense)
Total Other comprehensive (loss) income before reclassifications, net of tax
Net amount reclassified to earnings:
Interest rate swaps(2)
Fuel commodity swaps
Sub-total
Tax benefit
Total amount reclassified from Accumulated other comprehensive loss,
net of tax
Total Other comprehensive income (loss)
Balance at end of period
$
0.1
1.7
(0.4) $
—
(1.7)
(2.1) $
$
$
0.1 $
0.2 $
(1.4)
(1.0)
0.4
(0.6)
1.3
—
1.3
(0.6)
(1.7)
0.7
(1.0)
1.5
—
1.5
(0.6)
0.7
0.1
0.2 $
0.9
(0.1)
0.1 $
1.2
(0.5)
0.7
1.7
(0.2)
1.5
(0.6)
0.9
1.6
0.2
(1)
In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to
earnings (loss).
(2) This amount was included in Interest expense, net on the accompanying consolidated statements of operations.
F-23
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
5. Equity method investments in unconsolidated affiliates
The following tables summarize our equity method investments in unconsolidated affiliates:
Entity name
Frederickson
Orlando Cogen, LP
Koma Kulshan Associates
Chambers Cogen, LP
Selkirk Cogen Partners, LP
Total
Percentage of
Ownership as of
December 31, 2015
Carrying value as of
December 31,
2014
2015
50.2 % $ 124.7 $ 135.0
10.9
8.4
50.0 %
5.7
5.4
49.8 %
143.3
40.0 % 135.7
12.0
12.0
17.7 %
$ 286.2 $ 306.9
Equity (deficit) in earnings (loss) of equity method investments was as follows:
Entity name
Chambers Cogen, LP
Orlando Cogen, LP
Koma Kulshan Associates
Frederickson
Selkirk Cogen Partners, LP
Gregory Power Partners, LP(1)
Other
Total
Distributions from equity method investments
Deficit in earnings of equity method investments, net of
distributions
Year Ended December 31,
2014
2013
2015
$
6.5 $
7.0 $
27.0
0.4
2.6
0.2
—
—
36.7
(58.5)
18.6
0.9
2.2
(3.2)
—
—
25.5
(76.2)
9.6
3.3
0.3
2.1
8.7
1.6
0.2
25.8
(40.9)
$ (21.8) $ (50.7) $ (15.1)
(1) We sold Gregory in August 2013, resulting in a gain on sale of approximately of $30.4 million, which is recorded in
gain on sale of equity investments in the consolidated statements of operations for the year ended December 31,
2013.
F-24
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following summarizes the financial position at December 31, 2015, 2014 and 2013, and operating results
for the years ended December 31, 2015, 2014 and 2013, respectively, for our proportional ownership interest in equity
method investments:
2015
2014
2013
Assets(1)
Current assets
Chambers
Frederickson
Orlando
Other
Non-current assets
Chambers
Frederickson
Orlando
Other
Liabilities(1)
Current liabilities
Chambers
Frederickson
Orlando
Other
Non-current liabilities
Chambers
Frederickson
Orlando
Other
$ 15.0 $ 14.4 $ 11.8
11.0
7.4
14.6
1.8
10.0
12.2
1.8
6.3
12.9
201.7
124.0
10.2
7.5
224.0
143.9
12.5
26.2
$ 382.4 $ 401.3 $ 451.4
213.4
134.0
11.3
7.2
$
3.7 $
0.7
11.7
0.6
3.5 $
0.3
6.5
1.4
4.4
0.6
5.6
4.0
77.3
0.4
—
1.8
77.7
0.4
—
6.6
$ 96.2 $ 94.4 $ 99.3
81.0
0.4
0.1
1.2
(1) Excludes Idaho Wind Partners 1, LLC and Goshen, which were sold in June 2015 as a part of the sale of the Wind
Projects.
F-25
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Operating results(1)
Revenue
Chambers
Frederickson
Orlando
Other
Project expenses
Chambers
Frederickson
Orlando
Other
Project other income (expense)
Chambers
Frederickson
Orlando
Other
Project income (loss)
Chambers
Frederickson
Orlando
Other
2015
2014
2013
$ 48.0 $ 54.8 $ 52.7
20.7
45.6
72.5
191.5
21.6
54.1
13.1
136.8
20.6
50.5
45.3
171.2
39.7
19.0
27.1
12.7
98.5
44.8
18.4
31.9
46.8
141.9
40.6
18.5
42.3
59.6
161.0
(1.8)
—
—
0.2
(1.6)
(3.0)
—
—
(0.8)
(3.8)
(2.5)
(0.1)
—
(2.1)
(4.7)
$
6.5 $
2.6
27.0
0.6
36.7
7.0 $
2.2
18.6
(2.3)
25.5
9.6
2.1
3.3
10.8
25.8
1) Excludes Idaho Wind Partners 1, LLC and Goshen, which were sold in June 2015 as a part of the sale of Wind
Projects.
6. Inventory
Inventory consists of the following:
Parts and other consumables
Fuel
Total inventory
December 31,
2015
2014
$
$
9.3 $ 11.8
7.5
7.6
16.9 $ 19.3
F-26
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
7. Property, plant and equipment
Land
Office equipment, machinery and other
Leasehold improvements
Asset retirement obligation
Plant in service
Less accumulated depreciation
December 31, December 31,
2015
5.2 $
5.6
—
27.4
975.8
1,014.0
(236.3)
777.7 $
2014
5.7
4.4
0.5
29.3
1,118.8
1,158.7
(195.8)
962.9
$
$
Depreciable
Lives
3 - 10 years
7 - 15 years
1 - 43 years
1 - 45 years
Depreciation expense of $59.0 million, $64.6 million and $64.4 million was recorded for the years ended
December 31, 2015, 2014 and 2013, respectively.
As described in Note 8, Goodwill, we recorded a $76.6 million and $9.6 million long-lived asset impairment to
property, plant and equipment in the years ended December 31, 2015 and 2014, respectively.
8. Goodwill
Our goodwill balance was $134.5 million and $197.2 million as of December 31, 2015 and December 31, 2014,
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 fourth quarter of 2015, we performed our annual goodwill impairment test as of November 30, 2015. Of
the total reporting units with goodwill recorded, only Morris ($3.3 million of goodwill at December 31, 2015), Nipigon
($3.6 million of goodwill at December 31, 2015) and Mamquam ($64.1 million of goodwill at December 31, 2015)
passed step 1 of the two-step test. The total fair value of these reporting units exceeded their carrying value by
approximately $118.0 million or 37%. The Williams Lake, Calstock, Curtis Palmer, North Bay, Kapuskasing and
Moresby Lake reporting units all failed step 1 of the two-step test.
Because these 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 each of the reporting units’ 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 Williams Lake and Calstock asset groups (Canada segment) failed the recoverability test. For these asset
groups, we estimated their fair value utilizing an income approach based on market participant assumptions. These
assumptions include estimated cash flows from both contracted and uncontracted periods over the remaining useful lives
of the Williams Lake and Calstock asset groups. We determined that the carrying value exceeded the fair value at both
asset groups and recorded an impairment of $74.1 million and $2.5 million to the property, plant and equipment of the
Williams Lake and Calstock reporting units, respectively, for the year ended December 31, 2015.
Subsequent to recording long-lived asset impairments, we completed our annual goodwill impairment
assessment. For each of the reporting unit that failed step 1 of the two-step test, we performed a step 2 analysis. As a
F-27
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
result of this analysis, we recorded a $35.6 million full impairment at the Williams Lake reporting unit, a $13.7 million
partial impairment at the Curtis Palmer reporting unit and a $1.9 million full impairment at the Calstock reporting unit in
the year ended December 31, 2015. At the time of their acquisition in November 2011, the fair value of the assets
acquired and liabilities assumed for the Williams Lake, Curtis Palmer and Calstock 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 2011and 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. 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 fourth quarter of 2015 and not
earlier in the fiscal year because we did not identify any triggering events that would have required an event-driven
impairment assessment. The triggering event for testing long-lived assets was identified through our annual test of
goodwill. While declining oil prices over the past year have affected long-term power prices, the continued depressed
price of oil and the long-term outlook for sustained low oil prices in the fourth quarter of 2015 had the most significant
impact to the key inputs to our long-term forecasted cash flow models.
During the third quarter of 2014, we performed an event-driven goodwill impairment test based on the
continued deficit of our market capitalization as compared to our book carrying value. The test was performed as of
August 31, 2014. As a result of the event-driven goodwill assessment, we recorded a $17.9 million full impairment at the
Kenilworth reporting unit (East U.S. segment), a $50.2 million full impairment at the Manchief reporting unit (West U.S.
segment) and a $23.7 million partial impairment at the Williams Lake reporting unit (Canada segment). The total
impairment recorded in the three months ended September 30, 2014 was $91.8 million. The goodwill impairment
recorded at each reporting unit was primarily due to (i) decreases in forward merchant energy prices subsequent to the
expiration of the reporting units’ respective ESA or PPA, as applicable, as compared to the assumptions at the time of
the reporting units’ acquisition in November 2011, (ii) the continued amortization of cash flows under the reporting
units’ respective ESA or PPAs and (iii) an increase in the discount rate reflecting increased re-contracting risk. At the
time of its acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for each of the
Kenilworth, Manchief and Williams Lake reporting units were valued assuming a merchant basis for the period
subsequent to the expiration of the projects’ original ESAs or PPAs. As discussed above, these forecasted energy
revenues on a merchant basis were higher than the energy prices currently forecasted to be in effect subsequent to the
expiration of these reporting units’ ESAs or PPAs. Power prices have declined from 2011 due to several factors
including decreased demand and lower natural gas and oil 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 that were previously
forecasted in 2011.
Under our accounting policies for long-lived assets and goodwill impairment, we also perform an impairment
analysis at the earlier of (i) executing a new PPA (or other arrangement) and (ii) six months prior to the expiration of an
existing PPA. The Tunis project’s PPA expired on December 31, 2014 and accordingly, we performed a long-lived asset
impairment test and a goodwill impairment test as of June 30, 2014. Based on the results of our long-lived asset
impairment test, it was determined that the weighted average estimated undiscounted cash flows for Tunis over its
remaining useful life did not exceed the carrying value of the property, plant and equipment at the Tunis reporting unit.
As a result, the project recorded a $9.6 million long-lived asset impairment charge in the three months ended June 30,
F-28
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
2014 which was the difference between the carrying value of the project’s property, plant and equipment and its
estimated fair market value. Subsequent to adjusting the carrying value of the Tunis reporting unit for the $9.6 million
long-lived asset impairment, we performed an impairment analysis for the project’s goodwill. The project failed step 1 of
the impairment test because the weighted average estimated discounted cash flows over its remaining useful life did not
exceed the carrying value of the Tunis reporting unit. We performed step 2 of the goodwill impairment test and impaired
all of the project’s goodwill because the carrying value of goodwill exceeded its implied fair value. As a result, Tunis, a
component of the Canada segment, recorded a $5.2 million goodwill impairment charge in the three months ended
June 30, 2014. The total $14.8 million long-lived asset and goodwill impairment was primarily due to our assessment of
the forecasted cash flows from re-contracting and other strategic outcomes.
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.
The following table is a rollforward of goodwill for the year ended December 31, 2015:
Balance at December 31, 2013
Impairment of goodwill
Translation adjustment
Balance at December 31, 2014
Impairment of goodwill
Translation adjustment
Balance at December 31, 2015
F-29
Un-allocated
corporate Total
East U.S. West U.S. Canada
$ 79.4 $ 50.3 $ 166.6 $
(50.3)
—
—
—
—
— $ 86.7 $
(28.8)
(2.1)
135.7
(37.5)
(11.5)
(17.9)
—
61.5
(13.7)
—
$ 47.8 $
— $ 296.3
(97.0)
—
(2.1)
—
197.2
—
(51.2)
—
—
(11.5)
— $ 134.5
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
9. Power purchase agreements and other intangible assets and liabilities
Other intangible assets and liabilities include power purchase agreements, fuel supply agreements and
capitalized development costs.
The following tables summarize the components of our intangible assets and other liabilities subject to
amortization for the years ended December 31, 2015 and 2014:
Gross balances, December 31, 2015
Less: accumulated amortization
Net carrying amount, December 31, 2015
Gross balances, December 31, 2014
Less: accumulated amortization
Net carrying amount, December 31, 2014
Gross balances, December 31, 2015
Less: accumulated amortization
Net carrying amount, December 31, 2015
Gross balances, December 31, 2014
Less: accumulated amortization
Net carrying amount, December 31, 2014
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
Other Intangible Assets, Net
Development
Power Purchase
Agreements
$
563.6 $
(187.4)
376.2
$
$
Costs
13.4 $
(12.5)
0.9
$
Total
577.0
(199.9)
377.1
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)
Power Purchase and Fuel Supply Agreement Liabilities,Net
Power Purchase
Fuel Supply
Agreements
Agreements
Total
$
$
(32.2) $
(12.6) $
7.7
(24.5)
$
3.7
(8.9)
$
(44.8)
11.4
(33.4)
The following table presents amortization expense of intangible assets for the years ended December 31, 2015,
2014 and 2013:
2013
2015
2014
$ 51.3 $ 57.6 $ 60.6
(1.2)
$ 50.1 $ 56.4 $ 59.4
(1.2)
(1.2)
Power purchase agreements
Fuel supply agreements
Total amortization
F-30
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 power
purchase agreements and fuel supply agreements:
Year Ended December 31,
2016
2017
2018
2019
2020
Power Purchase Fuel Supply
Agreements
Agreements
(1.2)
$
(1.2)
(1.2)
(1.2)
(1.2)
34.9 $
32.9
26.1
25.4
22.4
The following table presents the weighted average remaining amortization period related to our intangible
assets as of December 31, 2015:
As of December 31, 2015
(in years)
Weighted average remaining amortization period
Power Purchase Fuel Supply
Agreements
Agreements
7.7
7.6
10. Other long-term liabilities
Other long-term liabilities consist of the following:
Asset retirement obligations
Net pension liability
Deferred revenue
Accrued LTIP and director share units
Other
2015
48.5 $
0.6
0.5
1.1
2.5
53.2 $
2014
51.2
3.1
0.9
1.1
3.3
59.6
$
$
The following table is a rollforward of asset retirement obligations for the year ended December 31, 2015:
Asset retirement obligations beginning of year
Accretion of asset retirement obligations
Translation adjustments
Sale of Greeley
Asset retirement obligations, end of year
2015
51.2 $
1.1
(3.8)
—
48.5 $
2014
54.0
1.3
(2.1)
(2.0)
51.2
$
$
F-31
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
Senior unsecured notes, due 2018
Senior unsecured notes, due June 2036 (Cdn$210.0)
Non-Recourse Debt:(2)
Epsilon Power Partners term facility, due 2019
Cadillac term loan, due 2025
Piedmont term loan, due 2018
Other long-term debt
Less: current maturities
Total long-term debt
Current maturities consist of the following:
Current Maturities(2):
Senior secured term loan facility, due 2021
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,
2015
2014
Interest Rate
$
473.2 $
—
151.7
541.5
319.9
181.0
LIBOR(1) plus
3.75 %
9.00 %
5.95 %
19.5
29.5
59.0
0.4
(15.8)
717.5 $
25.5
33.4
64.0
0.6
(20.0)
1,145.9
$
LIBOR plus 3.125 %
1.37 %
LIBOR plus
3.50 %
LIBOR plus
6.70 %
5.50 % -
December 31, December 31,
2015
2014
Interest Rate
$
$
4.7 $
6.0
2.5
2.4
0.2
15.8 $
5.4 LIBOR(1) plus
LIBOR plus
6.1
LIBOR plus
3.9
LIBOR plus
4.5
0.1
5.50 % -
20.0
3.75 %
3.125 %
1.37 %
3.50 %
6.70 %
(1) LIBOR cannot be less than 1.00%. On May 5, 2014 we entered into interest rate swap agreements to mitigate the
exposure to changes in LIBOR for $199.0 million notional amount ($153.6 million at December 31, 2015) of the
$600.0 million ($473.2 million at December 31, 2015) outstanding aggregate borrowings under our senior secured
term loan facility. See Note 14, Accounting for derivative instruments and hedging activities for further details.
(2) Excludes non-recourse debts of $164.9 million and $83.8 million from Meadow Creek term loan and Rockland term
loan as of December 31, 2014, respectively. Both debts are resolved as part of our sale of the Wind Projects. See
Note 3, Divestments.
Principal payments on the maturities of our debt due in the next five years and thereafter are as follows:
2016
2017
2018
2019
2020
Thereafter
$
$
15.8
16.4
68.3
8.5
7.6
616.7
733.3
F-32
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Senior Secured Credit Facilities
On February 24, 2014, Atlantic Power Limited Partnership (“the Partnership”), our wholly-owned indirect
subsidiary, entered into a new senior secured term loan facility (the “Term Loan Facility”), comprising of $600 million
in aggregate principal amount, and a new senior secured revolving credit facility (the “Revolving Credit Facility”) with a
capacity of $210 million (collectively, the “Senior Secured Credit Facilities”). Borrowings under the Senior Secured
Credit Facilities are available in U.S. dollars and Canadian dollars and bear interest at a rate equal to the Adjusted
Eurodollar Rate (LIBOR), the Base Rate or the Canadian Prime Rate, each as defined in the credit agreement governing
the Senior Secured Credit Facilities (the “Credit Agreement”), as applicable, plus an applicable margin between 2.75%
and 3.75% that varies depending on whether the loan is a Eurodollar Rate Loan, Base Rate Loan, or Canadian Prime
Rate Loan. The applicable margin for term loans bearing interest at the Adjusted Eurodollar Rate and the Base Rate is
3.75% and 2.75% respectively and was 3.75% at December 31, 2015. The Adjusted Eurodollar Rate cannot be less than
1.00% (1.00% at December 31, 2015). As further described in Note 14, the Partnership entered into interest rate swap
agreements on May 5, 2014 to mitigate the exposure to changes in the Adjusted Eurodollar Rate for a portion of the
Term Loan Facility.
In connection with the funding of the Senior Secured Credit Facilities, we terminated our prior revolving credit
facility on February 26, 2014.
The Term Loan Facility matures on February 24, 2021. The revolving commitments under the Revolving Credit
Facility terminate on February 24, 2018. Letters of credit are available to be issued under the revolving commitments
until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. The
Partnership is required to pay a commitment fee with respect to the commitments under the Revolving Credit Facility
equal to 0.75% times the average of the daily difference between the revolving commitments and all outstanding
revolving loans (excluding swing line loans) plus amounts available to be drawn under letters of credit and all
outstanding reimbursement obligations with respect to drawn letters of credit.
The Senior Secured Credit Facilities are secured by a pledge of the equity interests in the Partnership and its
subsidiaries, guaranties from the Partnership subsidiary guarantors and a limited recourse guaranty from the entity that
holds all of the Partnership equity, a pledge of certain material contracts and certain mortgages over material real estate
rights, an assignment of all revenues, funds and accounts of the Partnership and its subsidiaries (subject to certain
exceptions), and certain other assets. The Senior Secured Credit Facilities are not otherwise guaranteed or secured by us
or any of our subsidiaries (other than the Partnership subsidiary guarantors). The Senior Secured Credit Facilities have 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 debt service reserve requirement was funded with a $15.8 million letter of
credit.
The Partnership’s existing Cdn$210 million aggregate principal amount of 5.95% Medium Term Notes due
June 23, 2036 (the “MTNs”) prohibit the Partnership (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, the Partnership has granted
an equal and ratable security interest in the collateral package securing the Senior Secured Credit Facilities 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 covenants include a requirement that the Partnership and its subsidiaries maintain a Leverage Ratio (as defined in
the Credit Agreement) ranging from 5.25:1.00 in 2014 to 4.00:1.00 in 2021, and an Interest Coverage Ratio (as defined
in the Credit Agreement) ranging from 2.50:1.00 in 2014 to 3.25:1.00 in 2021. In addition, the Credit Agreement
includes customary restrictions and limitations on the Partnership’s and its subsidiaries’ ability to (i) incur additional
F-33
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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.
Under the Credit Agreement, if a change of control (as defined in the Credit Agreement) occurs, unless the
Partnership elects to make a voluntary prepayment of the term loans under the Senior Secured Credit Facilities, it will be
required to offer each electing lender to prepay such lender’s term loans under the Senior Secured Credit Facilities at a
price equal to 101% of par. In addition, in the event that the Partnership elects to repay, prepay or refinance 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 or refinanced.
The Credit Agreement also contains a mandatory amortization feature and customary mandatory prepayment
provisions, including: (i) from proceeds of assets sales, insurance proceeds, and incurrence of indebtedness, in each case
subject to applicable thresholds and customary carve-outs; and (ii) the payment of 50% of the excess cash flow, as
defined in the Credit Agreement, of the Partnership and its subsidiaries.
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 the Partnership and its
subsidiaries, bankruptcy, material judgments rendered against the Partnership or certain of its subsidiaries, certain
ERISA or regulatory events, a change of control of the Partnership, or defaults under certain guaranties and collateral
documents securing the Senior Secured Credit Facilities, in each case subject to various exceptions and notice, cure and
grace periods.
On February 26, 2014, $600 million was drawn under the Term Loan Facility, and letters of credit in an
aggregate face amount of $144.1 million ($104.0 million as of December 31, 2015) were issued (but not drawn) pursuant
to the revolving commitments under the Revolving Credit Facility and used to (i) satisfy a debt service reserve
requirement in an amount equivalent to six months of debt service (approximately $15.8 million) and (ii) support
contractual credit support obligations of the Partnership and its subsidiaries and of certain other of our affiliates.
Notes of the Partnership
The Partnership, a wholly-owned subsidiary acquired on November 5, 2011, has outstanding Cdn$210.0 million
($151.7 million as of December 31, 2015) 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.
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
contracts of the projects. The loans have certain financial covenants that must be met in order to distribute available
cash. At December 31, 2015, all of our projects, with the exception of Piedmont, were in compliance with the covenants
contained in project-level debt. We do not expect our 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, due to continued operational issues that
F-34
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
have resulted in higher forecasted maintenance and fuel expenses than initially expected.
12. Convertible debentures
The following table provides details related to outstanding convertible debentures:
Balance at December 31, 2013
Repayment of convertible debentures
Foreign exchange gain
Gain on repurchase of convertible
debentures
Balance at December 31, 2014
Repayment of convertible debentures
Foreign exchange (gain) loss
Gain on repurchase of convertible
debentures
6.5%
Debentures
due
6.25%
5.6%
5.75%
6.00%
Debentures Debentures Debentures Debentures
due
due
due
June 2019
due
December 2019 Total
October 2014 March 2017 June 2017
$
42.1 $
(40.6)
(1.5)
63.4 $
—
(5.3)
75.7 $ 130.0 $
(0.7)
(6.4)
(1.3)
—
94.0 $ 405.2
(43.0)
(0.4)
(20.8)
(7.6)
$
—
— $
—
—
(0.1)
58.0 $
(0.1)
(9.3)
—
(0.4)
68.6 $ 128.3 $
(3.0)
(10.7)
(9.4)
—
(0.8)
(0.3)
85.7 $ 340.6
(18.9)
(6.4)
(33.2)
(13.2)
Balance at December 31, 2015
$
—
— $
—
48.6 $
(0.1)
54.8 $ 117.0 $
(1.9)
(1.1)
(3.1)
65.0 $ 285.4
Aggregate interest expense related to the convertible debentures was $17.2 million, $22.8 million, and
$24.2 million for the years ended December 31, 2015, 2014, and 2013, respectively.
In 2006 we issued, in a public offering, Cdn$60.0 million aggregate principal amount of 6.25% convertible
secured debentures (the “2006 Debentures”) for gross proceeds of $52.8 million. The 2006 Debentures paid interest
semi-annually on April 30 and October 31 of each year, had an initial maturity date of October 31, 2011 and were
convertible into approximately 80.6452 common shares per Cdn$1,000 principal amount of 2006 Debentures, at any
time, at the option of the holder, representing a conversion price of Cdn$12.40 per common share. The 2006 Debentures
were secured by a subordinated pledge of our interest in certain subsidiaries and contain certain restrictive covenants. In
connection with our conversion to a common share structure on November 27, 2009, the holders of the 2006 Debentures
approved an amendment to increase the annual interest rate from 6.25% to 6.50% and separately, an extension of the
maturity date from October 2011 to October 2014. Over the maturity term of the 2006 Debentures, Cdn$15.2 million of
the 2006 Debentures were converted to 1.2 million common shares. On October 31, 2014, we used Cdn$44.8 million of
cash on hand to repay the 2006 Debentures at maturity.
On December 17, 2009, we issued, in a public offering, Cdn$86.3 million aggregate principal amount of 6.25%
convertible unsecured debentures (the “2009 Debentures”) for gross proceeds of $82.1 million. The 2009 Debentures
pay interest semi-annually on March 15 and September 15 of each year. The 2009 Debentures mature on March 15, 2017
and are convertible into approximately 76.9231 common shares per Cdn$1,000 principal amount of 2009 Debentures, at
any time, at the option of the holder, representing a conversion price of Cdn$13.00 per common share. As of
December 31, 2015, a cumulative Cdn$18.8 million of the 2009 Debentures, have been converted to 1.4 million
common shares.
On October 20, 2010, we issued, in a public offering, Cdn$80.5 million aggregate principal amount of 5.60%
convertible unsecured subordinated debentures (the “2010 Debentures”) for gross proceeds of $78.9 million. The 2010
Debentures pay interest semi-annually on June 30 and December 30 of each year. The 2010 Debentures mature on
June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion
F-35
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
rate of 55.2486 common shares per Cdn$1,000 principal amount of 2010 Debentures, at any time, at the option of the
holder, representing an initial conversion price of approximately Cdn$18.10 per common share.
On July 5, 2012, we issued, in a public offering, $130.0 million aggregate principal amount of 5.75%
convertible unsecured subordinated debentures due June 30, 2019 (the “July 2012 Debentures”) for net proceeds of
$124.0 million. The July 2012 Debentures pay interest semi-annually on the last day of June and December of each year.
The July 2012 Debentures are convertible into our common shares at an initial conversion rate of 57.9710 common
shares per $1,000 principal amount of July 2012 debentures representing a conversion price of $17.25 per common
share. We used the proceeds to fund a portion of our equity commitment in Canadian Hills.
On December 11, 2012, we issued, in a public offering, Cdn$100 million aggregate principal amount of 6.00%
convertible unsecured subordinated debentures due December 31, 2019 (the “December 2012 Debentures”) for net
proceeds of Cdn$95.5 million. The December 2012 Debentures pay interest semi-annually on the last day of June and
December of each year beginning June 30, 2013. The December 2012 Debentures are convertible into our common
shares at an initial conversion rate of 68.9655 common shares per Cdn$1,000 principal amount of December 2012
Debentures representing a conversion price of Cdn$14.50 per common share. We used the proceeds to acquire all of the
outstanding shares of capital stock of Ridgeline and to fund certain working capital commitments and acquisition
expenses related to Ridgeline.
On November 11, 2014, we commenced a normal course issuer bid (“NCIB”) for our convertible debentures.
Under the NCIB, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate
purchases of our convertible debentures which expired on November 10, 2015. As of December 31, 2015, we had
repurchased and cancelled $24.8 million of convertible debentures and recorded a gain of $3.1 million in the
consolidated statement of operations related to these transactions. On December 29, 2015, we commenced a new NCIB,
which will expire on December 28, 2016. The actual amount of convertible debentures that may be purchased under the
NCIB is approximately $28.5 million and is further limited to 10% of the public float of our convertible debentures.
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,
2015
2014
Cash and cash equivalents
Restricted cash
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
$ 72.4 $
15.2
0.3
36.7
20.8
733.3
285.4
72.4 $
15.2
0.3
36.7
20.8
686.5
231.4
106.0 $
22.5
1.1
36.1
47.5
1,165.9
340.6
Fair Value
106.0
22.5
1.1
36.1
47.5
1,119.5
269.9
Our financial instruments that are recorded at fair value have been classified into levels using a fair value
hierarchy.
F-36
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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.
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, 2015 and December 31, 2014. 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, 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
Level 1
December 31, 2014
Level 3
Level 2
Total
$ 106.0 $
22.5
—
$ 128.5 $
— $
—
1.1
1.1 $
— $ 106.0
22.5
—
—
1.1
— $ 129.6
$
$
— $
— $
83.6 $
83.6 $
— $
— $
83.6
83.6
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, 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. As of December 31, 2014, the credit
F-37
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
valuation adjustments resulted in a $13.0 million net increase in fair value, which consists of a $0.7 million pre-tax gain
in other comprehensive income and a $12.3 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
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 agreements
Gas purchase agreements to purchase gas forward at our North Bay, Kapuskasing and Nipigon projects do not
qualify for the normal purchase normal sales (“NPNS”) exemption and are accounted for as derivative financial
instruments. The gas purchase agreements at North Bay and Kapuskasing satisfy all of the forecasted fuel requirements
for these projects through their expiration in the fourth quarter of 2016. The gas purchase agreement for Nipigon satisfies
the majority of forecasted fuel requirements through December 31, 2022. 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.
In June 2014, the Partnership entered into contracts for the purchase of 2.9 million Gigajoules (“Gj”) of future
natural gas purchases beginning on November 1, 2014 and expiring on December 31, 2017 for our projects in Ontario.
These contracts effectively fix the price of approximately 98% of our expected uncontracted gas requirements for each
of 2014 and 2015 and 32% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively.
These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet
at fair value at December 31, 2015. 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.
The operating margin at our 50% owned Orlando project is exposed to changes in natural gas prices. We
previously entered into natural gas swaps to effectively fix the price of 4.5 million Mmbtu of future natural gas
purchases. On February 20, 2014, we paid $4.0 million to terminate a portion of these contracts in connection with the
termination of our prior revolving credit facility. We recorded fuel expense related to the settlement of these contracts in
the consolidated statement of operations.
F-38
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
We have entered into various natural gas swaps to effectively fix the price of 6.3 million Mmbtu of future
natural gas purchases at Orlando, which is approximately 100% of our share of the expected on-peak natural gas
purchases at the project through 2016 or approximately 63% of our share of the expected base load natural gas purchases
for 2015 and 2016, respectively. These contracts are accounted for as derivative financial instruments and are recorded
in the consolidated balance sheet at fair value at December 31, 2015. Changes in the fair market value of these contracts
are recorded in the consolidated statement of operations.
Interest rate swaps
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 income (loss).
The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest
rates related to its variable-rate debt. The interest rate swap agreement effectively converts the floating rate debt to a
fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From
February 2016 until the maturity of the debt in August 2018, the fixed rate of the swap is 4.47% and the applicable
margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.47% from the maturity of
the debt in August 2018 until November 2030. Prior to conversion of the Piedmont Construction loan facility to a term
loan, the notional amounts of the interest rate swap agreements matched the estimated outstanding principal balance of
Piedmont’s construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010
and expire on February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion
on February 14, 2014, these swap agreements were amended to reduce the notional amounts to match the outstanding
$68.5 million principal of the term loan. We recorded $1.0 million of deferred financing costs related to this transaction
in the consolidated balance sheets. 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.
On May 5, 2014 the Partnership entered into interest rate swap agreements to mitigate exposure to changes in
the Adjusted Eurodollar Rate for $199.0 million notional amount ($153.6 million at December 31, 2015) of the $600
million aggregate principal amount of borrowings ($473.2 million of borrowings at December 31, 2015) under the Term
Loan Facility. Borrowings under the $600 million Term Loan Facility bear interest at a rate equal to the Adjusted
Eurodollar Rate plus an applicable margin of 3.75%. Based on the terms of the Credit Agreement, the Adjusted
Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 4.75% all-in rate on the Term Loan Facility. As a
result of entering into the swap agreements, the all-in rate for $199.0 million of the Term Loan Facility cannot be less
than 4.91% if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. If the Adjusted Eurodollar Rate is below
1.00%, we will pay interest at a rate equivalent to the minimum 4.75% all-in rate plus any difference between the actual
Adjusted Eurodollar Rate and 1.16%. The interest rate swap agreements were effective June 30, 2014 and terminate on
December 29, 2017. The interest rate swap agreements are not designated as hedges and changes in their fair market
value will be recorded in the consolidated statements of operations.
Epsilon Power Partners, our wholly owned subsidiary, previously had an interest rate swap to economically fix
the exposure to changes in interest rates related to the variable-rate non-recourse debt. The interest rate swap agreement
effectively converted the floating rate debt to a fixed interest rate of 7.37% and had a maturity date of July 2019. The
notional amount of the swap matched the outstanding principal balance over the remaining life of Epsilon Power
Partners’ debt. On February 20, 2014, we paid $2.6 million to terminate this contract in connection with the termination
of our prior revolving credit facility. We recorded interest expense related to its settlement in the consolidated statement
F-39
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
of operations. This interest rate swap agreement was not designated as a hedge and changes in its fair market value were
recorded in the consolidated statements of operations.
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. On February 20, 2014,
we paid $0.4 million to terminate all of our remaining foreign currency forward contracts in connection with the
termination of our prior revolving credit facility and recorded their settlement in foreign exchange gain in the
consolidated statement of operations for the three months ended March 31, 2014. On April 2, 2014, we executed a
foreign currency forward contract in which we agreed to sell $41.0 million on September 30, 2014 and receive
Cdn$45.3 million at a foreign exchange rate of Cdn$1.105 per U.S. dollar in order to mitigate the foreign exchange risk
on the repayment at maturity of the Cdn$44.8 million convertible debentures due in October 2014. We recorded a $0.5
million realized foreign exchange loss on the expiration of the foreign currency forward contract on September 30, 2014.
We repaid the Cdn$44.8 million convertible debentures with cash on hand at their maturity on October 31, 2014.
Volume of forecasted transactions
We have entered into derivative instruments in order to economically hedge the following notional volumes of
forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS
exemption as of year ended December 31, 2015 and December 31, 2014:
Natural gas swaps
Gas purchase agreements
Interest rate swaps
Fair value of derivative instruments
Units
December 31, December 31,
2015
2014
Natural Gas (Mmbtu)
Natural Gas (Gigajoules)
Interest (US$)
2.8
25.0
302.3
6.3
33.9
333.9
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, 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
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
Gas purchase agreements current
Gas purchase agreements long-term
Total derivative instruments not designated as cash flow hedges
Total derivative instruments
$
F-40
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, 2014
Derivative
Assets
Derivative
Liabilities
$
— $
—
—
1.1
2.9
4.0
—
1.1
—
—
—
—
1.1
1.1 $
2.0
6.9
4.4
2.2
28.6
35.5
79.6
83.6
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:
For the 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
Gains expected to be realized from OCI in the next 12 months, net
of $0.6 million of tax
$
$
$
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
Gains expected to be realized from OCI in the next 12 months, net
of $0.6 million of tax
$
$
$
Interest Rate
Swaps
Interest Rate
Swaps
0.1
(0.6)
0.7
0.2
0.8
0.2
(1.0)
0.9
0.1
0.9
For the year ended December 31, 2013
Accumulated OCI balance at January 1, 2013
Change in fair value of cash flow hedges
Realized from OCI during the period
Accumulated OCI balance at December 31, 2013
Gains expected to be realized from OCI in the next
12 months, net of $0.6 million of tax
$
$
$
Interest Rate
Swaps
Natural Gas
Swaps
Total
(1.5) $
0.7
1.0
0.2 $
0.1 $
—
(0.1)
— $
0.9 $
— $
(1.4)
0.7
0.9
0.2
0.9
F-41
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Impact of derivative instruments on the consolidated statements of operations
The following table summarizes realized loss (gain) for derivative instruments not designated as cash flow
hedges:
Gas purchase agreements
Natural gas swaps
Interest rate swaps
Foreign currency forwards
Classification of loss (gain)
recognized in income
Fuel
Fuel
Interest, net
Foreign exchange loss (gain)
2015
Year Ended December 31,
2013
2014
$ 47.3 $ 52.4 $ 56.5
—
3.4
(14.4)
4.3
6.1
0.5
6.0
3.8
—
The following table summarizes the unrealized loss (gain) resulting from changes in the fair value of derivative
financial instruments that are not designated as cash flow hedges:
Classification of gain (loss)
recognized in income
Year ended December 31,
2013
2014
2015
Natural gas swaps
Gas purchase agreements
Interest rate swaps
Foreign currency forwards
15. Income taxes
Current income tax expense
Deferred tax benefit
Total income tax benefit, net
Change in fair value of derivatives $ 1.0 $ (3.3) $ (0.7)
19.2
Change in fair value of derivatives
11.6
7.0
Change in fair value of derivatives
(1.5)
$ 15.4 $ 6.8 $ 25.5
— $ (1.1) $ (19.4)
$
Foreign exchange loss
16.1
(1.7)
Year Ended December 31
2014
2015
2013
$
$
5.3 $
3.8 $
(35.7)
(30.4) $
(35.2)
(31.4) $
8.6
(41.4)
(32.8)
F-42
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% at
December 31, 2015, 2014 and 2013, respectively, to the provision for income taxes in the consolidated statements of
operations:
Computed income taxes at 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
Federal stimulus grant
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
$
$
$
Year ended December 31,
2014
(47.5) $
2015
(29.8) $
2013
(14.7)
(4.9)
(34.7) $
6.6
(28.1)
(19.2)
(66.7) $
40.5
(26.2)
(5.3)
(20.0)
12.1
(7.9)
1.1
(7.0)
2.1
—
(3.6)
(6.3)
2.1
14.8
—
(5.0)
(0.5)
(2.3)
(30.4) $
0.8
(7.4)
(5.8)
—
(0.3)
(4.1)
—
33.9
(10.2)
(15.8)
3.7
(5.2)
(31.4) $
3.7
(9.9)
(2.8)
(18.9)
(4.4)
23.0
—
13.6
—
(30.9)
1.7
(24.9)
(32.8)
The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and
deferred tax liabilities at December 31, 2015 and 2014 are presented below:
Deferred tax assets:
Loss carryforwards
Other accrued liabilities
Finance and share issuance costs
Tax credits
Disallowed interest carryforward
Derivative instruments
Other long-term notes
Other
Total deferred tax assets
Valuation allowance
Deferred tax liabilities:
Intangible assets
Property, plant and equipment
Other long-term investments
Total deferred tax liabilities
Net deferred tax liability
F-43
2015
2014
$ 238.4 $ 340.3
0.4
6.2
—
3.4
22.3
—
10.3
382.9
(168.6)
214.3
0.1
1.7
4.7
—
15.1
5.2
9.8
275.0
(175.2)
99.8
(79.0)
(106.5)
—
(185.5)
(75.0)
(208.9)
(22.8)
(306.7)
$ (85.7) $ (92.4)
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, 2015 and 2014:
Long-term deferred tax liabilities
Net deferred tax liability
2015
2014
$ (85.7) $ (92.4)
$ (85.7) $ (92.4)
As of December 31, 2015, we have recorded a valuation allowance of $175.2 million. This amount is comprised
primarily of provisions against available Canadian and U.S. net operating loss carryforwards. In assessing the
recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the
deferred tax asset will be realized. The ultimate realization of the deferred tax assets is dependent upon projected future
taxable income in the United States and in Canada and available tax planning strategies.
In 2011, the IRS began an examination of our federal income tax returns for the tax years ended December 31,
2007 and 2009. On April 2, 2012, the IRS issued various Notices of Proposed Adjustments. The principal area of the
proposed adjustments pertain to the classification of U.S. real property in the calculation of the gain related to our 2009
conversion from the previous Income Participating Security structure to our current traditional common share structure.
On September 14, 2014, we entered into a settlement agreement with the IRS resulting in a $3.6 million increase to our
taxable income for the 2009 tax year. This increase in taxable income was offset against our current year taxable losses
for the 2009 tax year and therefore resulted in no cash taxes.
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, 2015, we have not recorded any tax benefits related to uncertain tax positions.
As of December 31, 2015, 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
$
$
45.3
92.0
70.0
25.8
13.4
26.3
150.2
166.7
589.7
F-44
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
The following table summarizes the changes in outstanding LTIP notional units during the years ended
December 31, 2015, 2014 and 2013:
Outstanding at December 31, 2012
Granted
Additional shares from dividends
Forfeitures
Vested and redeemed
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
Units
492,535 $
597,031
64,576
(184,458)
(202,696)
766,988
1,776,083
178,114
(294,037)
(983,894)
1,443,254
1,007,726
59,996
(136,894)
(1,075,681)
Grant Date
Weighted-Average
Fair Value per Unit
13.90
4.91
8.74
8.17
13.48
7.86
2.64
3.79
6.68
4.78
3.28
2.75
2.87
3.75
3.21
2.88
1,298,401 $
The total grant date fair value of all outstanding notional units under the LTIP was $3.7 million, $4.6 million
and $4.8 million for the years ended December 31, 2015, 2014 and 2013. The weighted average remaining vesting term
for outstanding notional units was 1.7 years at December 31, 2015. Approximately $1.7 million of total unrecognized
compensation expense is expected to be recognized over this time period. Compensation expense related to LTIP was
$3.1 million, $3.5 million and $2.2 million for the years ended December 31, 2015, 2014 and 2013, respectively. Cash
payments made for vested notional units were $0.9 million, $0.7 million and $0.9 million for the years ended
December 31, 2015, 2014 and 2013, respectively.
Transition Equity Participation Agreement
We also have 550,869 transition notional shares outstanding at December 31, 2015 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 ($2.58) by at least 50%.
17. Defined benefit 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
legacy Partnership participants. The Plan is a defined benefit pension plan that allows for employee contributions. We
expect to contribute $0.7 million to the pension plan in 2016.
F-45
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The net annual periodic pension cost related to the pension plan for the years ended December 31, 2015 and
2014 includes the following components:
2015
2014
Service cost benefits earned
Interest cost on benefit obligation
Expected return on plan assets
Gain amortization
Net period benefit cost
$
0.9 $
0.7
(0.9)
—
0.8
0.7
(0.8)
—
0.7
$
0.7 $
A comparison of the pension benefit obligation and related plan assets for the pension plan is as follows:
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 were as follows:
2014
(0.9)
(0.7)
2.2
(0.1)
0.7
(0.1)
(15.0)
2015
$ (16.2) $ (14.5)
(0.8)
(0.7)
(3.3)
(0.1)
0.1
(0.1)
(19.4)
$ 13.6 $ 13.8
1.7
0.7
0.1
(0.1)
0.1
16.3
(3.1)
1.0
0.5
0.1
(0.7)
(0.1)
14.4
(0.6) $
$
Non-current liabilities
2015
2014
$
0.6 $
3.1
Amounts recognized in accumulated OCI that have not yet been recognized as components of net periodic
benefit cost were as follows, net of tax:
Unrecognized loss
2015
2014
$
1.6 $
1.7
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-46
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
$
2014
2015
15.0 $ 19.4
15.4
12.6
16.3
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 $14.4 million and $16.3 million for the years ended December 31, 2015 and 2014
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
2015
2014
4.3 %
3.0 %
4.0 %
4.0 %
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
2015
2014
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, 2015 and 2014, was 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-47
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
2015
2014
29 %
14 %
14 %
40 %
3 %
100 %
30 %
14 %
13 %
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$:
2016
2017
2018
2019
2020
2021-2024
18. Common shares
Stock Repurchase Program
2015
Cdn$
0.2
0.3
0.4
0.5
0.6
4.5
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 permits the Company to repurchase stock
through open market repurchases. The NCIB will expire on December 28, 2016 or such earlier date as the Company
and/or APPEL complete their respective purchases pursuant to the NCIB. During the year ended December 31, 2015, we
repurchased 47,300 common shares under the NCIB at a total cost of $0.1 million and through March 3, 2016, we
repurchased a cumulative 575,553 common shares at a total cost of $1.0 million.
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.
F-48
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 $8.8 million on the Series 1 Shares, Series 2 Shares and
Series 3 in 2015 as compared to $11.6 million in 2014.
20. Basic and diluted earnings (loss) per share
Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common
shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive
potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be
issued if all of the convertible debentures were converted into shares at January 1, 2015. Dilutive potential shares also
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 were vested and redeemed for shares under the terms of the
LTIP.
Because we reported a loss for the years ended December 31, 2015, 2014 and 2013, diluted earnings per share
are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.
F-49
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share
calculation for the years ended December 31, 2015, 2014 and 2013:
2015
2014
2013
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
Corporation
$ (92.9) $ (164.8) $ (36.2)
3.2
$ (62.4) $ (177.4) $ (33.0)
(12.6)
30.5
121.9
120.7
119.9
22.7
0.2
144.8
27.7
0.3
148.7
27.7
0.7
148.3
$ (0.76) $ (1.37) $ (0.30)
0.02
(0.10)
0.25
$ (0.51) $ (1.47) $ (0.28)
Potentially dilutive shares from convertible debentures have been excluded from fully diluted shares in the
years ended December 31, 2015, 2014 and 2013 because their impact would be anti-dilutive.
21. Discontinued operations
On March 31, 2015, APT, our wholly-owned, direct subsidiary, entered into the Purchase Agreement with
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.
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.
On November 5, 2013, we completed the sale of our 60% interest in Rollcast to its remaining shareholders. As
consideration for the sale, we were assigned asset management contracts valued at $0.5 million for the Cadillac and
Piedmont projects as well as the remaining 2% ownership interest in Piedmont bringing our total ownership to 100%. In
return, we paid $0.5 million in cash to the minority owner and forgave an outstanding $1.0 million loan that was
provided by us to Rollcast to fund working capital during 2013. Rollcast’s net loss is recorded as loss from discontinued
operations in the consolidated statements of operations for the year ended December 31, 2013.
The Florida Projects and Path 15 were sold on April 12, 2013 and April 30, 2013, respectively. Accordingly,
the projects’ net income (loss) is recorded as income (loss) from discontinued operations, net of tax in the statements of
operations for the years ended December 31, 2013.
F-50
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following table summarizes the December 31, 2014 financial position of the Wind Projects that were
classified as assets held for sale:
Current assets:
Cash and cash equivalents
Accounts receivable
Other current assets
Non-current assets:
Property, Plant & Equipment
Equity investments in unconsolidated affiliates
Other intangible assets, net
Restricted cash
Other assets
Assets held for sale
Current liabilities:
Accounts payable and other accrued liabilities
Current portion of long-term debt
Current portion of derivative instruments liability
Long term liabilities
Long-term debt
Derivative instruments liability
Other long-term liabilities
Liabilities held for sale
Noncontrolling interests held for sale
December 31,
2014
$
$
$
$
3.9
11.2
2.4
17.5
710.5
37.0
4.3
19.1
2.0
790.4
5.9
6.4
3.1
15.4
242.4
10.0
4.0
271.8
239.0
F-51
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
The following tables summarize the revenue, loss from operations, and income tax expense of the Wind
Projects, Greeley, Rollcast, Path 15 and the Florida Projects for the years ended December 31, 2015, 2014, and 2013:
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 (loss) on sale of asset
(Loss) income from operations of discontinued businesses
Income tax expense
(Loss) income from operations of discontinued businesses, net of tax
Net loss attributable to noncontrolling interests of discontinued
businesses
(Loss) income from operations of discontinued businesses, net of
noncontrolling interests
$
2015
Year Ended December 31,
2014
2013
$
34.8 $
79.3 $
149.9
—
10.8
10.3
21.1
(0.7)
(0.5)
(6.7)
46.8
38.9
52.6
33.1
19.5
—
21.1
40.3
61.4
(15.5)
0.3
(14.2)
2.0
(27.4)
(9.5)
19.5
(29.0)
30.6
33.2
52.1
115.9
34.7
1.1
(18.1)
(37.8)
(20.1)
13.9
14.1
(0.2)
(11.0)
(16.4)
(3.4)
30.5 $
(12.6) $
3.2
The following table summarizes the operating and investing cash flows of the Wind Projects for the years ended
December 31, 2015 and 2014:
Cash provided by operating activities
Cash (used in) provided by investing activities
December 31,
2015
2014
$ 21.9 $ 48.3
4.8
(12.8)
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations for the Wind
Projects, Florida Projects, Path 15, Greeley and Rollcast was $0.25, ($0.10), and $0.02 for the years ended December 31,
2015, 2014, and 2013 respectively.
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 years ended December 31, 2014
and 2013 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 project performance without
considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at
F-52
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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 are components of the former Wind segment, Greeley and Path 15, which are components of the West
U.S. segment, the Florida Projects, which are components of the East U.S. segment, and Rollcast, which is a component
of Un-Allocated Corporate, are included in the income (loss) from discontinued operations line item in the table below.
We have adjusted prior periods to reflect this reclassification. A reconciliation of Project Adjusted EBITDA to project
income (loss) is included in the table below:
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
423.8
86.7
3.4
819.9
47.8
7.0
$ 104.8 $ 46.9 $ 59.7 $
0.9 $
244.8
—
0.4
(2.5) $
0.6
1.1
—
(2.2)
(2.0)
29.4
107.1
(60.3)
(3.1)
420.2
1,717.1
134.5
11.3
208.9
(15.4)
130.1
9.8
125.8
(41.4)
29.4
107.1
(60.3)
(3.1)
—
39.3
—
7.6
—
—
—
—
(16.0)
47.2
—
114.2
(85.7)
—
—
—
—
(85.7)
—
7.6
—
7.6 $ (85.7) $
(75.1)
(30.4)
(44.7) $
(114.5)
(30.4)
(84.1)
Change in fair value of derivative instruments
Depreciation and amortization
Interest, net
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
—
42.5
9.8
13.8
38.7
—
—
—
—
38.7
—
$ 38.7 $
F-53
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, 2014
Project revenues
Segment assets
Goodwill
Capital expenditures
Project Adjusted EBITDA
Change in fair value of derivative instruments
Depreciation and amortization
Interest, net
Other project expense (income)
Project income (loss)
Administration
Interest, net
Foreign exchange gain
Other income, net
Income (loss) from continuing operations before income
taxes
Income tax benefit
Net income (loss) from continuing operations
Year Ended December 31, 2013
Project revenues
Segment assets
Goodwill
Capital expenditures
Project Adjusted EBITDA
Change in fair value of derivative instruments
Depreciation and amortization
Interest, net
Other project expense
Project (loss) income
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
$
167.1 $ 123.6 $ 198.3 $
1,103.2
61.5
3.1
676.8
135.7
7.8
396.7
—
0.4
106.4 $ 54.2 $ 76.3 $
—
40.3
(0.1)
41.6
(27.6)
—
—
—
—
(11.7)
59.9
—
38.6
(10.5)
—
—
—
—
4.3
55.0
20.6
17.8
8.7
—
—
—
—
0.9 $
739.3
—
1.1
(7.5) $
1.2
0.7
0.1
(9.5)
37.9
146.7
(38.3)
(0.6)
489.9
2,916.0
197.2
12.4
229.4
(6.2)
155.9
20.5
98.1
(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)
$
$
East U.S. West U.S. Canada
Un-Allocated
Corporate Consolidated
$ 146.1 $ 119.1 $ 208.6 $
493.4
50.3
0.1
967.9
166.6
2.4
935.4
79.4
1.5
$ 105.2 $ 57.1 $ 65.6 $
(5.2)
54.9
20.7
33.2
1.6
—
—
—
—
—
41.4
0.3
(26.3)
41.7
—
—
—
—
(19.2)
64.7
0.1
1.9
18.1
—
—
—
—
1.6
—
1.6 $ 41.7 $ 18.1 $
41.7
—
18.1
—
$
(0.4) $
144.4
—
3.6
(18.6) $
—
0.5
(2.1)
(0.6)
(16.4)
35.2
104.1
(27.4)
(10.5)
473.4
2,541.1
296.3
7.6
209.3
(24.4)
161.5
19.0
8.2
45.0
35.2
104.1
(27.4)
(10.5)
(117.8)
(32.8)
(85.0) $
(56.4)
(32.8)
(23.6)
The table below provides information, by country, about our consolidated operations for each of the years
ended December 31, 2015, 2014 and 2013 and Property, Plant & Equipment as of December 31, 2015 and 2014,
F-54
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.
United States
Canada
Total
2015
Revenue
2014
$ 255.5 $ 291.6 $ 264.8 $
198.3
$ 420.2 $ 489.9 $ 473.4 $
164.7
208.6
2013
Property, Plant & Equipment,
net
2015
529.6 $
248.1
777.7 $
2014
553.5
409.4
962.9
Ontario Electric Financial Corporation (“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. OEFC purchases electricity from the Calstock, Kapuskasing, Nipigon, North Bay and
Tunis projects in the East U.S. segment. San Diego Gas & Electric purchases electricity from the Naval Station, Naval
Training Center, and North Island projects in the West U.S. segment. BC Hydro purchases electricity from the
Mamquam, Moresby Lake, and Williams Lake projects in the West U.S. segment.
23. Commitments and contingencies
Commitments
Operating Lease Commitments
We lease our office properties and equipment under operating leases expiring on various dates through 2021.
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. Lease expense under operating
leases was $1.5 million, $1.0 million and $1.0 million for the years ended December 31, 2015, 2014, and 2013,
respectively. Future minimum lease commitments under operating leases for the years ending after December 31, 2015,
are as follows:
2016
2017
2018
2019
2020
Thereafter
$
$
0.6
0.6
0.6
0.2
—
—
2.0
F-55
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Long-Term Service Commitments
Our projects have entered into long-term contractual arrangements to obtain maintenance services for turbine
equipment expiring on various dates through 2022. As of December 31, 2015, our commitments under such outstanding
agreements are estimated as follows:
2016
2017
2018
2019
2020
Thereafter
$
$
0.4
0.4
0.4
0.4
0.4
0.6
2.6
Fuel Supply and Transportation Commitments
We have entered into long-term contractual arrangements to procure fuel and transportation services for our
projects. As of December 31, 2015, our commitments under such outstanding agreements are estimated as follows:
2016
2017
2018
2019
2020
Thereafter
Contingencies
Shareholder class action lawsuits
Massachusetts District Court Actions
$
54.0
20.8
14.4
10.4
10.4
20.8
$ 130.8
On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints
were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of
Massachusetts (the “District Court”) against Atlantic Power and Barry E. Welch, our former President and Chief
Executive Officer and a former Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or
all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer,
and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the “Proposed Individual
Defendants,” and together with Atlantic Power, the “Proposed Defendants”) (the “U.S. Actions”).
The District Court complaints differed in terms of the identities of the Proposed Individual Defendants they
named, as noted above, the named plaintiffs, and the purported class period they alleged (July 23, 2010 to March 4, 2013
in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions),
but in general each alleged, among other things, that in Atlantic Power’s press releases, quarterly and year end filings
and conference calls with analysts and investors, Atlantic Power and the Proposed Individual Defendants made
materially false and misleading statements and omissions regarding the sustainability of Atlantic Power’s common share
dividend that artificially inflated the price of Atlantic Power’s common shares. The District Court complaints assert
F-56
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
claims under Section 10(b) and, against the Proposed Individual Defendants, under Section 20(a) of the Securities
Exchange Act of 1934, as amended.
The parties to each District Court action filed joint motions requesting that the District Court set a schedule in
the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class
action complaint (the “Amended Complaint”), after the appointment of lead plaintiff and counsel; (ii) setting a deadline
for Proposed Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for
subsequent briefing regarding any such motion to dismiss); and (iii) confirming that the Proposed Defendants need not
answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the
Amended Complaint. On May 7, 2013, each of six groups of investors (the “U.S. Lead Plaintiff Applicants”) filed a
motion (collectively, the “U.S. Lead Plaintiff Motions”) with the District Court seeking: (i) to consolidate the five U.S.
Actions (the “Consolidated U.S. Action”); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to
have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed
oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed
replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address
certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and
directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of
those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file
additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13
and September 18, 2013.
On March 31, 2014, the Court entered an order consolidating the five individual U.S. Actions, appointing the
Feldman, Shapero, Carter and Smith investor group (one of the six U.S. Lead Plaintiffs Applicants) as Lead Plaintiff and
approving Lead Plaintiff’s selection of counsel. The Court also granted the parties’ joint motion regarding initial case
scheduling and directed the parties to resubmit a proposed schedule that contains specific dates. In response to that
directive, on April 7, 2014, Lead Plaintiff filed an application and proposed order, which sought an extension of the
schedule contained in the joint motion. The application and proposed order requested that: (i) Lead Plaintiff be permitted
to file an amended complaint on or before May 30, 2014, (ii) the Proposed Defendants be permitted to move to dismiss
or otherwise respond to the amended complaint on or before July 29, 2014, (iii) Lead Plaintiff be permitted to file an
opposition, if any, on or before September 24, 2014, and (iv) the Proposed Defendants be permitted to file a reply to
Lead Plaintiff’s opposition on or before November 13, 2014. Proposed Defendants did not object to the schedule
proposed by Lead Plaintiff. On May 29, 2014, Lead Plaintiff filed a renewed application and proposed order, which
sought another extension of the schedule, and on June 3, 2014, Lead Plaintiff and the Proposed Defendants jointly filed a
stipulation and proposed order requesting the following revised schedule: (i) Lead Plaintiff be permitted to file an
amended complaint on or before June 6, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or
otherwise respond to the amended complaint on or before August 5, 2014, (iii) Lead Plaintiff be permitted to file an
opposition, if any, on or before October 6, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead
Plaintiff’s opposition on or before November 20, 2014. On June 3, 2014, the Court entered an order setting this
requested schedule.
On June 6, 2014, Lead Plaintiff filed the amended complaint (the “Amended Complaint”). The Amended
Complaint names as defendants Barry E. Welch and Terrence Ronan (the “Individual Defendants”) and Atlantic Power
(together with the Individual Defendants, the “Defendants”) and alleges a class period of June 20, 2011 to March 4, 2013
(the “Class Period”). The Amended Complaint makes allegations that are substantially similar to those asserted in the
five initial complaints. Specifically, the Amended Complaint alleges, among other things, that in Atlantic Power’s press
releases, quarterly and year end filings and conference calls with analysts and investors, Defendants made materially
false and misleading statements and omissions regarding the sustainability of Atlantic Power’s common share dividend,
which artificially inflated the price of Atlantic Power’s common shares during the class period. The Amended Complaint
continues to assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the
F-57
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Securities Exchange Act of 1934, as amended. It also asserts a claim for unjust enrichment against the Individual
Defendants. In accordance with the schedule referenced above, Defendants filed their motion to dismiss the consolidated
(the “Motion to Dismiss”) U.S. Action on August 5, 2014.
On September 30, 2014, citing Atlantic Power’s September 16, 2014 announcement of changes to its dividend
and its President and CEO transition, Lead Plaintiff filed a motion (the “Extension Motion”) requesting a thirty day
extension of its October 6, 2014 deadline for filing its brief in opposition to the Motion to Dismiss, in which to
determine whether to file a second amended complaint. On October 2, 2014, the Court entered an order (i) extending
Lead Plaintiff’s deadline to file its opposition to the Motion to Dismiss to October 10, 2014 and (ii) requiring Defendants
to file their opposition to the Extension Motion by October 2, 2014. In accordance with this order, on October 2, 2014,
Defendants filed their opposition to the Extension Motion. On October 10, 2014, Lead Plaintiff filed its opposition to the
Motion to Dismiss (the “Opposition”) and also filed a motion for leave to amend the Amended Complaint, attaching a
proposed second amended complaint. On October 21, 2014, Lead Plaintiff and Defendants filed a joint scheduling
motion requesting (i) November 7, 2014 as the deadline for Defendants to file their opposition to Lead Plaintiff’s motion
for leave to amend the Amended Complaint; (ii) November 24, 2014 as the deadline for Defendants to file their reply in
further support of the Motion to Dismiss; and (iii) November 24, 2014 as the deadline for Lead Plaintiff to file its reply
in further support of its motion for leave to amend the Amended Complaint. On October 22, 2014, the Court entered an
order setting this requested schedule. Pursuant to that order, the Motion to Dismiss and Extension Motion were fully
briefed on November 24, 2014. On January 22, 2015, the Court held oral argument on the Motion to Dismiss and
Extension Motion.
On January 30, 2015, Lead Plaintiff filed a motion for leave to file a supplemental submission in opposition to
Defendants’ motion to dismiss (the “Motion for Leave”). The Court denied the Motion for Leave in an order entered on
February 5, 2015, but permitted Lead Plaintiff to submit a brief letter identifying supplemental authorities. Lead Plaintiff
filed that letter on February 9, 2015, and Defendants filed a response on February 10, 2015.
On March 13, 2015, the District Court entered an order granting Defendants’ motion to dismiss and denying
Lead Plaintiff’s motion to amend the Amended Complaint, and on March 18, 2015, the District Court entered an order
dismissing the Amended Complaint with prejudice.
On April 16, 2015, Lead Plaintiff filed a notice of appeal to the United States Court of Appeals for the First
Circuit (the “First Circuit”). On August 19, 2015, Lead Plaintiff filed with the First Circuit its brief appealing the
dismissal of its securities fraud claims.
On September 4, 2015, while appellate proceedings were still on-going, Lead Plaintiff filed with the District
Court a Rule 60(b)(2) motion to vacate the judgment based on evidence cited in the Ontario Superior Court’s decision
dismissing the Canadian action (for more information on that litigation, see below under “Canadian Actions”). On
September 17, 2015, Atlantic Power opposed Lead Plaintiff’s motion.
On September 18, 2015, Lead Plaintiff requested a stay of the appellate proceedings in the First Circuit pending
resolution of the District Court’s decision on its Rule 60(b)(2) motion. On September 21, 2015, Atlantic Power opposed
Lead Plaintiff’s request for a stay and tendered to the First Circuit its opposition brief to Lead Plaintiff’s appeal. On
October 5, 2015, the First Circuit granted Lead Plaintiff’s request for a stay in the appellate proceeding pending the
District Court’s decision on the Rule 60(b)(2) motion.
On October 21, 2015, the District Court entered an order denying Lead Plaintiff’s Rule 60(b)(2) motion to
vacate the judgment.
F-58
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
On October 29, 2015, pursuant to Federal Rule of Appellate Procedure 42(b), the parties jointly stipulated to the
voluntary dismissal of the appeal before the First Circuit with prejudice. On November 30, 2015, the First Circuit
ordered that the case be voluntarily dismissed.
Canadian Actions
On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities
class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common
shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of
Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power
common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of
Quebec in the Province of Quebec (the “Canadian Actions”).
On April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the
Ontario Superior Court of Justice in the Province of Ontario.
On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being
issued on behalf of Jacqeline Coffin and Sandra Lowry. As in the U.S. Action, this claim named the Company, Barry E.
Welch and Terrence Ronan as Defendants. The Plaintiffs sought leave to commence an action for statutory
misrepresentation under the Ontario Securities Act and asserted common law claims for misrepresentation.
The Plaintiffs’ motions for leave and certification were heard on May 20-21, 2015.
On July 24, 2015, the Ontario Superior Court of Justice issued a decision denying the Plaintiffs’ motion for
leave and certification. The Superior Court granted leave to reconstitute a claim for debenture holders but required that
there be a debenture holder as plaintiff, that the claim be amended and that the Plaintiffs pay the Defendants partial
indemnity costs of responding to the Plaintiffs’ motion.
The Plaintiffs appealed the July 24 decision on leave and certification to the Ontario Court of Appeal.
The appeal was subsequently abandoned by the Plaintiffs, and the Ontario action was dismissed by Order dated
December 2, 2015, the Defendants agreeing not to claim costs from the Plaintiffs.
The proposed Quebec class action was suspended by the Superior Court of Quebec pending the outcome of the
motions for leave and certification of the Ontario action as a class proceeding. Following the result in Ontario, the
petitioner in the Quebec proceedings has agreed in principle with the Defendants to discontinue the Quebec proceedings
without costs. The discontinuance will require the authorization of the Superior Court of Quebec. The parties are
preparing materials to obtain this authorization.
The petitioner in the Quebec proceedings did not estimate the alleged damages of the proposed class. Because
the Quebec proceedings were suspended and then an agreement to discontinue was made in its early stages, Atlantic
Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation, if it were
to continue. If the action were to continue, Atlantic Power intends to defend against it vigorously.
Other
In addition to the other matters listed, 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
F-59
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
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, 2015.
24. Unaudited selected quarterly financial data
Unaudited selected quarterly financial data are as follows:
Quarter Ended
2015
Project revenue
Project (loss) income
Loss (income) from continuing operations
Income (loss) from discontinued operations
Net (loss) income attributable to Atlantic Power
Corporation
December 31, September 30, June 30,
$
98.4 $
March 31, Total
107.4 $ 103.1 $ 111.3 $ 420.2
(41.4)
24.2
(84.1)
(3.3)
19.5
(0.5)
17.2
(20.0)
33.6
21.5
24.6
(12.3)
(104.3)
(85.4)
(1.3)
(88.6)
(6.0)
14.7
17.5
(62.4)
(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
$
(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
F-60
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
Quarter Ended
2014
Project revenue
Project income (loss)
Loss from continuing operations
Loss from discontinued operations
Net loss attributable to Atlantic Power Corporation
Loss per share from continuing operations attributable
to Atlantic Power Corporation
Loss per share from discontinued operations
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 from discontinued operations
Diluted loss per share attributable to Atlantic Power
Corporation
Weighted average number of common shares
outstanding-diluted
Dividends per common share
25. Guarantees
March 31,
Total
December 31, September 30, June 30,
$
119.9 $
2.1
(5.1)
(7.3)
(10.6)
121.6 $ 123.1 $ 125.3 $ 489.9
(38.9)
(64.7)
(153.2)
(83.2)
(29.0)
(7.7)
(177.4)
(88.7)
(2.0)
(50.7)
(5.7)
(59.2)
25.7
(14.2)
(8.3)
(18.9)
$
(0.07) $
(0.02)
(0.71) $ (0.45) $ (0.14) $ (1.37)
(0.10)
(0.02)
(0.04)
(0.02)
(0.09) $
(0.73) $ (0.49) $ (0.16) $ (1.47)
$
121.0
120.7
120.6
120.3
120.7
(0.07) $
(0.02)
$
(0.71) $ (0.45) $ (0.14) $ (1.37)
(0.10)
(0.02)
(0.04)
(0.02)
(0.09) $
(0.73) $ (0.49) $ (0.16) $ (1.47)
121.0
0.03
120.7
0.07
120.6
0.10
120.3
0.10
120.7
0.29
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.
In connection with the Purchase Agreement for the sale of the Wind Projects, on March 31, 2015, we entered
into the Guaranty Agreement, under which we agreed to guarantee the full and prompt payment of all payment
obligations of APT under the Purchase Agreement as and when they shall become due. APT and TerraForm have agreed
to utilize the representation and warranty insurance for coverage of certain indemnification obligations, subject to a cap
and certain exclusions.
F-61
ATLANTIC POWER CORPORATION
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013
(in millions of U.S. dollars)
Balance at Charged to
Beginning of Costs and
Expenses
Period
Charged to
Balance at
Other Accounts Deductions End of Period
Income tax valuation allowance, deducted from
deferred tax assets:
Year ended December 31, 2015
Year ended December 31, 2014
Year ended December 31, 2013
$
$
168.6 $
128.1
116.0 $
6.6 $
40.5
12.1 $
— $
—
— $
— $
—
— $
175.2
168.6
128.1
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
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 21, 2016.
14SEP201110485170