AcuityAds Annual Report 2008

FY2008 Annual Report · AcuityAds
Loading PDF…
INVEST IN 
POWER

ATLANTIC POWER CORPORATION 2008 ANNUAL REPORT

INVEST IN 
POWER

CORPORATE PROFILE 
Atlantic Power Corporation owns interests in a diversified and growing portfolio 

of power generating and transmission projects in major markets in the United States. 

The Company’s objectives are to maintain the stability and sustainability of cash 

distributions to holders of IPSs and to increase the long-term value of the Company. 

The Company’s Income Participating Securities (IPSs) are listed on the Toronto Stock 

Exchange under the symbol ATP.UN.

  CO N T E N T S

  1  Financial Highlights

  2   Report to Shareholders

  6  Projects at a Glance

  7  Management’s Discussion and 

  Analysis

 42  Consolidated Financial Statements 

45   Notes to the Consolidated 

  Financial Statements

66   Corporate Information

 
 
 
2008

FINANCIAL HIGHLIGHTS
(US$000 except where noted and per IPS data)

YEARS ENDED DECEMBER 31 

2008 

2007

Project revenue 
Project income 
Total assets 

Cash available for distribution (Cdn$000) 
Cash available for distribution per basic IPS (Cdn$) 

Total IPS distributions (Cdn$000) 
Total distribution per basic IPS (Cdn$) 

334,221 
132,230 
1,151,590 

110,719 
1.81 

65,143 
1.06 

  306,192
(113,395)
  1,081,847

86,005
1.40

65,181
1.06

MEETING OUR GOALS

 1  Sustain and grow cash flows:

 2  Make accretive acquisitions:

 >  Cash available for distribution increased 

 >  Purchase of Auburndale Project in 

29%, including one-time items
 >  Able to meet current level of cash 

distributions into 2015 without further 
acquisitions or organic growth

November 2008 was immediately accretive 
to distributable cash

 >  Pursuing development of several biomass 

power generation projects

 3  Enhance financial flexibility:

 >  Extended currency hedge for cash 

distributions at favorable exchange rates for 
two more years through December 2013

 >  Continued to add natural gas hedges that 

enhance the stability of future operating 
margins

 >  Cost eﬀ ectively ﬁ nanced Auburndale 
acquisition during challenging credit 
environment in late 2008

 4  Generate strong returns for investors:

 >  8% increase in cash dividend on common 

share portion of IPS 

 >  While the share price was down in 2008, 
ATP’s performance was better than its
independent power peers, TSX Trust Index 
and TSX Composite Index

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
REPORT TO SHAREHOLDERS

In spite of the challenges facing the economy 
and capital markets in 2008, we successfully grew 
our base of power producing assets, increased 
cash available for distribution and raised our 
common share dividend for the third time in the 
past four years.

SOLID FINANCIAL RESULTS
We were pleased with our operating and ﬁ nancial results 
in 2008 as cash ﬂ ow available for distribution rose to 
$103.7 million, an almost 30% increase from $80.1 million 
in the prior year.  The increase was primarily due to 
higher Adjusted EBITDA from our projects as well as the 
positive impact of several non-recurring items.  This solid 
performance resulted in a conservative payout ratio of 
59% in 2008 compared to 77% in 2007.

As a result of an acquisition completed in November 

and our positive outlook on the future performance of 
our portfolio, we were pleased to increase the common 
share dividend portion of our Income Participating 
Security (IPS) distribution by 8%, or Cdn$0.034, bringing 
our total annual cash distribution to Cdn$1.094 per IPS.  
This was the third increase in cash distributions since our 
Initial Public Oﬀ ering in November 2004, further proof 
that our strategies to enhance value are working.

GROWING AND STRENGTHENING OUR ASSET BASE
A key component of our initiatives to grow distributable 
cash is to make accretive acquisitions of power and 
related projects in targeted growth markets.  Since our 
Initial Public Oﬀ ering, we have added a total of three 
major projects to our portfolio and also acquired portions 
of other plants where we already had an ownership 
position.  These acquisitions have increased our net 
megawatts owned by 28%, and all of these acquisitions 
have made strong contributions to our growth and 
performance.

In November 2008 we acquired 100% of the 
Auburndale facility, a 155-megawatt natural gas-ﬁ red 

2 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

cogeneration facility in central Florida.  We were able 
to complete and cost-eﬀ ectively ﬁ nance this transaction 
despite the unprecedented volatility in the ﬁ nancial 
markets and the resulting tight credit environment.  The 
purchase price of approximately US$140 million was 
funded by cash on hand, $55 million in borrowings under 
our credit facility and $35 million of non-recourse 
acquisition debt. 

The Auburndale acquisition was immediately 

accretive to cash ﬂ ow and brings a number of additional 
beneﬁ ts to Atlantic Power.  The facility has a medium-
term power purchase agreement through 2013 and a fuel 
supply agreement through mid-2012, which substantially 
hedges natural gas prices.  Importantly, the plant has an 
excellent operating history since commencing operations 
in 1994 and we expect some synergies from our other 
operations in Florida.

ADDITIONAL DEVELOPMENTS
There were a number of other positive developments 
that bode well for strong performance going forward.  

Taking advantage of lower natural gas forward curves 

during late 2008 and early 2009, we were able to enter 
into a series of ﬁ nancial swaps that hedge the price of 
signiﬁ cant portions of future natural gas purchases at our 
Lake Project through 2013 and at our new Auburndale 
facility.  By capitalizing on these lower natural gas prices, 
we have enhanced the returns these investments will 
provide over the next few years.

Subsequent to year-end, our Path 15 transmission 

line in California reached a settlement on its 2008 
through 2010 rate case that will allow the Project to make 

distributions to the Company consistent with manage-
ment’s expectations.  Independently, the ﬁ nal resolution 
of the last pending landowner right-of-way litigation was 
resolved recently, which will result in the release of 
approximately $6 million to Path 15 in the second quarter 
of 2009 from a construction reserve account.  

During the fourth quarter, we reviewed our invest-

ment in the Stockton Project in order to determine 
whether we would recover our investment in the project. 
This review was undertaken as a result of the current and 
long-term market conditions for coal-ﬁ red generating 
assets in California, including the dramatically lower price 
of natural gas, which drives the price received for the 
Project’s electricity sales, and the signiﬁ cantly higher cost 
of Utah coal used by the Project. 

Based on this review, we determined that the carrying 

value of the Stockton Project will not be recovered and 
recorded a pre-tax impairment charge of $18.5 million 
at year-end.  This represents the entire carrying value of 
the project’s property, plant and equipment.  Subsequent 
to year-end, Stockton’s Power Purchase Agreement (PPA) 
was extended through March 2010 and we are consider-
ing a number of options to achieve additional recovery 
of our investment in the Project.  Over the past three years 
Stockton has represented on average only about 2% of 
total annual Project distribution.

RENEWABLE ENERGY INITIATIVES
As had been anticipated since our Initial Public Oﬀ ering, 
our Onondaga Project was formally taken oﬄ  ine on 
April 30, 2008.  Since the shutdown, we have successfully 
sold the project’s gas turbines, spare parts and other 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

3

 
equipment for total proceeds of approximately 
$7.5 million.  We are also making solid progress working 
with an experienced partner to re-develop and convert 
the site into a 35 to 40 megawatt biomass facility, 
providing renewable energy for the equivalent of up 
to 40,000 local homes.  This state-of-the-art facility would 
be the cleanest biomass plant in New York State and 
would create approximately 24 jobs at the plant as well 
as 150 fuel-related jobs.  The design, development and 
permitting process is progressing well.

In addition to the potential Onondaga conversion, 

in April we ﬁ nalized an investment in a biomass 
development company with a current pipeline of ﬁ ve 
50-megawatt biomass power plants in various stages of 
development.  Two of these projects have 20-year PPAs 
signed, which include fuel price pass-through mecha-
nisms.  The development company’s management team 
has more than 30 years of experience in project develop-
ment, management and ﬁ nancing, with an emphasis on 
solid fuels.  This opportunity will give us the option to 
invest equity in their ﬁ ve renewable energy projects. 
Renewable energy incentives included in the American 
Recovery and Reinvestment Act of 2009 signiﬁ cantly 
enhance the potential economic value of this investment 
and the Onondaga conversion.

FINANCIAL MARKETS AND DISTRIBUTION 

SUSTAINABILITY
Despite the challenging credit markets experienced 
through 2008 and continuing into 2009, we remain 
conﬁ dent in our ability to make additional investments 
in our projects as well as potential new acquisitions. 
While lending spreads for project-level debt are wider 
than they have been historically, underlying Treasury 
and LIBOR rates have remained relatively low, and as a 
result all-in rates are reasonable.  We are regularly in 
contact with our lenders and all have signiﬁ cant ongoing 
interest in ﬁ nancing our projects.

On the growth front, we continue to evaluate a 
solid pipeline of opportunities across North America, 
including proprietary deal ﬂ ow from our industry network, 
and we have a continuing ability to ﬁ nance potential 
acquisitions without accessing the public equity markets.  
Most important for our investors, based on our pro-
jections of distributable cash ﬂ ow from existing projects, 
utilizing reputable third-party commodity cost forecasts 

4 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

and including our cash on hand, we can continue the 
current level of monthly cash distributions well into 2015 
without any additional acquisitions or organic growth. 
This guidance includes the fact that we expect distribu-
tions from projects in 2009 will decline to between 
$90 million and $95 million due to expiring contracts at 
speciﬁ c projects, a drop in Chambers’ contribution due 
primarily to a planned full plant shutdown for mainte-
nance, and the absence of certain one-time items that 
positively impacted cash ﬂ ows in 2008.  

To further mitigate currency risk, in the fourth quarter 
of 2008, after a signiﬁ cant strengthening of the U.S. dollar, 
we extended our forward purchases of Canadian dollars 
at favorable rates for two additional years through 2013.  
We are also utilizing our excess cash to enhance 

value by acquiring IPSs in the open market.  As of 
December 31, 2008 we had acquired and canceled 
558,620 IPSs at an average price of Cdn$8.78 under our 
approved issuer bid. We continued to acquire IPSs in 
2009 as we believe they are an attractive investment 
and a prudent use of the Company’s cash.

A POSITIVE FUTURE
Looking ahead, we remain conﬁ dent in our ability to 
provide investors with stable, sustainable and growing 
cash distributions over the long term. 

We are evaluating additional acquisition opportuni-

ties within the North American power industry that meet 
our investment guidelines and will increase distributable 
cash ﬂ ow.  Capitalizing on our strong relationships 
with our investors, existing project partners and our 
broader industry network, we have excellent access 

to these growth opportunities.  Our investment in the 
biomass development company is a perfect example 
of positioning ourselves for superior investment 
opportunities in the renewable energy marketplace.
We continue to work closely with our project 
managers to enhance the operating and ﬁ nancial 
performance of our existing facilities.  Initiatives such as 
equipment upgrades and the optimization of our power 
purchase agreements, fuel supply contracts and other 
commercial arrangements serve to enhance returns 
at these projects.  Our initiative to convert the Onondaga 
plant to a biomass project is just one example 
of this creative strategy in action.  

Finally, we will continue to look for opportunities 
to consolidate and increase our ownership in projects 
where we have partial interests.  We know these projects, 
we are comfortable with their operations and we can 
accurately assess their future potential and risk proﬁ le. 
In closing, we are pleased with the continued 
success we have had in executing our strategies to grow 
distributable cash and increase the value of the 
Company.  I would like to thank our employees for their 
hard work in making this possible and our shareholders 
for their continued support.

Barry Welch
President and Chief Executive Oﬃ  cer

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

5

 
PROJECTS AT A GLANCE

Our diversified and well-
positioned power producing and 
related assets, located in major 
U.S. growth markets from coast to 
coast, continue to deliver strong 
operating performance and 
stable, sustainable and growing 
cash flow for our investors.

F

N

K

B

L

O

M

C

D

E

H

G

J

I

A

  PROJECT NAME 

LOCATION 

FUEL TYPE 

TOTAL MW 

OWNERSHIP INTEREST  

NET MW 

155 

46 

262 

132 

400 

13 

121 

308 

129 

121 

N/A 

85 

345 

55 

14 

100.00% 

50.00% 

40.00% 

40.00% 

17.10% 

49.80% 

100.00% 

50.00% 

50.00% 

100.00% 

100.00% 

23.50%  

18.50%  

50.00% 

50.00%  

155

23

105

53

68

6

121

154

65

121

N/A

20

64

27

7

A  Auburndale 

Auburndale  FL 

B  Badger Creek 

Bakersfield  CA 

Natural Gas 

Natural Gas 

C  Chambers 

Carney’s Point  NJ 

Coal 

D  Delta-Person 

Albuquerque  NM 

E  Gregory 

Corpus Christi  TX 

Natural Gas 

Natural Gas 

F  Koma Kulshan 

Whatcom County  WA 

Hydro 

G  Lake 

Umatilla  FL 

H  Mid-Georgia 

Kathleen  GA 

Orlando  FL 

Tampa  FL 

California 

Rumford  ME 

Natural Gas 

Natural Gas 

Natural Gas 

Natural Gas 

Transmission 

Coal/Biomass 

Bethlehem  NY 

Natural Gas 

Stockton  CA 

Topsham  ME 

Coal 

Hydro/Biomass 

I  Orlando 

J  Pasco 

K  Path 15 

L  Rumford 

M  Selkirk 

N  Stockton 

O  Topsham 

Additional details in MD&A on page 23.

6 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

MANAGEMENT’S DISCUSSION AND ANALYSIS
of Financial Condition and Results of Operations 

The following management’s discussion and analysis (“MD&A”) of ﬁ nancial condition and results of operations should be read 
in conjunction with the audited annual consolidated ﬁ nancial statements of Atlantic Power Corporation (“Atlantic Power” or 
the “Company”) for the year ended December 31, 2008. All dollar amounts in this MD&A are in thousands of U.S. dollars, un-
less otherwise stated. The annual ﬁ nancial statements have been prepared in accordance with Canadian generally accepted 
accounting principles (“GAAP”).

Forward-Looking Statements
Certain statements in this MD&A may constitute “forward-looking statements”, which reﬂ ect the expectations of Atlantic Power 
Management, LLC (the “Manager”) regarding future growth, results of operations, performance and business prospects and 
opportunities of the Company and the Projects (as deﬁ ned below). Examples of such statements include: the expectation that 
the Company’s cash on hand and projected future cash ﬂ ows will be adequate to meet the current level of cash distributions to 
IPS holders into 2015; the amount of distributions expected to be received from the Projects for the full year 2009; the Company’s 
current forecast of expected annual cash distributions from the Lake and Auburndale Projects through 2012; and the expected 
decrease  in  distributions  from  Chambers  in  2009.  Such  forward-looking  statements  reﬂ ect  current  expectations  regarding 
future  events  and  operating  performance  and  speak  only  as  of  the  date  of  this  MD&A.  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 the Company’s expectations. Forward-looking statements involve 
signiﬁ cant 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 
to the assumption described above, reference should also be had to the factors discussed under “Risk Factors” in the Company’s 
Annual Information Form dated March 30, 2009. Although the forward-looking statements contained in this MD&A 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  diﬀ erences  may  be  material. These  forward-looking  statements  are  made  as  of 
the date of this MD&A and, except as expressly required by applicable law, the Company assumes no obligation to update or 
revise them to reﬂ ect new events or circumstances. The ﬁ nancial outlook information contained in this MD&A is presented to 
provide readers with guidance on the cash distributions expected to be received by the Company and to give readers a better 
understanding of the Company’s ability to pay its current level of distributions into the future. Readers are cautioned that such 
information may not be appropriate for other purposes.

Information contained in this MD&A is based on information available to management as of March 30, 2009. 

Copies of ﬁ nancial data and other publicly ﬁ led documents, including the Company’s annual information form, are avail-
able on SEDAR at www.sedar.com under “Atlantic Power Corporation” or on the Company’s website at www.atlanticpower
corporation.com.

Overview
As of March 30, 2009, the Company has 60,938,731 income participating securities (“IPSs”), and Cdn$60 million principal amount 
of 6.25% convertible secured debentures due October 31, 2011 (the “Debentures”) outstanding. Atlantic Power Holdings, LLC 
(“Holdings”) was formed in 2004 to acquire indirect interests in a diversiﬁ ed portfolio of power generating facilities located 
primarily in major markets in the United States from ArcLight Energy Partners Funds I, L.P. (“Fund I”) and ArcLight Energy Partners 
Funds II, L.P. (“Fund II”, and, together with Fund I, the “ArcLight Funds”) and Caithness Energy, LLC (“Caithness”) (together with the 
ArcLight Funds, the “Former Investors”). As of February 2007, Holdings became a wholly-owned subsidiary of the Company.

Each IPS is comprised of: (1) one common share of the Company (“Common Share”); and (2) Cdn$5.767 aggregate 
principal amount of 11.0% subordinated notes of the Company (“Subordinated Notes”). IPS investors receive a monthly dis-
tribution comprised of a dividend payment on the Common Share and an interest payment on the Subordinated Notes. The 
current annual total distribution is Cdn$1.09 per IPS. 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

7

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

The Debentures were issued on October 11, 2006 and bear interest at an annual rate of 6.25%, payable semi-annually 
in arrears on April 30 and October 31 of each year commencing on April 30, 2007. The Debentures are convertible at any time, 
at the option of the holder, into 80.6452 IPSs per Cdn$1,000 principal amount of Debentures, representing a conversion price 
of Cdn$12.40 per IPS.

As of December 31, 2008, the Company owned interests in 14 power generating facilities in the United States and 
a transmission line in central California (collectively, the “Projects” and individually, a “Project”). The generating Projects have a 
combined total power generating capacity of approximately 2,186 megawatts (“MW”). The Company’s net interests in the 
Projects represented approximately 988 MW of power generating capacity as of December 31, 2008. Most of the generating 
Projects sell their power under long-term power purchase agreements (“PPAs”) to investment-grade utilities or other power 
purchasers. These agreements are typically structured to stabilize cash ﬂ ows by: (1) providing on average approximately half 
of the electricity revenues via steady capacity or tolling payments generally designed to provide a return of and on capital and 
to cover ﬁ xed costs regardless of how much electricity the plant is called upon to produce, provided that the plant meets an 
availability requirement; and (2) generally passing changes in the generating Projects’ fuel costs on to the power purchasers. 
As a result, variations in the portfolio’s cash ﬂ ow resulting from changes in the amount of power generated, spot market 
electricity prices and fuel price changes are signiﬁ cantly mitigated.

The Path 15 transmission line is a United States Federal Energy Regulatory Commission (“FERC”) regulated asset with a 
30-year regulatory life through 2034. Its annual revenue requirement is established by FERC and is collected by the California 
Independent System Operator (“CAISO”) from utilities in California without variations resulting from changes in power prices 
or line usage and with virtually no technical or operating risks.

The Company’s objectives are to maintain the stability and sustainability of cash distributions to holders of IPSs and to 
increase the long-term value of the Company. To achieve these objectives, Company management, working directly with 
Project managers, focuses on enhancing the operation of the existing Projects by improving facility performance, increasing 
output and eﬃ  ciency, optimizing contracts and managing other Project risks. In addition, the Company has a focused growth 
strategy that includes consolidating interests in Projects where it already holds an ownership interest, and making accretive 
acquisitions with a primary focus on the electric power industry in the United States and Canada. 

Management believes that opportunities for accretive acquisitions will be available based on a number of factors, 
including continued long-term electricity demand growth and the corresponding need for new power plants, continued 
liquidity in the secondary market for ownership interests in power-related assets, and superior access to potential growth 
transactions  through  the  Manager’s  industry  contacts.  Competitors  for  these  opportunities  include  private  equity  or 
infrastructure funds, power income funds and other sources of capital.

The most signiﬁ cant economic factors aﬀ ecting the Company’s performance are changes in energy commodity prices, 
interest rates, credit spreads and the currency exchange rate between the U.S. dollar and the Canadian dollar. See “Outlook” in 
this MD&A for further details regarding Projects that have signiﬁ cant exposure to commodity price risk. More than 90% of the 
Company’s existing debt either bears interest at a ﬁ xed rate or is economically hedged through the use of interest rate swaps. 
However, interest rates and credit spreads could aﬀ ect valuations of assets the Company may be attempting to buy or sell. All 
of the Company’s operating cash ﬂ ow is earned in U.S. dollars and a large portion of the Company’s cash obligations, primarily 
distributions on IPSs and interest payments on the Debentures, are denominated in Canadian dollars. See “Financial Instruments” 
in this MD&A for more information about currency exchange rate impacts and the Company’s strategy for managing this risk, 
including the hedging of the current levels of distributions and other Canadian dollar obligations at ﬁ xed rates through 2013.

Recent Developments
The FERC issued its initial order regarding Path 15’s 2008-2010 rates on February 19, 2008. That order granted approval of the 
Company’s proposed 13.5% return on equity and set certain other matters for hearing. On March 23, 2009, Path 15, FERC staﬀ , 
and the intervenors in the Project’s rate case ﬁ led an uncontested settlement with the FERC. The terms of the settlement will 
allow Path 15 to make distributions to the Company that are consistent with management’s expectations in 2009 and 2010. 
The Company expects the FERC to approve the settlement in the next two to three months. Once it is approved, Path 15 will 

8 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

be making a refund of approximately $1.3 million, comprising the amount collected above the settlement rates since the 
initial order in February 2008. Independently, the ﬁ nal resolution of pending landowner litigation over right-of-way issues 
was resolved recently, which will result in approximately $6 million being released in the second quarter to Path 15 from a 
construction reserve account.

In the fourth quarter of 2008, management reviewed the recoverability of its investment in the Stockton Project. The 
review was undertaken as a result of the current status of negotiations to extend the Project’s PPA and the recent deterioration 
of current and long-term market conditions for coal-ﬁ red generation assets in California, including the price of natural gas 
which sets marginal electricity prices. Based on this review, management determined that the carrying value of the Stockton 
Project will not be recovered and recorded a pre-tax long-lived asset impairment of $18,471, which represents the entire value 
of the Project’s property, plant and equipment at December 31, 2008. The Company has extended the PPA through March 2010 
and is also considering a variety of options to recover some of its remaining investment in the Stockton Project. The Stockton 
Project has historically contributed less than 4% of the Company’s distributions received from Projects.

On November 21, 2008, the Company acquired 100% of Auburndale Power Partners, Limited Partnership (“Auburndale”), 
which owns and operates a 155 MW natural gas-ﬁ red combined cycle cogeneration facility located in Polk County, Florida. 
The purchase price was approximately $140 million, including acquisition cost and was funded by cash on hand, a borrowing 
under the Company’s credit facility and $35 million of non-recourse acquisition debt. 

Auburndale is the last of the Projects in which the Company was granted a right of ﬁ rst oﬀ er by ArcLight Energy Partners 
Fund I, L.P. (“ArcLight Fund I”) at the time of the Company’s initial public oﬀ ering. ArcLight Fund I was the majority owner of a 
portion of the project through Pomifer Funding, LLC (“Pomifer”), an entity in which Caisse de dépôt et placement du Québec 
(“CDP”) is a minority owner. ArcLight Fund I is one of the owners of Atlantic Power Management, LLC, the Manager of the 
Company, and CDP owns approximately 19% of the Company’s IPSs and Cdn$36.5 million of its outstanding subordinated 
notes. An independent ﬁ nancial advisor provided a fairness opinion to the independent directors of the Company, given that 
two of the sellers were related parties. The remaining portion of Auburndale was owned by Calpine Corporation (“Calpine”).
On July 18, 2008, the Company approved a normal course issuer bid to purchase up to four million IPSs, representing 
approximately 8% of the Company’s public ﬂ oat. The Toronto Stock Exchange (“TSX”) approved the issuer bid on July 23, 2008, 
and purchases under the bid commenced on July 25, 2008. As of December 31, 2008, the Company had acquired 558,620 IPSs 
at an average price of Cdn$8.78 under the terms of the issuer bid. The issuer bid will terminate on July 24, 2009 or such earlier 
date that the Company has acquired the maximum number of IPSs under the issuer bid. Atlantic Power will pay the market 
price at the time of acquisition for any IPSs purchased and all IPSs acquired under the bid will be canceled.

As previously disclosed since the Company’s IPO, the Onondaga Project was formally taken oﬄ  ine on April 30, 2008, 
although payments continued under the Project’s swap and indexed hedge agreements through June 2008. This plant was 
taken out of service as a result of the relative eﬃ  ciency of its equipment and the regional electricity market. This combination 
of factors is not typical at the Company’s other Projects. The Project sold its gas turbines, spare parts and other equipment. 
Proceeds from these equipment sales in the amount of $7.5 million were received during the year ended December 31, 2008. 
The Company is continuing its eﬀ orts with an experienced developer to redevelop the site into a 35 to 40 MW biomass plant 
and has contributed certain remaining assets of the Onondaga Project to the new joint venture. 

Non-GAAP Financial Measures
Cash Flow Available for Distribution is not a measure recognized under GAAP and does not have a standardized meaning 
prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. Management 
believes Cash Flow Available for Distribution is a relevant supplemental measure of the Company’s ability to earn and distribute 
cash returns to investors. A reconciliation of net cash provided by operating activities from the Company’s ﬁ nancial statements 
to Cash Flow Available for Distribution is set out in the “Cash Flow Available for Distribution” section of this MD&A. Investors are 
cautioned that the Company may calculate this measure in a manner that is diﬀ erent from other companies.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

9

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

Earnings before interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in 
fair value of derivative instruments (“Adjusted EBITDA”) is not a measure recognized under GAAP and does not have a standard-
ized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other issuers. 
Management uses unaudited Adjusted EBITDA at the Projects to provide comparative information about Project performance. 
Investors are cautioned that the Company may calculate this measure in a manner that is diﬀ erent from other companies.

Selected Financial Data (in thousands of U.S. dollars, except as otherwise stated)

(unaudited)  
Project income
Project revenue  
Project expenses  
Project other income (expense)  
Total project income (loss) 

Three months ended 
December 31,  
2007 

2006 

2008 

Years ended
 December 31,
2007 

2008 

2006

88,219 
62,678 
56,073 
81,614 

76,030 
51,219 
(120,241)   
(95,430)   

69,506 
47,454 
(7,447)   
14,605 

  334,221 
  237,383 
35,392 
  132,230 

  306,192 
  204,805 

(214,782)   
(113,395)   

  261,091
  181,753
(22,091)
57,247

Administrative and other expenses
Management fees and administration  
Interest, net  
Distribution, non-controlling interest  
Loss from change in non-controlling interest liability  
Foreign exchange loss (gain) 
Other expenses 
Total administrative and other expenses 
Income (loss) before income taxes  
Income tax expense (beneﬁ t) 
Net income (loss)  

2,489 
9,589 
– 
– 

(27,392)   
(42)   
 (15,356)   
96,970 
18,046 
78,924 

2,574 
10,607 
– 
– 
2,030 
399 
15,610 
(111,040)   
(36,797)   
(74,243)   

1,894 
9,858 
2,029 
1,647 
(5,297) 
287 
10,418 
4,187 
1,253 
2,934 

  10,012 
  43,275 
– 
– 
  (44,719) 
451 
9,019 
  123,211 
12,523 
  110,688 

8,185 
44,282 
– 
– 
30,142 
975 
83,584 
(196,979)   
(47,774)   
(149,205)   

6,367
31,589
15,107
3,691
1,295
1,029
59,078
(1,831)
577
(2,408)

Basic earnings (loss) per share, US$  
Basic earnings (loss) per share, Cdn$  

$  1.30 
$  1.58 

$  (1.21) 
$  (1.19) 

$  (0.06) 
$  (0.06) 

$  1.81 
$  2.20 

$  (2.43) 
$  (2.61) 

$  (0.05)
$  (0.06)

Diluted earnings (loss) per share, US$  
Diluted earnings (loss) per share, Cdn$ 

$  1.20 
$  1.45 

$  (1.21) 
$  (1.19) 

$  (0.05) 
$  (0.06) 

$  1.67 
$  2.03 

$  (2.43) 
$  (2.61) 

$  (0.05)
$  (0.06)

Total assets at December 31 

1,151,590 

  1,081,847 

  1,232,696 

 1,151,590 

  1,081,847 

  1,232,696

Total long-term liabilities at December 31 

826,011 

  881,403 

  847,052 

  826,011 

  881,403 

  847,052

Cash ﬂ ows from operating activities    
Cash distributions declared per IPS, Cdn$ 

42,311 
$  0.27 

47,184 
$  0.27 

23,883 
$  0.27 

  107,243 
$  1.06 

85,901 
$  1.06 

57,521
$  1.04

10 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations for the Three and Twelve-Month Periods Ended December 31, 2008
OVERVIEW
Project income is the primary GAAP measure of the Company’s operating results and is discussed in “Project Operations Perfor-
mance – Three and Twelve-month Periods Ended December 31, 2008” below. In addition, an analysis of non-project expenses 
impacting the results of the Company is set out in “Administrative and Other Expenses” below.

Signiﬁ cant non-cash items, which are subject to potentially signiﬁ cant ﬂ uctuations, include: (1) the change in fair value of 
certain ﬁ nancial instruments that are required by GAAP to be revalued at each balance sheet date (see “Financial Instruments” 
in this MD&A for additional information); (2) the non-cash impact of foreign exchange ﬂ uctuations from period to period on 
the U.S. dollar equivalent of the Company’s Canadian dollar-denominated obligations and (3) currency forward contracts; and 
the related future income tax expense (beneﬁ t) associated with these non-cash items.

Cash ﬂ ow available for distribution was $37,177 and $103,728 for the three and twelve months ended December 31, 2008, 
respectively, compared to $42,305 and $80,116 for the respective comparable periods in 2007. See “Cash Flow Available for 
Distribution” in this MD&A for additional information.

Income before income taxes for the three and twelve months ended December 31, 2008 was $96,970 and $123,211 
respectively, compared to a loss before income taxes of $111,040 and $196,979 for the respective comparable periods in 2007. 
The change reﬂ ects project income of $81,614 and $132,230 during the three and twelvemonths ended December 31, 2008, 
respectively, compared to a project loss of $95,430 and $113,395 for the respective comparable periods in 2007. See “Project 
Income” in this MD&A for additional information. The following table contains signiﬁ cant non-cash and unusual items that 
impacted project income and income before taxes in each period: 

Project income (loss), as reported 
Non-cash and unusual items:
Change in fair value of derivative instruments 
Chambers goodwill impairment 
Stockton long-lived asset impairment 
Gain on settlement of Onondaga gas transportation contract 
Loss on sale of replaced gas turbines at Lake 
Project income (loss), excluding non-cash 
and unusual items noted above 

Income, (loss) before income taxes as reported 
Non-cash and unusual items:
Non-cash and unusual items impacting 

project income from above 

Unrealized foreign exchange loss (gain) 
Income (loss) before income taxes excluding

Three months ended 
December 31,  

Twelve months ended
December 31,

2008 
81,614 

2007  
(95,430) 

 2008 
$  132,230 

2007
$  (113,395)

$ 

$ 

(77,491) 
– 
18,471 
– 
– 

38,730 
71,726 
 – 
– 
8,554 

(55,061) 
– 
18,471 
– 
– 

128,377
71,726
–
(10,040)
8,554 

$ 

22,594 

$ 

23,580 

$ 

95,640 

$ 

85,222

$ 

96,970 

$  (111,040) 

$  123,211 

$  (196,979)

(59,020) 
(27,702) 

119,010 
5,802 

(36,590) 
(36,675) 

198,617
37,716

 non-cash and unusual items 

$ 

10,248 

$ 

13,772 

$ 

49,946 

$ 

39,354

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

11

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

PROJECT INCOME
Project revenue increased 16% to $88,219 and 9% to $334,221 during the three and twelve months ended December 31, 2008, 
respectively. The change in the fourth quarter is attributable to the following factors:
• 
• 
• 
• 

Acquisition of the Auburndale Project in November 2008.
Increased ownership in the Pasco Project that was acquired in December 2007.
Higher revenues at Pasco, Lake and Orlando as a result of higher power prices.
Receipt of a partial settlement of business interruption insurance claims at Orlando related to the unplanned outage 
earlier in 2008.
Higher revenues at Lake as a result of higher volumes of electricity sold when compared to the fourth quarter of 2007 
when the plant was out of service for its gas turbine upgrade.
The absence of revenue at Onondaga as the contracts that provided substantially all of the Project’s cash ﬂ ow expired in 
the second quarter of 2008, as previously disclosed. 

• 

• 

For the year ended December 31, 2008, the change in Project revenue is attributable to the factors described above for the 
fourth quarter and the following other factors from the ﬁ rst nine months of the year:
• 
• 

Higher revenues at Pasco, Lake, Chambers and Badger Creek as a result of higher power prices.
Lower revenue at Mid-Georgia due to lower electricity sales volumes resulting from cooler weather in the third quarter 
of 2008 compared to the third quarter of 2007.

Project expenses increased by $11,459 or 22% during the three months ended December 31, 2008, as compared to the com-
parable quarter, primarily as a result of the following factors:
• 
Acquisition of Auburndale Project in November 2008.
• 
Increased ownership in the Pasco project that was acquired in December 2007.
Higher fuel costs at Pasco as a result of the Project’s consumption of natural gas at market prices following the expiration 
• 
of its fuel supply agreement on June 30, 2008. Beginning January 1, 2009, a new 10-year PPA at the Pasco Project requires 
the PPA counterparty to provide natural gas required to operate the plant and, as a result, the Pasco Project will no longer 
be exposed to changes in market prices of natural gas.

Project expenses for the year ended December 31, 2008 increased by $32,578 or 16%, as a result of the fourth quarter factors 
described above and costs at Onondaga in connection with the shutdown of the plant in April 2008.

Project other income (expense) primarily includes the following items with details provided below:

Change in fair value of derivative instruments 
Impairment of Stockton Project 
Impairment of Chambers goodwill 
Gain on settlement of Onondaga gas transportation contract  
Loss on sale of replaced gas turbines at Lake  

Three months ended 
December 31,  

$ 

2008 
77,491 
(18,471) 
– 
– 
– 

$ 

2007 
(38,730) 
– 
(71,726) 
– 
(8,554) 

$ 

Twelve months ended
December 31,
2008 
55,061 
(18,471) 
– 
– 
– 

2007
$  (128,377)
–
(71,726)
10,040
(8,554)

• 

• 

The non-cash impact of the change in fair value of derivative instruments is primarily related to the accounting treatment 
of the PPA at the Chambers Project as a derivative instrument. The accounting treatment of this PPA does not directly 
impact the amount of cash ﬂ ow that the Chambers Project will receive under the terms of the PPA. See “Financial Instru-
ments” in this MD&A for additional details about the Company’s derivative instruments and other ﬁ nancial instruments. 
In the fourth quarter of 2008, management reviewed the recoverability of its investment in the Stockton Project. The review 
was undertaken as a result of the current status of negotiations to extend the Project’s PPA and the recent deterioration of 
current and long-term market conditions for coal-ﬁ red generation assets in California, including the price of natural gas 
which sets marginal electricity prices. Based on this review, management determined that the value of the Stockton Project 

12 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

will not be recovered and recorded a pre-tax long-lived asset impairment of $18,471, which represents the entire value of 
the Project’s property, plant and equipment at December 31, 2008. The Company has extended the PPA through March 
2010 and is also considering a variety of options to recover some of its remaining investment in the Stockton Project.
In the fourth quarter of 2007, the goodwill at the Chambers Project was written oﬀ  as a result of the signiﬁ cant increase in 
the book value of the reporting unit due to the Project’s PPA being recorded as a ﬁ nancial instrument at fair value.
In the second quarter of 2007, a gain of $10,040 was recorded on the settlement of a gas transportation contract liability 
at the Onondaga Project.
In the fourth quarter of 2007, a loss of $8,554 was recorded on the sale of the gas turbines that were replaced at the Lake 
Project as a result of the installation of new and more eﬃ  cient turbines.

• 

• 

• 

Income from cost and equity method investments decreased in the fourth quarter of 2008 compared to the prior year period 
because of a delay in timing of distributions received from the Selkirk Project as a result of restrictions under the terms of the 
Project’s non-recourse debt. The Project passed the test again beginning in December and management currently believes 
that the remaining restricted cash will become available for distribution in 2009. 

For the twelve-month period ended December 31, 2008, income from cost and equity method investments increased 
signiﬁ cantly due to the receipt of an $8.2 million distribution from the Gregory Project resulting from the release of debt ser-
vice reserves, as well as the absence of an impairment in the Jamaica Project that was recorded in the second quarter of 2007 
related to the sale of that investment.

ADMINISTRATIVE AND OTHER EXPENSES
Management fees and administration includes the costs of operating as a public company, as well as the fees and costs associ-
ated with the Manager. The Manager is indirectly owned by the ArcLight Funds and receives compensation in the form of an 
annual base fee that is indexed to inﬂ ation and an incentive fee that is equal to 25% of the cash distributions to IPS holders in 
excess of Cdn$1.00 per year per IPS. The Company also reimburses the Manager for reasonable costs incurred to manage the 
Company. The increase in management fees and administration for the twelve months ended December 31, 2008 from the 
comparative prior year period is primarily attributable to costs associated with pursuing acquisitions that were not completed 
in the 2008 periods, as well as personnel additions and expense recognized related to awards under the Company’s long-term 
incentive plan that were granted in March 2008 and March 2007.

Interest expense primarily relates to required interest payments to holders of the Subordinated Notes and the Debentures. 
In addition, there were amounts outstanding on the Company’s revolving credit facility during the ﬁ rst half of 2007 related to 
the temporary ﬁ nancing of the acquisition of the Path 15 Project, as well as amounts outstanding as of December 31, 2008 on 
the Company’s revolving credit facility due to the acquisition of Auburndale.

Foreign exchange loss (gain) primarily reﬂ ects the unrealized impact of changes in foreign exchange rates on the U.S. dollar 
equivalent of the Company’s Canadian dollar-denominated obligations to holders of Subordinated Notes and Debentures. In 
addition, unrealized and realized gains and losses on the Company’s forward contracts for the purchase of Canadian dollars to 
satisfy these obligations are included in foreign exchange loss (gain). The U.S. dollar to Canadian dollar exchange rate increased 
by approximately 12.6% during the three months ended December 31, 2008 and increased by approximately 18.6% during 
the year ended December 31, 2008. In the prior year comparative periods, the rate decreased by 0.4% and 17%, respectively. 
See “Financial Instruments” in this MD&A for additional details about the Company’s management of foreign currency risk and 
the components of the foreign exchange gains recognized during the three and twelve months ended December 31, 2008 
compared to the foreign exchange losses in the prior year periods. 

SUPPLEMENTARY FINANCIAL INFORMATION
The key measure used by management to evaluate the results of the Company’s Projects is Cash Flow Available for Distribution. 
See “Cash Flow Available for Distribution” in this MD&A for additional details and for a reconciliation of Cash Flow Available for 
Distribution to its nearest GAAP measure, cash ﬂ ows from operating activities.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

13

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

The primary factor inﬂ uencing Cash Flow Available for Distribution is cash distributions received from the Projects. These 
distributions received are generally funded from Adjusted EBITDA generated by the Projects, reduced by Project-level debt 
service and capital expenditures, and adjusted for changes in Project-level working capital and cash reserves. Please read 
“Non-GAAP Financial Measures” in this MD&A for important disclosures with respect to Cash Flow Available for Distribution 
and Adjusted EBITDA.

Because Project Adjusted EBITDA and Project distributions are key drivers of both the performance of the Company’s 
investments and Cash Flow Available for Distribution, this MD&A contains supplementary unaudited non-GAAP information 
that summarizes Adjusted EBITDA by Project and a reconciliation of Adjusted EBITDA by Project to Project distributions actually 
received by the Company.

Many of the Company’s investments are either proportionately consolidated or accounted for under the cost or equity 
method of accounting in the consolidated ﬁ nancial statements presented in accordance with GAAP. The proportionate con-
solidation method of accounting is applied by recording in the Company’s consolidated ﬁ nancial statements its proportionate 
share of each ﬁ nancial statement account at the proportionately consolidated Project. As a result, some components of the 
Company’s balance sheet contain assets that are not directly available to the Company in the normal course of business, or 
liabilities that are not direct obligations of the Company.

For example, the Company’s proportionate share of cash at a proportionately consolidated Project is reﬂ ected in the 
consolidated balance sheet even though this cash may not be directly controlled by the Company because it is subject to: 
(1) the provisions of the partnership agreement that governs the underlying investment; or (2) in the case of Restricted Cash, 
the non-recourse debt covenants at the Projects. Conversely, the Company’s proportionate share of debt at a proportionately 
consolidated Project is also reﬂ ected in the consolidated balance sheet notwithstanding that all of the Project-level debt at 
the Projects is only secured by assets at the Projects and is non-recourse to the Company.

• 

• 

• 

PROJECT OPERATIONS PERFORMANCE – THREE AND TWELVE MONTHS ENDED DECEMBER 31, 2008
Aggregate Adjusted EBITDA for the Projects, including earnings from projects accounted for under the equity method, 
increased by $2,899 or 7% during the fourth quarter of 2008 compared to the fourth quarter of 2007 and included the 
following factors:
• 
• 

Acquisition of the Auburndale Project in November 2008.
Receipt of a partial settlement of business interruption and property insurance claims at Orlando related to the unplanned 
outage earlier in 2008.
Receipt of a distribution in the fourth quarter of 2008 from the Gregory Project, compared to no distribution from Gregory 
in the prior year fourth quarter.
Increased Adjusted EBITDA at Lake due to higher power prices and higher plant eﬃ  ciency as a result of the turbine 
upgrades performed in the fourth quarter of 2007.
The absence of revenue at Onondaga as the contracts that provided substantially all of the Project’s cash ﬂ ow expired in 
the second quarter of 2008, as previously disclosed. 
A delay in the timing of a portion of the planned distribution from the Selkirk Project in the fourth quarter of 2008 as a result 
of restrictions under the terms of the Project’s non-recourse debt. The Project passed the test again beginning in December 
2008 and management currently believes that the remaining restricted cash will become available for distribution in 2009. 
For the year ended December 31, 2008, Adjusted Project EBITDA increased by $1,849 or 1% during the year ended December 31, 
2008 compared to the comparable period in 2007. In addition to the factors described above for the fourth quarter, the 
year-to-date period included the following factors:
• 

Receipt of an $8.2 million distribution from the Gregory Project in the ﬁ rst quarter of 2008 resulting from releases of debt 
services reserves at that Project.
Higher Adjusted EBITDA at Pasco due to the acquisition of the additional interest in the Project in December 2007 and 
higher power prices, oﬀ set by higher fuel costs as a result of market price purchases following the expiration of its fuel 
supply agreement on June 30, 2008. Beginning January 1, 2009, a new 10-year PPA at the Pasco Project requires the PPA 

• 

• 

14 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

MANAGEMENT’S DISCUSSION AND ANALYSIS

counterparty to provide natural gas required to operate the plant and, as a result, the Pasco Project will no longer be 
exposed to changes in market prices of natural gas.
Absence of Adjusted EBITDA from Jamaica due to the sale of the Project in 2007.

• 
Aggregate power generation for assets in operation at December 31, 2008 was 1.7% lower during the twelve months ended 
December 31, 2008, compared to the same period in 2007. Plant availability declined 2.9% over the same period. Generation 
in the twelve-month period was unfavorably impacted by reductions in generation at Orlando, due to the generator forced 
outage; and at Pasco, as a result of a longer scheduled outage in 2008, versus the same period in 2007. The reduction in gen-
eration was oﬀ set by increased generation at Lake, due to the upgrade of combustion turbines in late 2007; Selkirk, resulting 
from increased dispatch of the plant; and the acquisition of Auburndale in late 2008.

The Project portfolio achieved a weighted average availability of 91.1% for the twelve months ending December 31, 2008, 
versus 94.0% in the same period last year. The lower availability was driven by the forced outage at Orlando and a longer 
scheduled outage at Mid-Georgia versus the previous year. Each of the Projects with reduced availability was nevertheless 
able to achieve 100% of its respective capacity payments as a result of contract terms that provide for certain levels of planned 
and unplanned outages.

Cash Flow from Operating Activities
The Company’s cash ﬂ ow from the Projects may vary from year to year based on, among other things, changes in prices under 
the PPAs, fuel supply and transportation agreements, steam sales agreements and other Project contracts, changes in regulated 
transmission rates, compliance with the terms of non-recourse Project-level ﬁ nancing including debt repayment schedules, 
the transition to market or recontracted pricing following the expiry of PPAs, fuel supply and transportation contracts, working 
capital requirements and the operating performance of the Projects. Project cash ﬂ ows may have some seasonality and the 
pattern and frequency of distributions from the Projects to Holdings during the year can also vary.

The Company’s cash ﬂ ow from operating activities decreased by $4,873 to $42,311 for the three-month period ended 
December 31, 2008 compared to the same period in the prior year. The decrease was primarily attributable to a larger income 
tax refund in the 2007 fourth quarter, partially oﬀ set by the release of debt service reserves at Pasco in the fourth quarter of 
2008 as a result of the ﬁ nal payment of the Project’s debt. In addition, the working capital change in the fourth quarter of 2007 
was positively impacted by the receipt of a full month of third quarter revenues at the Lake and Orlando Projects on the ﬁ rst 
day of the fourth quarter and this timing diﬀ erence did not occur in the fourth quarter of 2008.

Working capital includes restricted cash and trade receivables at the Company’s Projects. Restricted cash ﬂ uctuates from 
period to period in part because non-recourse Project-level ﬁ nancing arrangements typically require all operating cash ﬂ ow 
from the Project to be deposited in restricted accounts and then released at the time principal payments are made on the 
related debt. As a result, the timing of principal payments on Project-level debt causes signiﬁ cant ﬂ uctuations in restricted cash 
balances, which typically beneﬁ t operating cash ﬂ ow in the second and fourth quarters of the year and decrease operating 
cash ﬂ ow in the ﬁ rst and third quarters of the year. 

For the year ended December 31, 2008, cash ﬂ ow from operating activities increased by $21,342, or 25%, to $107,243 
when compared to the 2007 period. The increase for the twelve-month period includes the impact of higher Project Adjusted 
EBITDA and positive working capital changes in the full year 2008 compared to 2007. Signiﬁ cant items contributing to 
the positive impact of working capital on operating cash ﬂ ow in 2008 include the release of Pasco debt service reserves 
throughout the year in a total amount of approximately $13 million, as well as the permanent release of working capital at 
Onondaga that was required to operate the facility.

Cash Flow Available for Distribution
Holders  of  IPSs  receive  cash  distributions  in  the  form  of  interest  payments  on  Subordinated  Notes  and  dividends  on 
Common Shares. Cash ﬂ ow available for distribution in the three months and twelve months ended December 31, 2008 
increased (decreased) by $(5,128) and $23,612, respectively, when compared the same periods in 2007 due to primarily the 
changes in cash ﬂ ow from operating activities described above. 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

15

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

The Company periodically evaluates its level of dividends with its Board of Directors by analyzing long-term cash ﬂ ow 
projections, as well as the accretion to cash ﬂ ow provided by acquisitions. On November 21, 2008, in connection with the 
closing of the Auburndale acquisition, the Company announced an increase of Cdn$.034 per share in the annual common 
share dividend. The increase was applicable to holders of record beginning on December 31, 2008 and brings the total annual 
distribution, including the interest payments on the Subordinated Notes component of the IPS, to Cdn$1.094 per IPS.

The table below presents the Company’s calculation of Cash Available for Distribution for the three and twelve months 

ended December 31, 2008 and 2007.

(In thousands of U.S. dollars, except as otherwise stated) 

(unaudited)  
Cash ﬂ ows from operating activities  
Project-level debt repayments 
Interest on IPS portion of Subordinated Notes  
Purchase of property, plant and equipment  
Cash Flow Available for Distribution2, US$  

Interest on IPS Subordinated Notes  
Dividends on IPS Common Shares  
Total IPS distributions, US$ 

Three months ended  
December 31, 

2008 
42,311 
(13,584) 
7,923 
527 
37,177 

7,923 
5,463 
13,386 

20071 
47,184 
(13,156)  
9,968  
(1,691)  
42,305 

9,968 
6,693 
16,661 

Twelve months ended
December 31,
2008 
  107,243 
(38,277) 
36,560 
(1,798) 
  103,728 

20071
85,901
(37,581)
36,726
(4,930)
80,116

36,560 
24,693 
61,253 

36,726
24,662
61,388

Payout ratio 

36% 

39% 

59% 

77%

Cash Flow Available for Distribution per IPS, US$
Basic 
Diluted 
Total distribution declared per IPS, US$  

Cash Flow Available for Distribution, Cdn$ 
Total IPS distributions, Cdn$ 

Cash Flow Available for Distribution per IPS, Cdn$ 
Basic 
Diluted 
Total distribution declared per IPS, Cdn$  

$  0.61 
$  0.59 
$  0.22 

45,065 
16,328 

$  0.69 
$  0.66 
$  0.27 

$  1.69 
$  1.62 
$  1.00 

41,542 
16,295 

  110,719 
65,143 

$  0.74 
$  0.71 
$  0.27 

$  0.68 
$  0.65 
$  0.27 

$  1.81 
$  1.73 
$  1.06 

$  1.30
$  1.26
$  1.00

86,005
65,181

$  1.40
$  1.35
$  1.06

1 

2 

Amounts previously reported in 2007 have been revised to conform to the calculation of Cash Available for Distribution adopted in 2008, which 
does not include any adjustment for income taxes recoverable. Through the end of 2007, the Company was required to pay tax instalments based 
on estimates of taxable income without the beneﬁ t of the interest deduction related to the Subordinated Notes and Debentures. This require-
ment resulted in the payment of signiﬁ cant tax instalments to the IRS, followed by a refund of most of the instalment payments when the actual 
tax returns were ﬁ led in subsequent periods with the full beneﬁ t of the interest deductions on the Subordinated Notes and Debentures. As of 
January 1, 2008, the Company is permitted to calculate tax instalment payments with the full beneﬁ t of these interest payments factored into 
estimated taxable income. As a result, management expects signiﬁ cant ﬂ uctuations in working capital related to tax instalments and subsequent 
refunds to decrease and the adjustment to Cash Flow Available for Distribution is no longer needed. 
Cash Flow Available for Distribution 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 issuers. See “Non-GAAP Financial Measures”.

16 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

Three months ended December 31, 
2008 
42,311 
78,924 

$ 

Years ended December 31,
2007 
85,901 
(149,205) 

$ 

$ 

2006
57,521
(2,408)

2008 
$  107,243 
  110,688 

7,923 
5,463 

36,848 
73,461 

36,560 
24,693 

82,550 
85,995 

36,235 
24,665 

26,464
16,985

61,236 
(173,870) 

40,536
(19,393)

Discussion of Distributable Cash

Cash ﬂ ows from operating activities (A) 
Net income (loss) (B) 
Actual cash distributions paid  

Interest on subordinated notes 
Dividends (C) 

Excess of cash ﬂ ows from 

operating activities over dividends paid (A-C) 

Excess (shortfall) of net income over dividends paid (B-C) 

As illustrated in the table above, the Company has historically generated substantially more cash ﬂ ows from operating 
activities than it has paid in dividends. The interest and dividend payments in the table above are expressed in U.S. dollars but 
are paid in Canadian dollars. The payments in the table do not reﬂ ect the impact of the Company’s contracts for forward 
purchases of Canadian dollars at exchange rates that were signiﬁ cantly more favorable than current levels of currency 
exchange rates during the periods presented above through approximately September 2008. In the fourth quarter of 2008, 
the Canadian dollar weakened signiﬁ cantly when compared to the U.S. dollar and the exchange rates were more consistent 
with the rates in the Company’s forward currency contracts. See “Financial Instruments” in this MD&A for additional details 
about the Company’s forward currency contracts.

The Company periodically evaluates its level of cash dividends with its Board of Directors by analyzing long-term cash 
ﬂ ow projections, as well as the accretion to cash ﬂ ow provided by acquisitions. In addition, the Company maintains cash on 
hand for acquisitions and other growth opportunities at existing Projects.

Net income (loss) includes large non-cash ﬂ uctuations in the fair value of derivative instruments which do not aﬀ ect cash 
ﬂ ows that may be distributed to shareholders. Excluding the change in fair value of derivative instruments, net income (loss) 
for the three and twelve months ended December 31, 2008 would have been $32,428 and $77,651, respectively. Accordingly, 
management does not view the comparison of net income (loss) to cash dividends to be a meaningful measure of the 
Company’s historical or future ability to pay cash dividends to its shareholders.

Management believes that its calculation of Cash Flow Available for Distribution on the previous page provides meaningful 

information about the Company’s ability to pay dividends from cash generated by the operations of its operating assets.

Summary of Quarterly Results
Variations in quarterly results are driven by the following factors:
• 

• 

• 

Seasonality of Project revenues created by seasonal variances in demand for electric power, in some cases varied seasonal 
pricing for portions of the PPA payments and the typical scheduling of major facility maintenance in the spring and fall.
Variations in cash ﬂ ow may also be driven by the timing of quarterly and semi-annual Project-level debt payments, 
as distributions from the Projects to the Company must occur in conjunction with passing certain tests at those payment 
dates.
Non-cash charges, principally: (1) the change in fair value of certain ﬁ nancial instruments that are required by GAAP to 
be revalued at each balance sheet date (see “Financial Instruments” in this MD&A for additional information) and (2) the 
non-cash portion of the foreign exchange gain or loss, reﬂ ecting the impact of foreign exchange ﬂ uctuations from period 
to period on the U.S. dollar equivalent of the Company’s Canadian dollar-denominated debt and the mark-to-market value 
of currency forward contracts.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

17

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

The table below presents selected quarterly consolidated ﬁ nancial data for the eight most recently completed ﬁ scal quarters. 

(in thousands of U.S. dollars, except as otherwise stated)

Project revenues 
Net income (loss) 
Cash ﬂ ow from operating activities 
Cash distributions 
Cash available for distribution 
Payout ratio 
Per IPS statistics 
Net income (loss) – basic 
Net income (loss) – diluted 
Cash ﬂ ow from operating activities 
Cash available for distribution, US$ 
Cash available for distribution, Cdn$ 
Distributions, US$ 
Distributions, Cdn$ 

20071 

2008

Q1 
72,933 
(32,047) 
18,782 
13,964 
21,021 
66% 

Q2 
75,841 
(24,188) 
11,927 
15,069 
4,816 
313% 

Q3 
81,387 
(18,728) 
8,007 
15,695 
11,975 
131% 

Q4 
76,030 
(74,243) 
47,184 
16,661 
42,305 
39% 

Q1 
80,028 
5,665 
27,429 
16,221 
29,812 
54% 

Q2 
81,830 
(40,055) 
30,328 
16,197 
27,219 
60% 

Q3 
84,145 
66,166 
7,176 
15,448 
9,520 
162% 

Q4
88,219
78,924
42,311
13,386
37,177
36%

(0.52) 
(0.52) 
0.31 
0.34 
0.40 
0.23 
0.27 

(0.39) 
(0.39) 
0.19 
0.08 
0.09 
0.25 
0.27 

(0.30) 
(0.30) 
0.13 
0.19 
0.20 
0.26 
0.27 

(1.21) 
(1.21) 
0.77 
0.69 
0.68 
0.27 
0.27 

0.09 
0.09 
0.45 
0.48 
0.49 
0.26 
0.27 

(0.65) 
(0.65) 
0.49 
0.44 
0.45 
0.26 
0.27 

1.08 
1.00 
0.12 
0.16 
0.16 
0.25 
0.26 

1.30
1.20
0.69
0.61
0.74
0.22
0.27

1 

Certain 2007 ﬁ gures have been reclassiﬁ ed to conform to the ﬁ nancial statement presentation adopted in 2008.

Liquidity and Capital Resources
OVERVIEW
The Company’s primary source of cash and cash equivalents is distributions from the Projects. A signiﬁ cant portion of the 
cash received from Project distributions is distributed in the form of interest and dividends to holders of the IPSs, the separate 
Subordinated Notes and the Debentures. The Company may fund future acquisitions with a combination of cash on hand, the 
issuance of additional debt or equity securities and the incurrence of privately-placed bank or institutional debt.

Management believes that the Company will be able to generate suﬃ  cient amounts of cash and cash equivalents to 
maintain the Company’s operations and meet obligations as they become due. The Company’s cash on hand and projected 
future cash ﬂ ows are adequate to meet the current level of cash distributions to IPS holders into 2015 before considering any 
positive impact from potential acquisitions or organic growth opportunities. 

Management does not expect any material unusual requirements for cash outﬂ ows in 2009 for capital expenditures or 
other required investments. In addition, there are no debt instruments with signiﬁ cant maturities or reﬁ nancing requirements 
expected in 2009. See “Outlook” in this MD&A for information about changes in expected distributions from the Company’s 
Projects in 2009.

CREDIT FACILITY
The Company maintains a credit facility with a capacity of $100 million, $50 million of which may be utilized for letters of credit. 
The credit facility matures in August 2012.

Outstanding amounts under the credit facility bear interest at the London Interbank Oﬀ ered Rate (“LIBOR”) plus an 
applicable margin between 0.875% and 1.625% that varies based on the credit ratio of a subsidiary of the Company. At 
December 31, 2008, the applicable margin is currently 0.875%.

As of December 31, 2008, $36,442 was allocated, but not drawn, to support letters of credit for contractual credit support 
at several Projects. In November 2008, the Company borrowed $55,000 under the credit facility and used the proceeds to 
partially fund the acquisition of Auburndale. The Company has executed an interest rate swap to ﬁ x the interest rate at 3.3% 
through November 2011 for $40 million of this borrowing.

18 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

The Company must meet certain ﬁ nancial covenants under the terms of the credit facility, which are generally based on 
the Company’s cash ﬂ ow coverage ratios and not on balance sheet ratios. The facility is secured by pledges of assets and 
interests in certain subsidiaries. The Company expects to be in compliance with the covenants of the credit facility for at least 
the next 12 months.

Management expects to reﬁ nance and increase the size of the term loan at Auburndale within the next 12 to 24 months and 
will use a portion of the proceeds from the reﬁ nancing to repay borrowings under the credit facility, although the reﬁ nancing is 
not required under either the credit facility or the existing non-recourse Project loan. In addition, the Company may use excess 
operating cash ﬂ ow to periodically reduce borrowings under the credit facility.

PROJECT-LEVEL DEBT
The following table summarizes the maturities of Project-level debt in thousands of U.S. dollars. The amounts represent the 
Company’s proportionate share of the non-recourse Project-level debt balances at December 31, 2008 and exclude any 
purchase accounting adjustments recorded to adjust the debt to its fair value at the time the Project was acquired by the 
Company. Certain of the Projects have more than one tranche of debt outstanding with diﬀ erent maturities, diﬀ erent 
interest rates and/or debt containing variable interest rates. The range of interest rates presented represents the rates in 
eﬀ ect at December 31, 2008.

Total
Remaining
Principal
Repayments 

Range of 
Interest Rates 

2009 

2010 

2011 

2012 

2013  Thereafter

Consolidated and 
  proportionately 
  consolidated Projects:

Chambers 
Path 15 
Mid-Georgia 
Topsham 
Auburndale1 

2.8%-8.4% 
7.9%-9.0% 
5.0%-9.0% 
9.5% 
4.1% 

134,146 
168,867 
39,661 
45 
35,000 

10,568 
7,508 
2,891 
45 
3,500 

12,051 
7,480 
3,161 
– 
9,800 

12,794 
7,987 
3,562 
– 
9,800 

13,676 
8,667 
3,963 
– 
7,000 

13,783 
9,402 
4,143 
– 
4,900 

71,274
127,823
21,941
–
–

Total consolidated and 
  proportionately consolidated Projects 

Equity and 
  cost method Projects:

377,719 

24,512 

32,492 

34,143 

33,306 

32,228 

221,038

Delta-Person 
Selkirk 
Gregory 
Total equity and cost method Projects 
Total all Projects 

2.8% 
9.0% 
5.3%-6.0% 

13,594 
31,997 
18,942 
64,533 
442,252 

1,098 
8,122 
1,668 
10,888 
35,400 

1,147 
8,247 
1,757 
11,151 
43,643 

1,220 
10,188 
1,901 
13,309 
47,452 

1,308 
5,440 
2,044 
8,792 
42,098 

1,403 
– 
2,205 
3,608 
35,836 

7,418
–
9,367
16,785

237,823

1 

In addition to the amount in this table, as of December 31, 2008, the Company has $55 million outstanding on its credit facility incurring interest 
at a rate of 1.8% for the unhedged portion and 3.3% for the hedged portion related to the acquisition of Auburndale on November 21, 2008.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

19

 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

RESTRICTED CASH
The Projects generally have reserve requirements to support payments for major maintenance costs and project-level debt 
service. For Projects that are consolidated or proportionately consolidated with Atlantic Power, these amounts, or Atlantic 
Power’s portion of these amounts, are reﬂ ected as Restricted Cash on the Company’s consolidated balance sheet. 

At December 31, 2008, Restricted Cash at consolidated and proportionately consolidated Projects totaled $25.4 million. 
All project-level debt is non-recourse to the Company and substantially all of the principal is amortized over the life of the 
Projects’ PPAs.

CONTRACTUAL OBLIGATIONS
Contractual obligations of the Company as at the period ended December 31, 2008 are presented in the table below.

Long-term debt, including current portion (a) 
Subordinated notes (b) 
Convertible debentures (c) 
Head oﬃ  ce lease (d) 
Total contractual obligations 

Total 
$  432,719 
320,974 
49,261 
1,857 
$  804,811 

2009 
$  79,5121 
– 
– 
280 
79,792 

$ 

Payments due by period
2010-2011 
66,635 
$ 
– 
49,261 
579 
$  116,475 

2012-2013 
65,534 
$ 
– 
– 
607 
66,141 

$ 

Thereafter
$  221,038
320,974
–
391
$  542,403

1 

The $55 million outstanding on the Company’s credit facility may be extended, at the Company’s option, until the maturity of the credit facility in 
August 2012.

(a)  Long-Term Debt, including current portion

Long-term debt represents the Company’s consolidated and proportionately consolidated share of Project long-term 
debt and amounts outstanding under the Company’s credit facility. The amount presented excludes the net unamortized 
purchase price adjustment of $12,756 related to the fair value of debt assumed in the Path 15 acquisition. Project debt is 
non-recourse to the Company and is amortized during the term of the respective revenue generating contracts of the 
Projects. The range of interest rates on long-term Project debt at December 31, 2008 was 2.06% to 9.5%.

(b)  Subordinated Notes

As of December 31, 2008, the Company had $320,974 outstanding principal amount of Subordinated Notes due 2016. 
The notes pay interest only at a rate of 11% until their maturity.

(c)  Convertible Debentures

The Debentures pay interest semi-annually on April 30 and October 31 each year, commencing on April 30, 2007. The 
Debentures mature on October 31, 2011 and are convertible into approximately 80.6452 IPSs per Cdn$1,000 principal 
amount of Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per IPS.

(d)  Head offi  ce lease

Pertains to the lease payments associated with the Company’s Boston, MA head oﬃ  ce lease entered into on April 1, 2007 
and expires on March 31, 2015.

20 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

PROJECT CONTRACTS
Each Project typically has a set of contracts that includes obligations of the Project partnerships, all of which are non-recourse 
to the Company. Therefore, speciﬁ c contracts for individual Projects are not discussed in detail in the MD&A or included in the 
Contractual Obligations table above. The following are general characteristics of the typical contracts at the Projects:
• 

PPAs typically provide for capacity payments based on plant availability and energy payments based on actual generation. 
They generally allow Projects to pass through their fuel costs. See the table in the “Project Portfolio” section in this MD&A 
with respect to oﬀ -takers and durations.
Fuel supply agreements.
Fuel transportation agreements may incorporate capacity reservation/demand payments for natural gas or shipping cost 
per ton of coal.
Steam sales agreements typically have a tenor that matches that of the related PPA and are designed to meet regulatory 
requirements for thermal load/eﬃ  ciency at fossil fuel plants.
Operating and maintenance agreements for services provided by third parties or owners.
Long-term service agreements may be in place for gas or steam turbine inspections and overhauls.
Site lease agreements grant use of project land where Projects do not own the site.

• 
• 
• 
Further information about the Projects’ agreements is contained in the Company’s annual information form dated March 30, 
2009, which is available on SEDAR’s website at www.sedar.com.

• 
• 

• 

Information Regarding Guarantors
The Subordinated Notes and the Debentures are secured by a pledge of the Company’s membership interests in Holdings 
and are guaranteed by Holdings and Teton Power Funding, LLC, Epsilon Power Funding, LLC, MP Power LLC, Teton East Coast 
Generation LLC, Teton Fuels Mid-Georgia LLC, Teton Selkirk LLC, Badger Power Generation I LLC, Badger Power Generation II 
LLC, Baker Lake Hydro LLC, Dade Investment, L.P., Geddes II Company LLC, Geddes Cogeneration Company LLC, MEP Rumford, 
LLC, NCP Dade Power LLC, NCP Houston Power LLC, NCP Pasco LLC, NCP Perry LLC, Olympia Hydro LLC, Onondaga Cogenera-
tion  Limited  Partnership,  Orlando  Power  Generation  I  LLC,  Orlando  Power  Generation  II  LLC,  Stockton  Cogen  (II)  LLC, 
Teton Operating Services, LLC and Teton New Lake, LLC (the ‘‘Guarantors’’). The guarantee of Holdings is secured by a pledge 
of its membership interests in Teton Power Funding, LLC and Epsilon Power Funding, LLC and the guarantees of certain of 
the Guarantors are secured by pledges of the membership interests or other securities they hold in subsidiary entities subject 
to the provisions of agreements governing or aﬀ ecting interests in such subsidiaries which may restrict or prevent pledges 
in certain cases.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

21

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

The consolidated ﬁ nancial statements of the Company include the consolidated ﬁ nancial results of the Company and 
its guarantor and non-guarantor subsidiaries. Summary unaudited consolidated ﬁ nancial information of the Company, the 
Guarantors and the non-guarantor subsidiaries of the Company as at and for the twelve-month period ended December 31, 2008 is 
presented in the table below in thousands of U.S. dollars. The selected ﬁ nancial information for the Company and for the Guarantors 
includes certain investments in subsidiaries accounted for on a cost basis and is therefore not presented in accordance with GAAP. 

Atlantic  
Power 
Corporation 

Non-

Guarantor 
Subsidiaries 

Guarantor   Consolidation
Subsidiaries  Adjustments 

Consolidated

Income Statement – 

Year Ended December 31, 2008

Project revenue  
Project expenses  
Project other income (expense)  
Project income (loss) 
Dividends received 
Administrative and other expenses  
Income (loss) before income taxes 
Income taxes  
Income (loss)  

Balance sheet – December 31, 2008
Current assets  
Investments in guarantor subsidiaries 
Investment in non-guarantor subsidiaries 
Other non-current assets  
Total non-current assets 
Total assets 
Current liabilities 
Non-current liabilities 
Shareholders’ equity 
Total liabilities and shareholders’ equity 

– 
– 
(161) 
(161) 
65,715 
(38,674) 
104,228 
28,022 
76,206 

(17,144) 
588,626 
– 
(2,323) 
586,303 
569,159 
12,383 
425,603 
131,173 
569,159 

11,773 
44 
5,909 
17,638 
124,489 
47,693 
94,434 
(141) 
94,575 

64,009 
– 
604,457 
1,898 
606,355 
670,364 
64,794 
16,944 
588,626 
670,364 

322,448 
237,339 
29,644 
114,753 
– 

114,753 
(15,358) 
130,111 

122,777 
– 
– 
938,784 
938,784 
1,061,561 
73,640 
383,464 
604,457 
1,061,561 

– 
– 
– 
– 
(190,204) 
– 
(190,204) 
– 
(190,204) 

(20,177) 
(588,626) 
(604,457) 
63,766 
(1,129,317) 
(1,149,494) 
(20,177) 
– 
(1,129,317) 
(1,149,494) 

334,221
237,383
35,392
132,230
–
9,019
123,211
12,523
110,688

149,465
–
–
1,002,125
1,002,125
1,151,590
130,640
826,011
194,939
1,151,590

22 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

Project Portfolio
The following table outlines the Company’s portfolio of power generating and transmission assets as of March 30, 2009 including its interest 
in each facility. Management believes the portfolio is well diversiﬁ ed based on electricity and steam buyers, fuel type, regulatory jurisdictions 
and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions speciﬁ c to any single region.

Project 
Name 
Auburndale  
Badger Creek 
Chambers 

Primary 
Location  
Florida  
California  
New Jersey 

Fuel  
Type  
Natural gas  
Natural gas  
Coal 

Delta-Person 
Gregory  

New Mexico 
Texas  

Natural gas  
Natural gas  

Washington   Hydro  

C 
P  
P 

Interest1  
100.0%  
50.0%  
40.0% 

Total   Ownership  Acctg   Net  
Tmt2   MW3  
MW  
155 
155  
23  
46 
894 
262 
16  
53  
59  
9  
6  

40.0%5  
17.1%  

E  
Cost  

132  
400  

49.8%  

13  

P  

Koma 
Kulshan
Lake  
Mid-Georgia  
Orlando 

Florida  
Georgia  
Florida 

Natural gas  
Natural gas  
Natural gas 

121  
308  
129 

100.0%  
50.0%  
50.0% 

C   121 
P   154  
46  
P 
19  

Pasco  
Path 15  

Florida  
California  

Natural gas  
Transmission  

121  
N/A 8  

100.0%  
100.0%  

P   121 
C   N/A 8  

Rumford  
Selkirk  

Maine  
New York  

Coal/biomass  
Natural gas  

85  
345  

E  
23.5%5  
18.5%5   Cost  

Stockton  

California  

Coal  

Topsham6  

Maine  

Hydro  

55  

14  

50.0%  

50.0%  

P  

P  

20  
49  
15  
24  
3  
7  

Electricity  
Oﬀ -Taker  
Progress Energy Florida  
Paciﬁ c Gas & Electric  
Atlantic City Electric  
DuPont  
PNM  
Fortis 
Sherwin Alumina  
Puget Sound Energy  

Progress Energy Florida 
Georgia Power  
Progress Energy Florida  
Reedy Creek  
Improvement District 
TECO 
California Utilities via  
CAISO 7 
Rumford Paper Co.  
Consolidated Edison  
Merchant 
Paciﬁ c Gas & Electric  
Corn Products Int’l  
Central Maine Power  

Oﬀ -Taker
S&P Credit
Rating
BBB +
BBB+
BBB
A
BB-
A-

PPA 
Expiry  
2013 
2011  
2024  
2024  
2020  
2013 
2020   N/R
BBB
2037  

2013  
2028  
2023  
2013  

BBB+
A
BBB+
A-10

2018 
N/A8 

BBB-
BBB+
to A9
2009   N/R
2014  
N/A 
2010 
2010  
2011  

A-
N/A 
BBB+
BBB
BBB+

5 
6 
7 

1 
2 
3 
4 

Except as otherwise noted, economic interest represents the percentage ownership interest in each Project held indirectly by the Company.
Accounting treatment: C – Consolidated; P – Proportionate consolidation; E – Equity method; Cost – Cost method.
Represents the interest of the Company in each Project’s electricity generation capacity based on the Company’s economic interest.
Includes separate power sales agreement in which the Project and Atlantic City Electric (“ACE”) share proﬁ ts on merchant sales of electricity 
not purchased by ACE under the base PPA.
Represents the Company’s estimate of its share of the cash ﬂ ow from the project.
The Company owns its interest in this Project as a lessor.
California utilities pay Transmission Access Charges (“TACs”) to California Independent System Operator (“CAISO”), which allocates the 
payments among owners of transmission and Transmission System Rights, such as Path 15, in accordance with the Project’s FERC-approved 
annual revenue requirement.
Path 15 is an 84-mile, 500-kilovolt transmission line in California. The Project is a FERC-regulated asset with a FERC-approved regulatory 
life of 30 years, through 2034.
The largest payers of TACs supporting Path 15’s annual revenue requirement and their S&P credit ratings are PG&E (BBB+), 
SoCal Ed (BBB+) and SDG&E (A). CAISO imposes minimum credit quality requirements of A or better for all participants unless collateral 
is posted per CAISO imposed schedule.
10  Rating from Fitch of Reedy Creek bonds.

9 

8 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

23

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

Capital Expenditures
Capital expenditures for the Projects are generally made at the Project level using Project cash ﬂ ows and Project reserves. 
Therefore, the distributions that Holdings receives from the Projects are made net of capital expenditures needed at the 
Projects. The Company has only injected funds into the Projects for signiﬁ cant elective upgrades to output and eﬃ  ciency. 
The  Projects  in  which  the  Company  has  investments  generally  consist  of  large  capital  assets  that  have  established 
commercial operations. Ongoing capital expenditures for assets of this nature are generally not signiﬁ cant because most major 
expenditures relate to planned repairs and maintenance and are expensed when incurred.

In 2009, several of the Projects have planned outages to complete major maintenance work that will prolong the life, and 
ensure eﬃ  cient and reliable operation of the assets. Major overhaul inspections are planned at Badger, Chambers and Selkirk. 
The  principal  maintenance  activity  at  Chambers  will  be  a  major  overhaul  of  the  Project’s  steam  turbine  which  occurs 
approximately every eight years. Please refer to “Outlook” in this MD&A for details of impacts to distributions expected from 
the Project. Selkirk will be conducting major overhaul inspections of two of its three gas turbines. Both Chambers and Selkirk 
have reserves that are funded from operating cash ﬂ ow in anticipation of major maintenance expenditures. Reserve withdraw-
als cover a substantial portion of the actual maintenance costs. Typically, Selkirk is able to fully mitigate lost operating margin 
through the resale of natural gas not consumed. Major maintenance costs associated with the major gas turbine overhaul at 
Badger are paid for by the operator of the plant based on a levelized O&M fee they are paid by the Project. A minor inspection 
and overhaul is currently underway at Gregory and a minor inspection and overhaul is scheduled for later in the year at 
Auburndale. Both Gregory and Auburndale have long-term service agreements in place with steady payments over time that 
cover a substantial portion of the overhaul cost. Each of the Projects conducts maintenance activities during periods of the 
year when impacts to the Project’s margin on energy sales and contractual availability requirements can be minimized.

Related Party Transactions
The Manager has been engaged under the Management Agreement to provide certain management and administrative 
services to the Company, for which it is paid: (1) a base management fee ($356 for 2008), which is adjusted annually for inﬂ ation 
and when acquisitions increase the scope of the Manager’s responsibilities under the agreement; (2) a reimbursement of costs; 
and (3) an incentive fee equal to 25% of the excess in distributions paid to IPS holders and Former Investors during the year 
above Cdn$1.00 per IPS ($864 in 2008). The Management Agreement has an initial term of 20 years expiring in 2024. In addition, 
the Path 15 Project directly pays the Manager an annual fee of $266, which is subject to adjustment for inﬂ ation.

The Manager receives administrative and oﬃ  ce support services from ArcLight under a management support agreement 
executed in November 2004 among the Manager, ArcLight and the Company. This agreement also requires the ArcLight Funds 
and their aﬃ  liates to give the Manager the opportunity to pursue, on behalf of the Company, investment opportunities that do 
not ﬁ t within the investment guidelines for the ArcLight Funds or other investment funds managed by ArcLight or its aﬃ  liates.
The Manager is owned indirectly by subsidiaries of the ArcLight Funds, which in conjunction with a subsidiary of 
Caithness, owned 41.9% of Holdings’ common membership interest immediately after the IPO, but reduced their interest 
to 29.9% in October 2005 and further reduced their interest to approximately 14% in October 2006. In February 2007, the 
Company acquired all of the remaining interest of the Former Investors in Holdings. 

On November 21, 2009, the Company acquired Auburndale from an entity owned by the ArcLight Funds and CDP. 

See “Recent Developments” in this MD&A for additional details.

Critical Accounting Estimates
The preparation of ﬁ nancial statements requires management to make estimates and assumptions that aﬀ ect the reported 
amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the ﬁ nancial statements 
and the reported amounts of revenues and expenses during the period. Actual results could diﬀ er from those estimates. During 
the periods presented, management has made a number of estimates and valuation assumptions, including the fair values 
of acquired assets, the useful lives and recoverability of property, plant and equipment and PPAs, the recoverability of equity 

24 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

MANAGEMENT’S DISCUSSION AND ANALYSIS

investments, the recoverability of future tax assets and the fair value of ﬁ nancial instruments and derivatives. The accounting 
policies that are most impacted by management estimates are related to ﬁ nancial instruments and impairment of long-lived 
assets and equity investments.

The Company’s accounting policy related to ﬁ nancial instruments includes material non-cash income and losses related 
to changes in the fair value of derivative instruments, particularly the Chambers PPA and forward contracts for purchases of 
Canadian dollars to pay the Company’s Canadian dollar obligations. Management’s estimate of the fair value of the Chambers 
PPA at each balance sheet date is measured by comparing the net present value of the cash ﬂ ows expected to be received 
under the terms of the PPA to the net present value of the cash ﬂ ows that would be received if the same volumes were sold 
at projected market power prices over the term of the contract expiring in 2024. Changes in forward market conditions are 
sometimes signiﬁ cant from period to period and have a material impact on the estimated fair value of the PPA but do not 
directly impact the amount of cash ﬂ ow the Chambers Project will receive under the terms of the PPA. 

The Company’s accounting policy for impairment of long-lived assets and equity investments requires management 
to periodically assess whether changes in events or circumstances at an operating Project or equity investment require an 
impairment test. When management determines that an impairment test is required, the future projected cash ﬂ ows from 
the operating Project or equity investment are the most signiﬁ cant factor in determining whether an impairment exists and, 
if so, the amount of the impairment charge. Management uses its best estimates of market prices of power and fuel and its 
knowledge of the operations of the Project and its related contracts when developing these cash ﬂ ow estimates. In addition, 
when determining fair value using discounted cash ﬂ ows, the discount rate used can have a material impact on the fair value 
determination. Discount rates are based on management’s risk of the cash ﬂ ows in the estimate, including when applicable, 
the credit risk of the counterparty that is contractually obligated to purchase electricity or steam from the Project. No signiﬁ cant 
changes in the method used to measure accounting estimates have occurred since December 31, 2007.

Changes in Accounting Policies
FINANCIAL INSTRUMENTS – PRESENTATION AND DISCLOSURE
Eﬀ ective January 1, 2008, the Company adopted Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3862, 
“Financial Instruments – Disclosures” and Handbook Section 3863, “Financial Instruments – Presentation”.

Section 3862 requires entities to provide disclosures in their ﬁ nancial statements that enable users to evaluate the 
signiﬁ cance of ﬁ nancial instruments on the entity’s ﬁ nancial position and its performance and the nature and extent of risks 
arising from ﬁ nancial instruments to which the entity is exposed during the period and at the balance sheet date, and how 
the entity manages those risks.

Section 3863 establishes standards for presentation of ﬁ nancial instruments and non-ﬁ nancial derivatives. It deals with 
the classiﬁ cation of ﬁ nancial instruments, from the perspective of the issuer, between liabilities and equity, the classiﬁ cation 
of related interest, dividends, losses and gains, and circumstances in which ﬁ nancial assets and ﬁ nancial liabilities are oﬀ set.
The adoption of these standards did not have any impact on the classiﬁ cation and valuation of the Company’s ﬁ nancial 
instruments. The  new  disclosures  pursuant  to  these  new  Handbook  Sections  are  included  in  Note  14  to  the  Audited 
Consolidated Financial Statements for the year ended December 31, 2008.

CAPITAL DISCLOSURES
Eﬀ ective January 1, 2008, the Company adopted the new recommendations of the CICA Handbook Section 1535, “Capital 
Disclosures”. This new Handbook Section establishes standards for disclosing information about an entity’s capital and how 
it is managed. It requires the disclosure of information about an entity’s objectives, policies and processes for managing 
capital. These new disclosures are included in Note 15 to the Audited Consolidated Financial Statements for the year ended 
December 31, 2008.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

25

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

RECENTLY ISSUED ACCOUNTING STANDARDS
In February 2008, the Canadian Accounting Standards Board announced the adoption of International Financial Reporting 
Standards (“IFRS”) for publicly accountable enterprises in Canada. Eﬀ ective January 1, 2011, the Company will be required to 
convert from Canadian GAAP to IFRS. Management has begun to develop plans to implement the new standards and cannot 
at this time reasonably estimate the impact of adopting IFRS on the Company’s consolidated ﬁ nancial statements.

CICA Handbook Section 3064, “Goodwill and Intangible Assets”, establishes standards for recognition, measurement, 
presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets. Standards concerning 
goodwill are unchanged from the standards included in the previous CICA Handbook Section 3062. The Company will adopt 
the new Handbook Section on January 1, 2009 and is currently assessing the impact that the adoption of these standards will 
have on its consolidated ﬁ nancial statements. 

On January 20, 2009 the Emerging Issues Committee (“EIC”) of the CICA issued EIC-173, “Credit Risk and the Fair value of 
Financial Assets and Financial Liabilities”, which clariﬁ es that an entity’s own credit risk and the credit risk of the counterparty 
should be taken into account in determining the fair value of ﬁ nancial assets and liabilities, including derivative instruments. 
EIC-173 is to be applied retrospectively without restatement of prior periods in interim and annual ﬁ nancial statements for 
periods ending on or after the date of issuance of EIC-173. The Company will adopt this recommendation in its fair value deter-
minations as of March 31, 2009 and is currently assessing the impact of this change on its consolidated ﬁ nancial statements.
In January 2009, the CICA issued CICA Handbook Section 1582, “Business Combinations”, Section 1601, Consolidations”, 
and Section 1602, “Non-controlling Interests”. These sections replace the former CICA Handbook Section 1581, “Business 
Combinations” and Section 1600, “Consolidated Financial Statements” and establish a new section for accounting for a 
non-controlling interest in a subsidiary.

CICA Handbook Section 1582 establishes standards for accounting for a business combination. It provides the Canadian 
equivalent to IFRS 3, “Business Combinations” (January 2008). The section applies prospectively to business combinations for 
which the acquisition date is on or after the beginning of the ﬁ rst annual reporting period beginning on or after January 1, 2011.

CICA Handbook Section 1601 establishes standards for the preparation of consolidated ﬁ nancial statements.
CICA Handbook Section 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in con-
solidated ﬁ nancial statements subsequent to a business combination. It is the equivalent of the corresponding provisions of 
IFRS IAS 27, “Consolidated and Separate Financial Statements” (January 2008).

CICA Handbook Section 1601 and Section 1602 apply to interim and annual consolidated ﬁ nancial statements relating 
to ﬁ scal years beginning on or after January 1, 2011. Earlier adoption of these sections is permitted as of the beginning of a 
ﬁ scal year. Section 1582, Section 1601 and Section 1602 must be adopted concurrently. The Company is currently evaluating 
the impact of the adoption of these sections.

Financial Instruments
The  following  table  contains  the  components  of  income  (expense)  related  to  changes  in  the  fair  value  of  the 
Company’s derivative ﬁ nancial instruments:

Change in fair value of derivative instruments
Chambers power purchase agreement 
Onondaga indexed swap and hedge 
Project-level interest rate swaps 
Project-level natural gas swaps 

2008 

2007

$ 

$ 

74,608 
(10,844) 
(5,325) 
(3,378) 
55,061 

$  (106,113)
(20,290)
(1,974)
–
$  (128,377)

26 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

CHAMBERS POWER PURCHASE AGREEMENT
The PPA at the proportionately consolidated Chambers Project meets the accounting deﬁ nition of a derivative instrument. 
The PPA does not qualify for exclusion from CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, 
and has not been designated as a hedge. Accordingly, the PPA has been recorded at its fair value in the consolidated balance 
sheets and changes in the fair value are recognized in change in fair value of derivative instruments in the consolidated 
statements of income (loss) and deﬁ cit.

The fair value of the PPA is measured by comparing the net present value of the cash ﬂ ows expected to be received 
under the terms of the PPA to the net present value of the cash ﬂ ows that would be received if the same volumes were sold at 
projected market power prices over the term of the contract expiring in 2024. Accordingly, periodic changes to the fair value 
of the PPA reﬂ ect changes in forward market conditions and do not directly impact the amount of cash ﬂ ow the Chambers 
Project will receive under the terms of the PPA. The most signiﬁ cant factor that impacts the calculated fair value of the PPA is 
the projected forward market prices of power, and such prices can vary signiﬁ cantly from period to period. As of December 31, 
2008, a 10% change in the projected average forward power prices through the term of PPA expiring in 2024 would change 
the fair value of the PPA by approximately $27 million. 

ONONDAGA INDEXED SWAP AND HEDGE
A swap agreement (“Indexed Swap”) between a utility company and Onondaga, which had replaced Onondaga’s original 
power purchase contract, expired on June 30, 2008. The Indexed Swap was a derivative ﬁ nancial instrument under which the 
utility company made monthly payments to Onondaga based upon the diﬀ erential between an indexed contract price and 
a market reference price for electricity. The indexed contract price ﬂ uctuated in relation to the market cost of natural gas and 
a prescribed index of inﬂ ation. The notional quantity of electricity for the purpose of these calculations was ﬁ xed for the full 
term of the Indexed Swap.

In addition, Onondaga was party to a commodity derivative instrument (“Indexed Swap Hedge”), which locked in favour-

able gas, power and capacity pricing under the Indexed Swap. The Indexed Swap Hedge expired on June 30, 2008.

FOREIGN CURRENCY FORWARD CONTRACTS
The Company uses forward foreign currency contracts to manage its exposure to changes in foreign exchange rates, as the 
Company earns its income in the United States but has the obligation to make distributions to shareholders predominantly 
in Canadian dollars. Since its inception, the Company has established a hedging strategy for the purpose of reinforcing the 
long-term sustainability of its distributions. The Company has executed this strategy by entering into forward contracts to 
purchase Canadian dollars at ﬁ xed rates of exchange suﬃ  cient to make monthly distributions through December 2013 at the 
current annual dividend level of Cdn$0.46 per common share, as well as interest payments on the Subordinated Notes and 
Debentures. It is the Company’s intention to periodically consider extending the length of these forward contracts. Changes in 
the fair value of the Company’s forward contracts partially oﬀ set foreign exchange gains or losses on the U.S. dollar equivalent 
of the Company’s Canadian dollar obligations. 

The following table summarizes the Company’s forward foreign currency contracts with monthly settlement terms as of 

December 31, 2008:

Period  
2009  
2010 - 2013  

Sell U.S. dollars  
4,974  
5,289  

Notional monthly amounts
Buy Cdn. dollars  
6,000  
6,000  

Average rate
1.2062
1.1344

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

27

 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

In addition to the forward contracts in the table above that settle on a monthly basis, the Company has executed forward 
contracts to purchase Canadian dollars at ﬁ xed rates of exchange suﬃ  cient to make semi-annual payments on the Debentures. 
The contracts provide for the purchase of Cdn$1.9 million in April and in October of 2008 through 2011 at a rate of 1.1075 
Canadian dollars per U.S. dollar.

The foreign exchange forward contracts are carried at estimated fair value based on quoted market prices. Changes in the 
fair value of the foreign currency forward contracts are reﬂ ected in foreign exchange loss (gain) in the consolidated statements 
of income (loss) and deﬁ cit. 

The following table contains the components of recorded foreign exchange gain (loss) for the periods indicated:

Unrealized foreign exchange gains (losses):
Subordinated notes and convertible debentures   
Forward contracts and other 

Realized foreign exchange gains on forward contract settlements 

2008 

2007

$ 

$ 

85,212 
(48,537) 
36,675 
8,044 
44,719 

$ 

$ 

(68,419)
30,703
(37,716)
7,574
(30,142)

The following table illustrates the income (loss) that would be recorded on the Company’s ﬁ nancial instruments in the event 
of a 10% hypothetical decrease in the value of the U.S. dollar compared to the Canadian dollar as of December 31, 2008: 

Subordinated notes 
Convertible debentures 
Foreign currency forward contracts 

$ 

$ 

(32,097)
(4,926)
33,874
(3,149)

PASCO NATURAL GAS SWAPS
The Pasco Project’s operating margin was exposed to changes in natural gas prices for the second half of 2008 as a result of 
the expiry of its favourably priced natural gas supply contract on June 30, 2008 before the expiry of its PPA at the end of 2008. 
In the second quarter of 2008, the Company entered into a series of ﬁ nancial swaps that eﬀ ectively ﬁ xed the price of natural 
gas at the Pasco Project during the second half of 2008 at a weighted average price of $12.24/Mmbtu. 

These natural gas swaps are derivative ﬁ nancial instruments and were recorded in the consolidated balance sheet at fair 
value. Changes in the fair value of the natural gas swaps were recorded in change in fair value of derivative instruments in the 
consolidated statements of income (loss) and deﬁ cit. The natural gas swaps at Pasco expired in December 2008.

Beginning January 1, 2009, a new 10-year PPA at the Pasco Project requires the PPA counterparty to provide natural gas 
needed to operate the plant and, as a result, the Pasco Project is no longer exposed to changes in market prices of natural gas.

LAKE AND AUBURNDALE NATURAL GAS SWAPS
The Lake Project’s operating margin is exposed to changes in natural gas prices from the expiry of its natural gas supply 
contract on June 30, 2009 through the expiry of its PPA on July 31, 2013. The Auburndale Project purchases natural gas 
under a fuel supply agreement which provides approximately 80% of the Project’s fuel requirements through June 30, 2012. 
The remaining 20% is purchased at spot market prices and therefore the Project is exposed to changes in natural gas prices 
through the termination of the fuel supply agreement. 

The Company is executing a strategy to mitigate the future exposure to changes in natural gas prices at Lake and Auburn-

dale by periodically entering into ﬁ nancial swaps that eﬀ ectively ﬁ x the price of natural gas required at these projects.

28 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

These natural gas swaps are derivative ﬁ nancial instruments and are recorded in the consolidated balance sheet at fair 
value. Changes in the fair value of the natural gas swaps are recorded in other comprehensive income (loss) as they have been 
designated as a hedge of the risk associated with changes in market prices of natural gas.

The following table summarizes the hedge position related to natural gas needed to meet PPA requirements at Lake and 

Auburndale:

As of December 31, 2008 
Portion of gas volumes currently hedged:

Lake:
Contracted 
Financially hedged 
Total 

Auburndale:
Contracted 
Financially hedged 
Total 

2009 

2010 

2011 

2012 

2013

50% 
49% 
99% 

80% 
13% 
93% 

– 
49% 
49% 

80% 
– 
80% 

– 
– 
0% 

80% 
– 
80% 

– 
– 
0% 

40% 
– 
40% 

–
–
0%

–
–
0%

Average price of  ﬁ nancially hedged volumes (per Mmbtu)

Lake 
Auburndale 

$  8.64 
$  5.80 

$  7.59 
 – 
$  

$  
$  

 – 
 – 

$ 
$ 

 – 
 – 

$  
$ 

 –
 –

As of March 30, 2009 
Portion of gas volumes currently hedged:

2009 

2010 

2011 

2012 

2013

Lake:
Contracted 
Financially hedged 
Total 

Auburndale:
Contracted 
Financially hedged 
Total 

50% 
49% 
99% 

80% 
15% 
95% 

– 
72% 
72% 

80% 
9% 
89% 

– 
44% 
44% 

80% 
– 
80% 

– 
22% 
22% 

40% 
13% 
53% 

–
22%
22%

–
22%
22%

Average price of ﬁ nancially hedged volumes (per Mmbtu)

Lake 
Auburndale 

$  8.64 
$  5.68 

$  7.27 
$  6.78 

$  6.53 
 – 
$ 

$  6.60 
$  6.66 

$  6.71
$  6.78

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

29

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

SUBORDINATED NOTES PREPAYMENT OPTION
The Company has the option to redeem the Subordinated Notes beginning on November 18, 2009 at an initial redemption 
price equal to 105% of the principal amount being redeemed. The Company has determined that the redemption option 
is an embedded derivative that is recorded at fair value and periodic changes in fair value are recorded in other expenses in 
the consolidated statements of income (loss) and deﬁ cit. As of December 31, 2008, the fair value of the redemption option 
is zero. 

Management will periodically assess this option beginning in November 2009 and will consider exercising the call option 

if the Subordinated Notes can be recapitalized in a manner that beneﬁ ts the Company’s shareholders.

INTEREST RATE SWAPS
The  Company’s  proportionately  consolidated  Mid-Georgia  and  Chambers  projects  have  executed  interest  rate  swaps  to 
economically ﬁ x a portion of the respective Project’s exposure to changes in interest rates related to variable-rate project debt. 
These interest rate swaps are derivative ﬁ nancial instruments and are not designated as a hedge for accounting purposes. 
Interest rate swaps are recorded as derivative instruments liability in the consolidated balance sheet and changes in fair value 
are recorded in change in fair value of derivative instruments in the consolidated statements of income (loss) and deﬁ cit. The 
primary factor that inﬂ uences the fair value of interest rate swaps is changes in projected forward market interest rates. 

The fair value of interest rate swaps reﬂ ects the cash ﬂ ows due to or from the Company on the balance sheet date. Cash 
settlements related to interest rate swaps are recorded in interest expense in the consolidated statements of income (loss) 
and deﬁ cit.

The Company has executed interest rate swaps on its revolving credit facility and at its proportionately consolidated 
Auburndale Project to economically ﬁ x a portion of its respective exposure to changes in interest rates related to variable-rate 
debt. The interest rate swap agreements were designated as a cash ﬂ ow hedge of the forecasted interest payments under 
the existing credit facility as of November 2008. The interest rate swap termination date for Auburndale is November 30, 2009 
and for the revolving credit facility is November 30, 2011. 

The interest rate swap is a derivative ﬁ nancial instrument and is recorded in the balance sheet at fair value. Changes in 
the fair value of the interest rate swap are recorded in other comprehensive income (loss) as they have been designated as a 
hedge of the risks associated with the changes in the market interest rates.

AUCTION RATE SECURITIES
As of December 31, 2007, approximately $26 million of the Company’s cash and cash equivalents were invested in auction-
rate securities (“ARSs”). ARSs typically have an underlying maturity of up to 40 years but have historically traded in seven- or 
28-day intervals in a highly liquid market. The ARSs that were held at December 31, 2007 were redeemed at auctions held in 
January 2008 and the proceeds were re-invested in ARSs.

In February 2008, the overall market for ARSs suﬀ ered a signiﬁ cant decline in liquidity. Since early March 2008, most of 
the auctions of ARSs have been unsuccessful, resulting in the Company continuing to hold these securities and the issuers 
paying interest at the maximum contractual rate. 

In September and November 2008, all of the Company’s investments in ARS were sold, at par plus accrued interest, for 

$36.5 million. 

30 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

MANAGEMENT’S DISCUSSION AND ANALYSIS

LOANS AND RECEIVABLES
Accounts receivable is primarily comprised of amounts due to the Company’s consolidated and proportionately consolidated 
projects for sales of electricity under long-term contracts. As of December 31, 2008, there are no signiﬁ cant amounts of 
accounts receivable past due. The carrying value of loans and receivables approximates their fair value due to the short-term 
maturity of those ﬁ nancial instruments.

Income taxes recoverable represents tax instalment payments made to the United States Internal Revenue Service (“IRS”) 
and various state tax authorities, reduced by the estimated actual tax liability in those taxing jurisdictions. Through the end of 
2007, the Company was required to pay instalments to the IRS based on estimates of taxable income without the beneﬁ t of the 
interest deduction related to the Subordinated Notes and Debentures. This requirement resulted in the payment of signiﬁ cant 
tax instalments to the IRS, followed by a refund of most of the instalment payments when the actual tax returns were ﬁ led in 
subsequent periods with the full beneﬁ t of the interest deductions on the Subordinated Notes and Debentures. 

As of January 1, 2008, the Company is permitted to calculate tax instalment payments with the full beneﬁ t of these 
interest payments factored into estimated taxable income. As a result, management expects signiﬁ cant ﬂ uctuations in working 
capital related to tax instalments and subsequent refunds to decrease.

CONVERTIBLE DEBENTURES
The 6.25% convertible secured debentures (“Debentures”) are due October 31, 2011. Interest is payable semi-annually in arrears 
on April 30 and October 31 of each year. The Debentures are convertible into 80.6452 IPS per Cdn$1,000 principal amount of 
Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per IPS.

Commitments and Contingencies
From time to time, the Company and its subsidiaries and Projects are parties to disputes and litigation that arise in the normal 
course of business. The Company assesses its exposure to these matters and records estimated loss contingencies when a 
loss is likely and can be reasonably estimated. There were no matters pending as of December 31, 2008 which are expected 
to have a material impact on the Company’s ﬁ nancial position or results of operations.

Outstanding Share Data
The Company had 60,937,731 and 61,470,500 IPSs outstanding at December 31, 2008 and 2007, respectively.

On July 18, 2008, the Company approved a normal course issuer bid to purchase up to four million IPSs, representing 
approximately 8% of the Company’s public ﬂ oat. The Toronto Stock Exchange (“TSX”) approved the issuer bid on July 23, 2008, 
and purchases under the bid commenced on July 25, 2008. As of December 31, 2008, the Company had acquired 558,620 
IPSs at an average price of Cdn$8.78 under the terms of the issuer bid. The issuer bid will terminate on July 24, 2009 or such 
earlier date that the Company has acquired the maximum number of IPSs under the issuer bid. Atlantic Power will pay the 
market price at the time of acquisition for any IPSs purchased through the facilities of the TSX, and all IPSs acquired under 
the bid will be canceled.

The Debentures are convertible to approximately 80.6452 IPSs per Cdn$1,000 principal amount of Debentures, at any time, 
at the option of the holder, representing a conversion price of Cdn$12.40 per IPS. As of December 31, 2008, approximately 
4,838,700 IPSs would be required to be issued if all of the outstanding Debentures were converted to IPSs. On March 26, 2008 
and March 28, 2007, the Board of Directors approved grants of notional units to acquire a maximum of 142,717 and 172,071 
IPSs, respectively, under the terms of the Company’s Long-Term Incentive Plan. 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

31

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

Outlook
Based on management projections, the Company’s cash on hand and projected future cash ﬂ ows from existing projects are 
suﬃ  cient to meet the current level of cash distributions to IPS holders into 2015 before considering any positive impact from 
potential acquisitions or organic growth opportunities. 

Based  on  year-to-date  results  and  management  projections  for  the  remainder  of  the  year,  the  Company  expects 
to  receive  distributions  from  its  Projects  in  the  range  of  $90  million  to  $95  million  for  the  full  year  2009. This  amount
represents a decrease of approximately $30 million to $35 million over distributions received from the Projects in 2008. 

The decrease in 2009 Project distributions has historically been included in management’s long-term cash ﬂ ow projections 

and does not change the Company’s ability to continue paying distributions to shareholders at current levels.

The following decreases in projected 2009 Project distributions compared to 2008 are attributable to expiring contracts 

or one-time items discussed elsewhere in this MD&A:
• 

• 
• 

Shutdown of Onondaga due to the expiration of its ﬁ nancial swap arrangement that provided substantially all of the 
Project’s cash ﬂ ow.
Decrease in distributions from Gregory attributable to a non-recurring debt service reserve release received in 2008.
Decrease in distributions from Pasco resulting from the start of a new 10-year tolling agreement on January 1, 2009 that 
produces lower cash ﬂ ows than the PPA that expired at the end of 2008.
Lower cash distributions from Selkirk due to the expiry of one of the Project’s PPAs in 2008.

• 
During  2009,  the  following  five  Projects  are  expected  to  comprise  approximately  85%  of  Project  distributions
received by the Company: Auburndale, Lake, Orlando, Path 15 and Pasco. In 2008, the following seven Projects comprised 
approximately 85% of Project distributions received: Lake, Pasco, Onondaga, Chambers, Gregory, Selkirk and Path 15. 

In addition to the items above, following is a summary of other projections for Project distributions in 2009 and beyond:

LAKE
The Lake Project is exposed to changes in natural gas prices from the expiry of its natural gas supply contract on June 30, 2009 
through the expiry of its PPA in July 2013. The Company is executing a strategy to mitigate the future exposure to changes in 
natural gas prices at Lake by periodically entering into ﬁ nancial swaps that eﬀ ectively ﬁ x the price of natural gas required at 
the Project. Management has taken advantage of recent decreases in the market price of natural gas to make signiﬁ cant 
progress in its natural gas hedging strategy. These hedges are summarized in “Financial Instruments – Lake and Auburndale 
Natural Gas Swaps” in this MD&A. Management intends to continue, when appropriate, to execute additional transactions to 
mitigate natural gas price exposure at Lake in the 2010 to 2013 period. 

The variable energy revenues in the Lake Project’s PPA are indexed to the price of coal consumed by a speciﬁ c utility plant 
in Florida. The components of this coal price are proprietary to the utility, but management believes the utility purchases coal 
for that plant under a combination of short-term contracts and spot market transactions.

The Company’s previous guidance regarding expected distributions from the Lake Project is unchanged and is set forth 

in the table below:

Year  
2009 
2010 
2011 
2012 

Estimated Range of Cash Distributions ($ millions)
24-27
24-27
23-27
27-33

32 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

The estimates above are based on management’s current internal models as of March 30, 2009. The Company’s models 
are based on future gas prices forecasted by Cambridge Energy Research Associates, an independent third-party energy 
consulting ﬁ rm, which have decreased from the prices utilized in previous cash ﬂ ow projections. The 2009 natural gas price 
exposure at Lake has been substantially hedged. In 2010, projected cash distributions at Lake would change by approximately 
$1.1 million per $1.00/Mmbtu change in the price of natural gas based on the current level of unhedged natural gas volumes 
at the Project.

Coal prices used in the revenue component of the projected distributions from the Lake Project incorporate a forecast of 
the applicable Crystal River facility coal cost provided by the utility based on their internal projections. The projected annual 
cash distributions change by approximately $1.0 million for every $0.25/Mmbtu change in the projected price of coal.

AUBURNDALE
Increased distributions from Auburndale are the result of owning the Project for the full year of 2009 as it was acquired in 
November 2008. The Company previously disclosed projected distributions from Auburndale in the range of $20 million to 
$23 million in 2009 and $8 million to $10 million in each of the years from 2010 through 2013, when the Project’s current 
PPA expires. Based on the current forecast, the Company now expects distributions from Auburndale in 2009 in the range 
of $22 million to $25 million. The increase in forecasted 2009 distributions is attributable to a $1.7 million working capital 
adjustment received from the previous owners and a small increase in projected electricity revenues for the Project. 

Distributions received from Auburndale in the 2010 through 2013 period will be impacted by the timing and terms of the 
Company’s expected reﬁ nancing of the project-level debt, as well as projected coal and gas prices in the forecast period. The 
Company has not made signiﬁ cant changes to its previously disclosed forecast of distributions of $8 million to $10 million per 
year during the 2010 to 2013 period.

The projected revenue component of the Auburndale PPA contains a component related to coal costs at the Crystal 
River facility as described above for the Lake Project. In addition, Auburndale is exposed to changes in natural gas prices for 
a portion of the Project’s fuel requirements throughout the term of the PPA. The Company is executing a strategy to mitigate 
the  future  exposure  to  changes  in  natural  gas  prices  at  Auburndale  by  periodically  entering  into  ﬁ nancial  swaps  that 
eﬀ ectively ﬁ x the price of natural gas required at the Project. See “Financial Instruments – Lake and Auburndale Natural Gas 
Swaps” in this MD&A for additional details about hedge contracts executed as of March 30, 2009. The 2009 natural gas price 
exposure at Auburndale has been substantially hedged. In 2010, projected cash distributions at Auburndale would change 
by approximately $0.8 million per $1.00/Mmbtu change in the price of natural gas based on the current level of unhedged 
natural gas volumes at the Project. Management intends to continue, when appropriate, to execute additional transactions 
to mitigate natural gas price exposure at Auburndale in the 2010 to 2013 period. 

CHAMBERS
The Company expects a decrease in cash ﬂ ow at the Chambers Project in 2009 due to a planned major maintenance outage, 
changes in market power prices and expected sales volumes and the expense associated with regional carbon allowance 
purchases. 

The major maintenance outage requires a complete shutdown of the plant for approximately half of the second quarter 
of 2009. This type of outage is scheduled every seven years at the Project. The combined costs of maintenance and associated 
lost proﬁ t margin are expected to reduce distributions from Chambers by approximately $4 million compared to the main-
tenance outage in 2007. Signiﬁ cantly lower 2009 market power prices in the PJM region are expected to result in both lower 
volumes of electricity sold from the Project as well as operating margins on electricity sold under the Project’s proﬁ t-sharing 
arrangement with the local utility.

The estimated costs for the Project to comply with New Jersey’s implementation of the Regional Greenhouse Gas Initiative 

will reduce distributions from Chambers by approximately $2 million.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

33

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

The combined impact of these factors is expected to reduce cash ﬂ ows to the point that the Project’s non-recourse debt 
does not meet a cash ﬂ ow coverage ratio at a level that will allow cash to be distributed to the Company in 2009. Based on 
management’s current projections, the Chambers Project will be able to resume distributions to the Company in the second 
half of 2010. 

ORLANDO
Cash distributions from the Orlando Project are expected to increase in 2009 compared to 2008. The increase in projected 
distributions is attributable to higher volumes of electricity in 2009 than in 2008 when an unplanned outage shut the plant 
for approximately four months. The Project took advantage of the unplanned outage to make improvements in the eﬃ  ciency 
of the plant, which will result in slightly higher operating margins in 2009. In addition, insurance recoveries related to the 2008 
unplanned outage in the amount of $1.7 million are expected to be received by the Project in 2009.

Disclosure Controls and Procedures
Based on the requirements of Multilateral Instrument 52-109, “Certiﬁ cation of Disclosure in Issuers’ Annual and Interim Filings”, 
the Chief Executive Oﬃ  cer and Chief Financial Oﬃ  cer of the Manager have evaluated the eﬀ ectiveness of the Company’s 
disclosure controls and procedures (as deﬁ ned in Multilateral Instrument 52-109) as of December 31, 2008. Based on that 
evaluation, the Chief Executive Oﬃ  cer and Chief Financial Oﬃ  cer of the Manager have concluded that the Company’s disclo-
sure controls and procedures were eﬀ ective as of December 31, 2008 to provide reasonable assurance that material informa-
tion relating to the Company would be made known to them by others within the Company.

Internal Control over Financial Reporting
Internal control over ﬁ nancial reporting (“ICFR”) is designed to provide reasonable assurance regarding the reliability of 
ﬁ nancial reporting and the preparation of ﬁ nancial statements in accordance with Canadian GAAP. As of December 31, 2008, 
management evaluated, with the participation of the Chief Executive Oﬃ  cer and Chief Financial Oﬃ  cer of the Manager, 
the eﬀ ectiveness of the Company’s ICFR using the framework and criteria established by the Committee of Sponsoring 
Organizations of the Treadway Commission. Based on this evaluation, the Chief Executive Oﬃ  cer and Chief Financial Oﬃ  cer 
of the Manager concluded that the Company’s ICFR was eﬀ ective and that there were no material weaknesses in ICFR. There 
have been no material changes in the Company’s ICFR during the year ended December 31, 2008.

The CEO and CFO of the Manager have limited the scope of design of ICFR to exclude the Auburndale Project, which was 
acquired in November 2008. In addition, the proportionately consolidated Badger Creek, Chambers, Koma Kulshan, Orlando, 
Stockton and Topsham Projects have been excluded from the scope of ICFR.

Risk Factors
Atlantic Power’s future performance and its ability to generate suﬃ  cient cash ﬂ ow to meet its monthly cash distributions to 
holders of IPSs, and the Common Shares and Subordinated Notes represented thereby, and to holders of Debentures, are 
subject to a number of risks and uncertainties. Any of these risks and uncertainties could have a material adverse eﬀ ect on 
the Company’s results of operations, business prospects, ﬁ nancial condition, the cash available to the Company for distribution 
to holders of IPSs, Common Shares, Subordinated Notes or Debentures or on the market price or value of IPSs, Common 
Shares, Subordinated Notes or Debentures. A discussion of these risks and uncertainties can be found in the Company’s 
Annual Information Form dated March 30, 2009. The Company’s annual information form is available on SEDAR’s website at 
www.sedar.com. The following is a summary of the primary risks facing the Company:

34 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

REVENUE MAY BE REDUCED UPON EXPIRATION OR TERMINATION OF PPAS
Power generated by the Projects, in most cases, is sold under PPAs that expire at various times. In addition, these PPAs may 
be subject to termination in certain circumstances, including default by the Project owner or operator. When a PPA expires 
or is terminated, it is possible that the price received by the relevant Project for power under subsequent arrangements may 
be reduced signiﬁ cantly. It is possible that subsequent power purchase arrangements may not be available at prices that 
permit the operation of the Project on a proﬁ table basis. If this occurs, the aﬀ ected Project may temporarily or permanently 
cease operations.

THE PROJECTS DEPEND ON THEIR ELECTRICITY AND THERMAL ENERGY CUSTOMERS
Each Project 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. The amount of cash available for distribution to holders of IPSs, Common 
Shares and Subordinated Notes is highly dependent upon customers under such agreements fulﬁ lling their contractual 
obligations. There is no assurance that these customers will perform their obligations or make required payments to the 
Project Operating Entities.

CERTAIN PROJECTS ARE EXPOSED TO FLUCTUATIONS IN THE PRICE OF ELECTRICITY AND FUELS
While a majority of the oﬀ -takers of the Projects are contractually obligated to purchase electricity under long-term PPAs, 
those Projects with power purchase arrangements based on market pricing will be exposed to ﬂ uctuations in the wholesale 
price of electricity. In addition, should any of the long-term PPAs expire or terminate, the Manager or the relevant Project 
operator will be required to either negotiate new PPAs or sell into the electricity wholesale market, in which case the prices 
for electricity will depend on market conditions at the time.

PREDICTING PROJECT CASH FLOWS OVER THE LONG TERM IS DIFFICULT
Due to the many uncertainties described in this risk factors section that could materially aﬀ ect future revenues or expenses it 
can be diﬃ  cult to make long-term projections of the Company’s cash ﬂ ows and operating margins.

OPERATIONS ARE SUBJECT TO THE PROVISIONS OF VARIOUS ENERGY LAWS AND REGULATIONS
Generally, in the United States, the Company’s projects are subject to regulation by the FERC regarding the terms and 
conditions of wholesale service and rates, as well as by state agencies regarding PPAs entered into by QF projects and the 
siting of the generation facilities. The majority of the Company’s generation is sold by QF projects under PPAs that required 
approval by state authorities. 

On  August  8,  2005,  the  Energy  Policy  Act  of  2005  (“EPAct  2005”)  was  enacted,  which  removed  certain  regulatory 
constraints on investment in utility power producers by repealing the PUHCA 1935 and enacting the PUHCA 2005. EPAct 
2005 also limited the requirement that electric utilities buy electricity from QFs to certain markets that lack competitive 
characteristics. Finally, EPAct 2005 amended and expanded the reach of FERC’s corporate merger approval authority under 
section 203 of the FPA. FERC has issued ﬁ nal rulemakings implementing these provisions of EPAct 2005.

PROJECTS ARE SUBJECT TO SIGNIFICANT ENVIRONMENTAL AND OTHER REGULATIONS
The Projects are subject to numerous and signiﬁ cant federal, state 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; the storage, handling, use, transportation and distribution of dangerous goods and hazardous and residual 
materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the prevention, presence 
and remediation of hazardous materials in soil and groundwater, both on and oﬀ  site; land use and zoning matters; and 
workers’ health and safety matters. As such, the operation of the Projects carries an inherent risk of environmental, health 
and safety liabilities (including potential civil actions, compliance or remediation orders, ﬁ nes and other penalties), and may 
result in the Projects being involved from time to time in administrative and judicial proceedings relating to such matters.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

35

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

Environmental laws and regulations have generally become more stringent over time, and this trend may continue. 
In particular, the EPA has promulgated regulations under the federal Clean Air Interstate Rule (“CAIR”) requiring additional 
reductions in nitrogen oxides, or NOX and sulphur dioxide, or SO2, emissions, beginning in 2009 and 2010, respectively, and 
has also promulgated regulations requiring reductions in mercury emissions from coal-ﬁ red electric generating units, begin-
ning in 2010 with more substantial reductions in 2018. Moreover, certain of the states in which we operate have promulgated 
air pollution control regulations which are more stringent than existing and proposed federal regulations. The CAIR program 
underwent several legal challenges which resulted in the DC Circuit Court vacating the program on July 11, 2008. The EPA 
was instructed by the Court to completely overhaul the program. On December 23, 2008, the DC Circuit Court remanded, 
without vacature, EPA’s CAIR program. EPA is currently working with the states involved in the program to reinstate it and 
while doing so, making changes as required in the initial Court ruling.

Under the CAIR program, regulations are under consideration that would modify the existing program of distribution of 

NOX allocations at no cost to generators, to an auction-based program for all allocations.

 Ongoing public concerns about emissions of carbon dioxide and other greenhouse gases (“GHG”) from power plants 
have resulted in proposed laws and regulations at the federal, state and regional levels that, if they were to take eﬀ ect 
substantially as proposed, would likely apply to Project operations. For example, a proposed multi-state carbon dioxide cap-
and-trade program known as the Regional Greenhouse Gas Initiative (“RGGI”) would apply to the Company’s fossil fuel facilities 
in the Northeast region. The RGGI program went into eﬀ ect on January 1, 2009. Two regional quarterly CO2 auctions have 
already occurred. CO2 allocations are now a trade commodity, currently averaging in the $3.50 to $4.00/ton range. The State of 
Florida is conducting stakeholder meetings as part of the process of developing GHG contract regulations. They have held their 
most recent stakeholders meeting in January, 2009. Discussion then indicated favoring a program similar to that of RGGI.

In 2006, the State of California passed legislation initiating two programs to control/reduce the creation of GHG. The two 
laws, more commonly known as AB 32 and SB 1368, are currently in the regulatory rulemaking phase which will involve public 
comment and negotiations over speciﬁ c provisions. Development towards the implementation of this program continues.
Under AB 32 (the California Global Warming Act of 2006) the California Air Resources Board (“CARB”) is required to adopt 
a GHG emissions cap on all major sources (not limited to the electric sector). In order to do so, it must adopt regulations for 
the mandatory reporting and veriﬁ cation of GHG emissions and to reduce state-wide emissions of GHG to 1990 levels by 
2020. This will most likely require that electric generating facilities reduce their emissions of GHG or pay for the right to emit 
by the implementation date of January 1, 2012. The program has yet to be ﬁ nalized and the decision as to whether allocations 
will be distributed or auctioned will be determined in the rulemaking process that is currently underway. Discussion to date 
favors an allocation auction-based program.

SB 1368 added the requirement that the California Energy Commission, in consultation with the California Public Utilities 
Commission (“CPUC”) and the CARB establish a GHG emission performance standard and implement regulations for power 
purchase agreements that exceed ﬁ ve years entered into prospectively by publicly-owned electric utilities. The legislation 
directs the CEC to establish the performance standard as one not exceeding the rate of GHG emitted per megawatt-hour 
associated with combined-cycle, gas turbine baseload generation. Provisions are under consideration in the rulemaking to 
allow facilities that have higher CO2 emissions to be able to negotiate PPAs for up to a ﬁ ve-year period or sell power to entities 
not subject to SB 1368. This statute may limit Stockton’s ability to extend its PPA with PG&E (which currently expires in early 
2009) beyond the ﬁ ve-year limit.

In addition to the regional initiatives, legislation for the regulation of GHG has been introduced at the federal level and if 

passed, may eventually override the regional eﬀ orts with a national cap and trade program.

Signiﬁ cant expenditures may be required for either capital expenditures or the purchase of allowances under any or all 
of these programs to keep the Projects’ facilities compliant with environmental laws and regulations. The Projects’ PPAs do not 
allow for the pass through of emissions allowance or emission reduction capex 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.

36 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

MANAGEMENT’S DISCUSSION AND ANALYSIS

The Projects have obtained environmental permits and other approvals that are required for their operations. Compliance 
with applicable laws and future changes to them is material to the Company’s businesses. Although the Manager believes 
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. 

THE PROJECTS DEPEND ON SUPPLIERS UNDER FUEL SUPPLY AGREEMENTS 

AND INCREASES IN FUEL COSTS MAY ADVERSELY AFFECT THE PROFITABILITY OF THE PROJECTS
Revenues in respect of the Projects may be aﬀ ected by the availability, or lack of availability, of a stable supply of fuel at 
reasonable or predictable prices. To the extent possible, the Projects attempt to match fuel cost setting mechanisms in 
supply agreements to PPA energy payments formulas. To the extent that fuel costs are not matched well to PPA energy 
payments, increases in fuel costs may adversely aﬀ ect the proﬁ tability of the Projects.

The amount of energy generated at the Projects is highly dependent on suppliers under certain fuel supply agreements 
fulﬁ lling their contractual obligations. The loss of signiﬁ cant fuel supply agreements or an inability or failure by any supplier to 
meet its contractual commitments may adversely aﬀ ect cash distributions by the Company.

Upon the expiry or termination of existing fuel supply agreements, the Manager or Project operators will have to 
renegotiate these agreements or may need to source fuel from other suppliers. There can be no assurance that the Manager 
or Project operators will be able to renegotiate these agreements or enter into new agreements on similar terms. Furthermore, 
there can be no assurance as to availability of the supply or pricing of fuel under new arrangements and it can be very diﬃ  cult 
to accurately predict the future prices of fuel.

The amount of energy generated at the Projects is dependent upon the availability of natural gas, coal, oil or biomass. 

There can be no assurance that the long-term availability of such resources will remain unchanged.

U.S. FEDERAL INCOME TAX RISKS
There can be no assurance that U.S. federal income tax laws and IRS administrative policies respecting the U.S. federal income 
tax consequences generally applicable to a holder of Common Shares and Subordinated Notes, as represented by IPSs, will 
not be changed in a manner which adversely aﬀ ects Non-U.S. Holders.

There is no authority that directly addresses the tax treatment of securities similar to the Subordinated Notes (i.e., as part 
of a unit that includes Common Shares of the Company). In light of this absence of direct authority, it cannot be concluded 
with certainty that the Subordinated Notes will be treated as debt for U.S. federal income tax purposes, and, although the 
Company takes the position that the Subordinated Notes are debt for U.S. federal income tax purposes, there can be no 
assurance  that  this  position  will  not  be  challenged  by  the  IRS.  If  such  a  challenge  were  sustained,  some  or  all  of  the 
interest payments on the Subordinated Notes would be recharacterized as non-deductible distributions with respect to the 
Company’s equity, and the Company’s net taxable income, which is eﬀ ectively connected income, and thus its U.S. federal 
income tax liability would be materially increased. 

As a result, the Company’s after-tax cash ﬂ ow would be reduced and the Company’s ability to make interest payments 

on Subordinated Notes and distributions with respect to Common Shares could be materially and adversely impacted.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

37

 
MANAGEMENT’S DISCUSSION AND ANALYSIS

RECENT CANADIAN FEDERAL INCOME TAX PROPOSALS
On June 22, 2007, Bill C-52, which signiﬁ cantly modiﬁ es the Canadian federal income tax rules applicable to certain publicly 
listed trusts and partnerships, received Royal Assent. An investment in IPSs does not involve a publicly listed trust or partner-
ship, but an investment in IPSs shares certain characteristics with investments in publicly listed trust or partnership entities 
that are the subject of the new legislation. The proposals of October 31, 2006 ﬁ rst announcing the proposed rules indicated 
that although the details outlined therein reﬂ ected the then present intentions of the government, any aspect of these mea-
sures may be changed accordingly and possibly with retroactive eﬀ ect if there should emerge structures or transactions that 
are clearly devised to frustrate the policy objectives underlying the proposals. Management believes that the proposed rules 
do not apply to the Company and do not alter the tax consequences of an investment in Common Shares and Subordinated 
Notes represented by IPSs. However, there is no assurance that Canadian federal income tax laws and administrative policies 
will not be changed in a manner that adversely aﬀ ects the holders of Common shares and Subordinated Notes represented 
by IPSs.

Atlantic Power’s future performance and its ability to generate suﬃ  cient cash ﬂ ow to meet its monthly cash distributions 
to holders of IPSs, and the Common Shares and Subordinated Notes represented thereby, and to holders of Debentures, is 
subject to a number of risks and uncertainties. Any of these risks and uncertainties could have a material adverse eﬀ ect on 
the Company’s results of operations, business prospects, ﬁ nancial condition, the cash available to the Company for distribu-
tion to holders of IPSs, Common Shares, Subordinated Notes or Debentures or on the market price or value of IPSs, Common 
Shares or Subordinated Notes. In addition to the summary of certain risk factors below and other information contained or 
incorporated by reference in this MD&A, the “Risk Factors” section in the Company’s annual information form dated March 30, 
2009 should be given careful consideration and is incorporated by reference herein. Additional risks and uncertainties not 
currently known to the Company or management of the Manager, or that the Company or management of the Manager 
currently consider immaterial, may also impair operations of the Company. If any such risks actually occur, the business, ﬁ nan-
cial condition, or liquidity and results of operations of the Company, and the ability of the Company to make distributions on 
the IPSs, the Common Shares and Subordinated Notes represented thereby, and the Debentures, could be materially adversely 
aﬀ ected. The Company’s annual information form is available on SEDAR’s website at www.sedar.com.

Additional Information
Additional information is available on the Company’s website at www.atlanticpowercorporation.com, or under the Company’s 
proﬁ le on the SEDAR website at www.sedar.com.

The tables on the following two pages present unaudited non-GAAP supplementary ﬁ nancial information provided 
for informational purposes. Please see “Non-GAAP Financial Measures” and “Results of Operations for the Three and Twelve 
Month Periods Ended December 31, 2008 – Supplementary Financial Information” in this MD&A for additional details about 
the supplementary information.

38 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

MANAGEMENT’S DISCUSSION AND ANALYSIS

Three months ended December 31,  
2007 

2008  

Project Adjusted EBITDA1 (in thousands of U.S. dollars)  
(unaudited)  
Adjusted EBITDA1 from consolidated and proportionately consolidated Projects
Auburndale 
Badger Creek  
Chambers  
Koma Kulshan  
Lake  
Mid-Georgia 
Onondaga  
Orlando  
Pasco  
Stockton 
Topsham 
Path 15  
Other  
Total adjusted EBITDA1 from consolidated 

and proportionately consolidated Projects 

Amortization  
Interest expense, net  
Change in the fair value of derivative instruments 
Other expense  
Earnings (loss) from consolidated and proportionately consolidated Projects  
Adjusted EBITDA1 from equity and cost method Projects
Delta-Person  
Jamaica 
Gregory2 
Rumford  
Selkirk2 
Other  
Total adjusted EBITDA1 from equity and cost method Projects  
Amortization  
Interest expense, net  
Other expense 
Income tax  
Income from cost and equity investments 
Project income
Total adjusted EBITDA1 from all Projects  
Amortization  
Interest expense, net  
Change in the fair value of derivative instruments 
Other expense  
Income taxes  
Project income (loss) as reported in the statement of income  
Earnings (loss) from consolidated and proportionately consolidated Projects  
Equity income from equity and costs investments 
Project income (loss) as reported in the statement of income 

4,461 
1,098 
6,066 
259 
7,830 
590 
(467) 
5,170 
4,660 
777 
958 
6,317 
384 

38,103 
12,564 
7,428 
(77,493) 
18,795 
76,809 

536 
– 
1,478 
601 
2,834 
– 
5,449 
454 
190 
– 
– 
4,805 

43,552 
13,018 
7,618 
(77,493) 
18,795 
– 
81,614 
76,809 
4,805 
81,614 

– 
1,314 
4,962 
323 
6,633 
982 
4,681 
2,214 
3,633 
968 
470 
8,175 
248 

34,603 
9,792 
8,868 
38,730 
77,934 
(100,721) 

558 
– 
– 
655 
4,821 
16 
6,050 
463 
223 
– 
73 
5,291 

40,653 
10,255 
9,091 
38,730 
77,934 
73 
(95,430) 
(100,721) 
5,291 
(95,430) 

Years ended December 31,
2007

2008 

4,461 
3,762 
27,603 
912 
32,892 
4,206 
7,865 
8,206 
21,953 
1,780 
2,629 
28,872 
964 

146,105 
49,267 
26,473 
(55,061) 
13,330 
112,096 

2,012 
– 
10,411 
2,395 
8,032 
(164) 
22,686 
1,824 
728 
– 
– 
20,134 

168,791 
51,091 
27,201 
(55,061) 
13,330 
– 
132,230 
112,096 
20,134 
132,230 

–
4,109
28,028
1,196
28,042
5,587
21,966
8,336
14,225
3,505
2,031
31,564
987

149,576
48,188
26,975
128,377
67,897
(121,861)

2,255
2,381
–
2,585
10,350
(205)
17,366
1,948
1,172
5,115
665
8,466

166,942
50,136
28,147
128,377
73,012
665
(113,395)
(121,861)
8,466
(113,395)

1 

Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP. Adjusted EBITDA is deﬁ ned as earnings 
before interest, taxes, depreciation, amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Management uses 
adjusted EBITDA at the Projects to provide comparative information about Project performance. See “Non-GAAP Financial Measures” in this MD&A.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

39

 
 
MANAGEMENT’S DISCUSSION AND ANALYSIS

Reconciliation of Project Distributions (in thousands of U.S. dollars)

For the year ended December 31, 2008 

Adjusted 
EBITDA1 

Repayment 
of long-  
term debt  

Interest  
expense, 
net  

Capital 
expenditures 

Change in
working  
capital &  
other items 

Project
distribution
received

Consolidated and proportionately
  consolidated Projects
Auburndale 
Badger Creek  
Chambers  
Koma Kulshan  
Lake  
Mid-Georgia  
Onondaga  
Orlando  
Pasco  
Stockton 
Topsham 
Path 15 
Other 

Total consolidated and proportionately
  consolidated Projects  

Equity and cost method Projects
Delta-Person 
Gregory  
Rumford  
Selkirk 
Other  
Total equity and cost method Projects 
Total all Projects  

4,461 
3,762 
27,603 
912 
32,892 
4,206 
7,865 
8,206 
21,953 
1,780 
2,629 
28,872 
964 

– 
– 
(9,639) 
– 
– 
(2,646) 
– 
(3,468) 
(12,038) 
– 
(2,400) 
(8,086) 
– 

(225) 
(3) 
(8,537) 
4 
33 
(3,271) 
81 
16 
(978) 
(9) 
(193) 
(13,232) 
(159) 

– 
– 
(145) 
(192) 
(814) 
11 
(3) 
(306) 
(175) 
(61) 
– 
– 
(113) 

1,764 
441 
1,414 
(528) 
(931) 
1,700 
11,693 
(1,048) 
10,883 
(1,460) 
(36) 
156 
(290) 

6,000
4,200
10,696
196
31,180
–
19,636
3,400
19,645
250
–
7,710
402

146,105 

(38,277) 

(26,473) 

(1,798) 

23,758 

103,315

2,012 
10,411 
2,395 
8,032 
(164) 
22,686 
168,791 

(1,027) 
(1,807) 
– 
(6,915) 
– 
(9,749) 
(48,026) 

(738) 
– 
2 
– 
8 
(728) 
(27,201) 

– 
(133) 
(187) 
(60) 
– 
(380) 
(2,178) 

(247) 
1,940 
524 
6,974 
156 
9,347 
33,105 

–
10,411
2,734
8,031
–
21,176
124,491

1    Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP. Adjusted EBITDA is deﬁ ned as earnings 

before interest, taxes, depreciation, amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Management uses 
Adjusted EBITDA at the Projects to provide comparative information about Project performance. See “Non-GAAP Financial Measures” in this MD&A.

40 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS 
to the Shareholders of Atlantic Power Corporation

The accompanying consolidated ﬁnancial statements of Atlantic Power Corporation, the management’s discussion and analysis 
and the information included in this annual report have been prepared by Atlantic Power Management, LLC, the Corporation’s 
management, which is responsible for their consistency, integrity and objectivity. Management is also responsible for ensuring 
that the consolidated ﬁnancial statements are prepared and presented in accordance with Canadian generally accepted account-
ing principles, which include amounts that are based on estimates and judgments. To fulﬁll these responsibilities, management 
maintains appropriate internal control systems and policies and procedures to provide reasonable assurance that assets are 
safeguarded and ﬁnancial records are reliable and form a proper basis for the preparation of ﬁnancial statements.

KPMG LLP, the Corporation’s independent auditors, are responsible for auditing the consolidated ﬁnancial statements in 
accordance with Canadian generally accepted accounting principles, and have expressed their opinion on the consolidated 
ﬁnancial statements in this report. Their report, as auditors, is set forth below.

The Corporation’s Board of Directors is responsible for ensuring that management fulﬁlls its responsibilities for ﬁnancial 
reporting and internal controls. The Board of Directors carries out this responsibility through its Audit Committee, which 
meets regularly with management and the independent auditors. The members of the Audit Committee are independent 
of management. The consolidated ﬁnancial statements have been reviewed and approved by the Board of Directors and its 
Audit Committee. The independent auditors have direct and full access to the Audit Committee and the Board of Directors.

Barry Welch 
President and CEO 

Patrick Welch
Chief Financial Oﬃ  cer

AUDITORS’ REPORT TO THE SHAREHOLDERS 

We have audited the consolidated balance sheets of Atlantic Power Corporation as at December 31, 2008 and 2007 and 
the consolidated statements of income (loss) and deﬁ cit, comprehensive income (loss) and cash ﬂ ows for each of the years 
then ended. These ﬁ nancial statements are the responsibility of the Company’s management. Our responsibility is to express 
an opinion on these ﬁ nancial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require 
that we plan and perform an audit to obtain reasonable assurance whether the ﬁ nancial statements are free of material 
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the 
ﬁ nancial statements. An audit also includes assessing the accounting principles used and signiﬁ cant estimates made by 
management, as well as evaluating the overall ﬁ nancial statement presentation.

In our opinion, these consolidated ﬁ nancial statements present fairly, in all material respects, the ﬁ nancial position of 
the Company as at December 31, 2008 and 2007 and the results of its operations and its cash ﬂ ows for each of the years 
then ended in accordance with Canadian generally accepted accounting principles.

Chartered Accountants, Licensed Public Accountants
Toronto, Canada   
March 30, 2009

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

41

 
CONSOLIDATED BALANCE SHEETS
(In thousands of U.S. dollars)

ASSETS 
Current assets:
Cash and cash equivalents 
Restricted cash  
Accounts receivable 
Current portion of derivative instruments asset (Note 14) 
Prepayments, supplies and other 
Income taxes recoverable 

Property, plant and equipment (Note 5) 
Transmission system rights (Note 7) 
Other intangible assets (Note 7) 
Long-term investments (Note 8) 
Goodwill (Note 6) 
Derivative instruments asset (Note 14) 
Other assets 

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities 
Current portion of long-term and short-term debt  
Current portion of derivative instruments liability (Note 14) 
Interest payable on Subordinated Notes and Debentures 
Dividends payable 
Other 

Long-term debt (Note 11) 
Subordinated Notes (Note 12) 
Convertible Debentures (Note 13) 
Derivative instruments liability (Note 14) 
Future tax liability (Note 16) 
Other liabilities 

Shareholders’ equity:
Common Stock (Note 17) 
Accumulated other comprehensive loss (Note 20) 
Deﬁ cit 

Commitments and contingencies (Note 22) 
Subsequent events (Note 23) 

See accompanying notes to consolidated ﬁ nancial statements.

On behalf of the Board:

Director 

Director

42 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

December 31,

2008 

2007

$ 

50,071 
25,372 
48,128 
15,001 
8,593 
2,300 
149,465 

433,542 
203,833 
180,186 
63,765 
8,918 
109,482 
2,399 
$ 1,151,590 

$ 

31,783 
79,512 
10,031 
3,455 
1,918 
3,941 
$  130,640 

  364,155 
  310,584 
48,790 
22,132 
44,883 
35,467 

$ 

55,990
38,304
38,134
23,753
10,020
10,261
176,462

413,040
210,972
125,976
64,815
8,918
79,611
2,053
$ 1,081,847

$ 

$ 

32,886
36,926
7,822
4,271
2,127
2,637
86,669

356,188
386,092
59,912
8,044
46,914
24,253

  214,888 
(3,204) 
(16,745) 
  194,939 

216,636
–
(102,861)
113,775

$ 1,151,590 

$ 1,081,847

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF INCOME (LOSS), 
COMPREHENSIVE INCOME (LOSS) AND DEFICIT
(In thousands of U.S. dollars, except per share amounts)

Project revenue:
Energy sales 
Energy capacity revenue 
Transmission services 
Other 

Project expenses:
Fuel  
Operations and maintenance 
Project operator fees and expenses 
Depreciation and amortization 

Project other income (expense):
Change in fair value of derivative instruments (Note 14) 
Income from long-term investments 
Asset impairments (Notes 5 and 6) 
Interest, net 
Other project income  

Project income (loss) 

Administrative and other expenses:
Management fees and administration  
Interest, net 
Foreign exchange (gain) loss 
Other expenses, net 

Income (loss) before income taxes 

Income tax expense (beneﬁ t) (Note 16) 
Net income (loss) 
Retained earnings (deﬁ cit), beginning of year 
Redemption of IPSs (Note 17) 
Dividends paid 
Deﬁ cit, end of year 

Years Ended December 31,
2007

2008 

$  148,376 
  145,538 
31,528 
8,779 
  334,221 

  133,362 
41,387 
13,367 
49,267 
  237,383 

55,061 
20,134 
(18,471) 
(26,473) 
5,141 
35,392 
  132,230 

10,012 
43,275 
(44,719) 
451 
9,019 
  123,211 

12,523 
  110,688 
  (102,861) 
275 
(24,847) 
(16,745) 

$ 

$  147,486
121,119
34,524
3,063
306,192

109,217
38,467
8,933
48,188
204,805

(128,377)
8,466
(71,726)
(26,975)
3,830
(214,782)
(113,395)

8,185
44,282
30,142
975
83,584
(196,979)

(47,774)
(149,205)
71,009
–
(24,665)
$  (102,861)

Net income (loss) per share – basic (Note 19) 
Net income (loss) per share – diluted (Note 19) 

$ 
$ 

1.81 
1.67 

$ 
$ 

(2.43)
(2.43)

Consolidated Statements of Comprehensive Income (Loss) 
(In thousands of U.S. dollars)
Net income (loss) 
Other comprehensive (loss)

Unrealized loss on natural gas and interest rate cash ﬂ ow hedges, net (Note 20) 

Comprehensive income (loss) 

$  110,688 

$  (149,205)

(3,204) 
$  107,484 

–
$  (149,205)

See accompanying notes to consolidated ﬁ nancial statements.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

43

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands of U.S. dollars)

Cash fl ows from operating activities:
Net income (loss) 
Items not involving cash:
Depreciation and amortization 
(Gain) loss on sale of property, plant and equipment 
Earnings from equity investments (Note 8) 
Asset impairments (Notes 5 and 6) 
Change in gas transportation contract commitment (Note 9) 
Unrealized foreign exchange (gain) loss 
Change in fair value of derivative instruments (Note 14) 
Future taxes 
Change in other operating balances 
Distributions from equity investments (Note 8) 

Cash fl ows from (used in) fi nancing activities:
Redemption of IPSs 
Proceeds from revolving credit facility borrowings 
Repayment of revolving credit facility borrowings 
Proceeds from issuance of project-level debt 
Dividends paid 
Repayment of long-term debt 
Repayment of obligations to non-controlling interest 
Cash proceeds from escrow used for redemption 

Cash fl ows used in investing activities:
Acquisition, net of cash acquired (Note 3) 
Proceeds from sale of equity investment 
Purchase of property, plant and equipment 
Proceeds from sale of property, plant and equipment 

Years Ended December 31,
2007

2008 

$  110,688 

$  (149,205)

49,267 
(5,163) 
(1,692) 
18,471 
– 
(36,675) 
(55,061) 
12,535 
12,131 
2,742 
  107,243 

(4,676) 
55,000 
– 
35,000 
(24,612) 
(38,277) 
– 
– 
22,435 

  (141,688) 
– 
(1,798) 
7,889 
  (135,597) 

47,602
8,923
1,898
71,726
(23,573)
37,716
131,089
(51,747)
7,387
4,085
85,901

–
31,000
(31,000)
48,056
(24,342)
(88,581)
(76,888)
74,433
(67,322)

(23,213)
6,195
(17,271)
3,073
(31,216)

Decrease in cash and cash equivalents 

Cash and cash equivalents, beginning of period 

(5,919) 

(12,637)

55,990 

68,627

Cash and cash equivalents, end of period 

$ 

50,071 

$ 

55,990

Supplemental cash fl ow information:
Interest paid 
Income taxes refunded 

See accompanying notes to consolidated ﬁ nancial statements.

$ 

72,129 
2,418 

$ 

72,248
1,143

44 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years ended December 31, 2008 and 2007
(In thousands of U.S. dollars, unless otherwise noted, and except per share amounts)

Atlantic Power Corporation (the “Company”) is a corporation established under the laws of the Province of Ontario on 
June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. The Company issued income participating 
securities (“IPSs”) for cash pursuant to an initial public oﬀ ering on November 18, 2004. Each IPS is comprised of one common 
share and Cdn$5.767 principal value of 11% subordinated notes due 2016 (“Subordinated Notes”). 

The Company currently owns, through its wholly-owned subsidiary Atlantic Power Holdings, LLC (“Holdings”) indirect 
interests in 14 power generation projects and one transmission line located in the United States (collectively, the “Projects”). 
Four of the Projects are wholly-owned subsidiaries of the Company: Lake Cogen Ltd. (“Lake”), Pasco Cogen, Ltd. (“Pasco”), 
Auburndale Power Partners, L.P. (“Auburndale”) and Atlantic Holdings Path 15, LLC (“Path 15”).

1.  Basis of presentation and signifi cant accounting policies
A.  BASIS OF PRESENTATION
The consolidated ﬁ nancial statements of the Company are prepared in accordance with Canadian generally accepted 
accounting principles and include the consolidated accounts of all of its subsidiaries. The Company applies the equity meth-
od of accounting for investments in which it has signiﬁ cant inﬂ uence but does not control and applies the cost method of 
accounting for investments in which it does not have signiﬁ cant inﬂ uence as these are treated as available for sale instruments 
for which there is no available market and as such are recorded as cost (Note 8). The Company proportionately consolidates 
investments in which it has joint control (Note 4). The Company eliminates intercompany accounts and transactions. 

B.  CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash deposited at banks and highly liquid investments with original maturities of three 
months or less.

C.  RESTRICTED CASH
Restricted cash represents cash and cash equivalents that are maintained by the Projects to support payments for major 
maintenance costs and meet Project-level contractual debt obligations. 

D.  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. The useful lives of facilities range from three to 60 years. The weighted 
average useful life is 23 years.

E.  TRANSMISSION SYSTEM RIGHTS
Transmission system rights are an intangible asset that represents the long-term right to approximately 72% of the capacity 
of the Path 15 transmission line in California. Transmission system rights are amortized on a straight-line basis over 30 years, 
the regulatory life of the Project.

F.  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 the Company’s reporting units that are expected to beneﬁ t from the synergies of the business 
combination. 

Goodwill is not amortized and is tested for impairment annually, or more frequently if events or changes in circumstances 
indicate that the asset might be impaired. The impairment test is carried out in two steps. In the ﬁ rst step, 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, good-
will of the reporting unit is considered not to be impaired and the second step of the impairment test is unnecessary.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

45

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 impair-
ment 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 described in the preceding paragraph, 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 income 
(loss), comprehensive income (loss) and deﬁ cit.

G.  OTHER INTANGIBLE ASSETS
Other intangible assets include power purchase contracts and fuel supply agreements.

Power purchase agreements are valued at the time of acquisition based on the rates received under the power purchase 
contracts relative to projected market rates. The balances are presented net of accumulated amortization. Amortization 
is recorded on a straight-line basis over the remaining term of the contract. The amortization period ranges from one to 16 
years. The weighted average period of amortization is 13 years.

Fuel supply agreements are valued at the time of acquisition based on the rates projected to be paid under the fuel 
supply agreement relative to projected market rates. The amortization period ranges from one to 16 years. The weighted 
average period of amortization is nine years.

H.  REVENUE RECOGNITION
The Company recognizes energy sales revenue when electricity and steam are delivered under the terms of the related 
contracts. If the power purchase contract contains capacity payments that ﬂ uctuate over the term of the contract, the 
Company recognizes energy capacity revenue based on the estimated average rate for the duration of the contract with the 
diﬀ erence between cash received and revenue recognized reﬂ ected as deferred revenue.

Transmission services revenue is recognized as transmission services are provided. The annual revenue requirement 
for transmission services is regulated by the Federal Energy Regulatory Commission (“FERC”) and is established through a 
rate-making process that occurs every three years. When actual cash receipts from transmission services revenue are diﬀ erent 
than the regulated revenue requirement because of timing diﬀ erences, the over or under collections are deferred until the 
timing diﬀ erences reverse in future periods.

Onondaga Cogeneration, LP (“Onondaga”) recognized revenue as its swap agreements settled monthly, net of any change 

in fair value on these swap agreements (Note 14(c)).

INCOME TAXES

I. 
Income taxes are accounted for using the asset and liability method. Future tax assets and liabilities are recognized for the 
future tax consequences attributable to diﬀ erences between the ﬁ nancial statement carrying amounts of existing assets and 
liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted 
tax rates expected to apply to taxable income in the years in which those temporary diﬀ erences are expected to be recovered 
or settled. The eﬀ ect on future tax assets and liabilities of a change in tax rates is recognized in income in the year that includes 
the date of enactment or substantive enactment.

A valuation allowance is recorded against future tax assets to the extent that it is more likely than not that the future tax 

asset will not be realized.

J.  FINANCIAL INSTRUMENTS
Financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is 
based on the classiﬁ cation of the ﬁ nancial instrument. Financial assets and ﬁ nancial liabilities held for trading are measured at 
fair value with changes in fair value reported in earnings. Financial assets held to maturity, loans and receivables and ﬁ nancial 
liabilities other than those held for trading are measured at amortized cost using the eﬀ ective interest method. Available for 

46 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

sale ﬁ nancial assets are measured at fair value with changes in fair value reported in other comprehensive income until the 
ﬁ nancial instrument is de-recognized, at which time cumulative gain or loss previously recognized in accumulated other 
comprehensive income is recognized in net income for the period.

The Company uses ﬁ nancial derivative agreements in the form of interest rate swaps, indexed swap hedges and foreign 
exchange forward contracts to manage its current and anticipated exposure to ﬂ uctuations in interest rates and foreign 
currency exchange rates. On occasion, the Company has also entered into natural gas supply contracts and natural gas 
forwards or swaps to minimize the eﬀ ects of the price volatility of natural gas which is a major production cost. The Company 
does not enter into ﬁ nancial derivative agreements for trading or speculative purposes; however, not all derivatives qualify 
for hedge accounting.

Derivative ﬁ nancial instruments not designated as a hedge are measured at fair value with changes in fair value recorded 
in the consolidated statements of income (loss), comprehensive income (loss) and deﬁ cit. Derivative ﬁ nancial instruments not 
designated as hedges are the foreign currency forward contracts, the Indexed Swap and the Indexed Swap Hedge agreements 
and certain interest rate and natural gas swaps. Mark-to-market adjustments in the foreign currency forward contracts are 
reﬂ ected in foreign exchange loss, Indexed Swap and Indexed Swap Hedge agreements are netted and reﬂ ected as Indexed 
Swaps under Project revenue and adjustments in interest rate swaps are reﬂ ected in Project interest expense in the consoli-
dated statements of income (loss), comprehensive income (loss) and deﬁ cit.

The Company has designated its natural gas forward contracts and some of its interest rate swaps as hedges of cash 

ﬂ ows for accounting purposes.

Tests are performed to evaluate hedge eﬀ ectiveness and ineﬀ ectiveness at inception and on an ongoing basis, both 
retroactively and prospectively. Unrealized gains or losses on the interest rate swaps designated within a designated hedging 
relationship are recognized in other comprehensive income.

Gains and losses on natural gas forward contracts and swaps that are designated as a hedge of fuel costs are recognized in 
accumulated other comprehensive loss until the hedged items are recognized in earnings as actual fuel costs are recognized.
Natural gas supply contracts in the normal course of business, in which the Company takes possession of the natural 

gas, are treated as executory contracts.

K.  ASSET RETIREMENT OBLIGATIONS
The fair value of asset retirement obligations is recognized in other long-term liabilities in the consolidated balance sheets 
when they are identiﬁ ed and their fair value is reasonably estimable. The asset retirement cost, equal to the estimated fair value 
of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. The asset retirement costs 
are depreciated over the asset’s estimated useful life and included in depreciation expense on the consolidated statements of 
income (loss), comprehensive loss and deﬁ cit. Increases in the asset retirement obligation resulting from the passage of time are 
recorded as accretion of asset retirement obligation in the consolidated statements of income (loss), comprehensive income 
(loss) and deﬁ cit. Actual expenditures incurred to retire the asset are charged against the accumulated obligation.

IMPAIRMENT OF LONG-LIVED ASSETS AND EQUITY INVESTMENTS

L. 
Long-lived assets, such as property, plant and equipment, transmission system rights and other intangible assets subject to 
depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the 
carrying amount of an asset 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 ﬂ ows expected to be generated by the asset. If the 
carrying amount of an asset exceeds its estimated future cash ﬂ ows, an impairment charge is recognized in the amount by 
which the carrying amount of the asset exceeds its fair value.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

47

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company is required to evaluate its equity method investments to determine whether or not they are impaired when 
the value is considered an “other than a temporary” decline in value. The evaluation and measurement of impairments for equity 
method investments involve the same uncertainties as described for long-lived assets. Similarly, estimates, with respect to our 
equity and cost-method investments, are subjective, and the impact of variations in these estimates could be material.

M.  FOREIGN CURRENCY TRANSLATION
The  Company’s  functional  currency  and  reporting  currency  is  the  United  States  dollar. The  functional  currency  of  the 
Company’s subsidiaries and other investments is the United States dollar. Monetary assets and liabilities denominated in 
Canadian dollars are translated into United States dollars using the rate of exchange in eﬀ ect at the end of the year. All trans-
actions denominated in Canadian dollars are translated into United States dollars at the exchange rates in eﬀ ect at the trans-
action date. Foreign currency translation gains and losses are reﬂ ected in the consolidated statements of income (loss), 
comprehensive income (loss) and deﬁ cit.

N.  USE OF ESTIMATES
The preparation of ﬁ nancial statements requires management to make estimates and assumptions that aﬀ ect the reported 
amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the ﬁ nancial statements and 
the reported amounts of revenue and expenses during the year. Actual results could diﬀ er from those estimates. During the 
periods presented, management has made a number of estimates and valuation assumptions, including the fair values of 
acquired assets, the useful lives and recoverability of property, plant and equipment and power purchase agreements, the 
recoverability of long-term investments, the recoverability of future tax assets, and the fair value of ﬁ nancial instruments and 
derivatives. These estimates and valuation assumptions are based on present conditions and management’s planned course 
of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assump-
tions and estimates change, the recorded amounts could change by a material amount.

O.  LONG-TERM INCENTIVE PLAN
The oﬃ  cers and other employees of Atlantic Power Management, LLC (the “Manager”) are eligible to participate in the 
Company’s Long-Term Incentive Plan (“LTIP”) that was implemented in 2007, as determined by the independent members of 
the Board of Directors of the Company. On an annual basis, the Board of Directors establishes awards that are based on the 
cash ﬂ ow performance of the Company in the most recently completed year, each participant’s base salary and the market 
price of the IPSs at the award date. Awards are granted in the form of notional units that have similar economic characteristics 
to the Company’s IPSs. Notional units vest over a three-year period and are redeemed in a combination of cash and IPSs upon 
vesting. 

Unvested notional awards are entitled to receive distributions equal to the distributions per public IPS during the vesting 
period in the form of additional notional units. Unvested awards are subject to forfeiture if the participant is not an employee 
of the Manager at the vesting date or if the Company does not meet certain ongoing cash ﬂ ow performance targets.

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 at each balance sheet date. Fair value of the awards is determined by projecting the total 
number of notional units that will vest in future periods, including distributions received on notional units during the vesting 
period, and applying the current market price per IPS to the projected number of notional units that will vest. Forfeitures are 
recorded as they occur and are not included in the estimated fair value of the awards. The aggregate number of IPSs which may 
be issued from treasury under the LTIP is limited to one million.

48 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.   Changes in accounting policies
A.  FINANCIAL INSTRUMENTS – PRESENTATION AND DISCLOSURE
Eﬀ ective January 1, 2008, the Company adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 
3862, “Financial Instruments – Disclosures” and Handbook Section 3863, “Financial Instruments – Presentation”.

Section 3682 requires entities to provide disclosures in their ﬁ nancial statements that enable users to evaluate the 
signiﬁ cance of ﬁ nancial instruments on the entity’s ﬁ nancial position and its performance and the nature and extent of risks 
arising from ﬁ nancial instruments to which the entity is exposed during the period and at the balance sheet date, and how 
the entity manages those risks. 

Section 3683 establishes standards for presentation of ﬁ nancial instruments and non-ﬁ nancial derivatives. It deals with 
the classiﬁ cation of ﬁ nancial instruments, from the perspective of the issuer, between liabilities and equity, the classiﬁ cation 
of related interest, dividends, losses and gains, and circumstances in which ﬁ nancial assets and ﬁ nancial liabilities are oﬀ set.
The adoption of these standards did not have any impact on the classiﬁ cation and valuation of the Company’s ﬁ nancial 

instruments. The additional new disclosures pursuant to these new Handbook Sections are included in Note 14.

B.  CAPITAL DISCLOSURES
Eﬀ ective January 1, 2008, the Company adopted the new recommendations of the CICA Handbook Section 1535, “Capital 
Disclosures”. This new Handbook Section establishes standards for disclosing information about an entity’s capital and how it 
is managed. It requires the disclosure of information about an entity’s objectives, policies and processes for managing capital. 
These new disclosures are included in Note 15.

C.  RECENTLY ISSUED ACCOUNTING STANDARDS
In February 2008, the Canadian Accounting Standards Board announced the adoption of International Financial Reporting 
Standards (“IFRS”) for publicly accountable enterprises in Canada. Eﬀ ective January 1, 2011, the Company will be required to 
convert from Canadian GAAP to IFRS. Management has begun to develop plans to implement the new standards, and cannot 
at this time reasonably estimate the impact of adopting IFRS on the Company’s consolidated ﬁ nancial statements.

CICA Handbook Section 3064, “Goodwill and Intangible Assets”, establishes standards for recognition, measurement, 
presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets. Standards concerning 
goodwill are unchanged from the standards included in the previous CICA Handbook Section 3062. The Company will adopt 
the new Handbook Section on January 1, 2009 and is currently assessing the impact that the adoption of these standards 
will have on its consolidated ﬁ nancial statements.

On January 20, 2009 the Emerging Issues Committee (“EIC”) of the CICA issued EIC-173, “Credit Risk and the Fair Value of 
Financial Assets and Financial Liabilities”, which clariﬁ es that an entity’s own credit risk and the credit risk of the counterparty 
should be taken into account in determining the fair value of ﬁ nancial assets and liabilities, including derivative instruments. 
EIC-173 is to be applied retrospectively without restatement of prior periods in interim and annual ﬁ nancial statements for 
periods ending on or after the date of issuance of EIC-173. The Company will adopt this recommendation in its fair value 
determinations eﬀ ective January 1, 2009 and is currently assessing the impact of this change on its consolidated ﬁ nancial 
statements.

In January 2009, the CICA issued Handbook Section 1582, “Business Combinations”, Section 1601, “Consolidations”, and 
Section 1602, “Non-controlling Interests”. These sections replace the former CICA Handbook Section 1581, “Business Combina-
tions” and Section 1600, “Consolidated Financial Statements” and establish a new section for accounting for a non-controlling 
interest in a subsidiary.

CICA Handbook Section 1582 establishes standards for accounting for a business combination. It provides the Canadian 
equivalent to IFRS 3, “Business Combinations” (January 2008). The section applies prospectively to business combinations for 
which the acquisition date is on or after the beginning of the ﬁ rst annual reporting period beginning on or after January 1, 2011.

CICA Handbook Section 1601 establishes standards for the preparation of consolidated ﬁ nancial statements.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

49

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

CICA Handbook Section 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in con-
solidated ﬁ nancial statements subsequent to a business combination. It is the equivalent of the corresponding provisions of 
IFRS IAS 27, “Consolidated and Separate Financial Statements” (January 2008).

CICA Handbook Section 1601 and Section 1602 apply to interim and annual consolidated ﬁ nancial statements relating 
to ﬁ scal years beginning on or after January 1, 2011. Earlier adoption of these sections is permitted as of the beginning of a 
ﬁ scal year. Section 1582, Section 1601 and Section 1602 must be adopted concurrently. The Company is currently evaluating 
the impact of the adoption of these sections.

3.  Acquisitions and divestments
A.  AUBURNDALE ACQUISITION
On November 21, 2008, the Company acquired 100% of Auburndale, which owns and operates a 155 MW natural gas-ﬁ red 
combined cycle cogeneration facility in Polk County, Florida. The purchase price was funded by cash on hand, a borrowing 
under the Company’s credit facility and $35 million of acquisition debt. The cash payment for the acquisition, including 
acquisition costs, has been allocated to the net assets acquired based on management’s preliminary estimate of the fair 
value. Total cash paid for the acquisition, less cash acquired, during 2008 was $141,688. In 2009, the Company received a 
working capital adjustment from the sellers in the amount of $1,780, resulting in a ﬁ nal purchase price of $139,908.

The allocation of the purchase price to the net assets acquired is as follows:

Working capital 
Property, plant and equipment 
Power purchase agreements 
Fuel supply agreements 
Other long-term assets 
Total purchase price 

Less: cash acquired 

Cash paid, net of cash acquired 

$ 

11,589
56,301
45,980
33,846
663
148,379
(8,471)
$  139,908

B.  PASCO ACQUISITION
In December 2007, the Company acquired substantially all of the remaining 50.1% interest in the Pasco Project from its existing 
partners. During 2008, management ﬁ nalized the allocation of purchase price to the net assets acquired with no signiﬁ cant 
changes from the preliminary allocation in the following table: 

Working capital 
Other long-term assets 
Total purchase price 

Less: cash acquired 

Cash paid, net of cash acquired 

$ 

$ 

4,466
20,518
24,984
(1,771)
23,213

JAMAICA PRIVATE POWER COMPANY LTD. DIVESTMENT

C. 
In 2007, a subsidiary of the Company sold its equity investment in the Jamaica Project for $6.2 million. The carrying value of 
the equity investment exceeded the sales price and, accordingly, an impairment charge in the amount of $5.1 million was 
recorded in income from long-term investments in the consolidated statement of income (loss), comprehensive loss and 
deﬁ cit for the year ended December 31, 2007. 

50 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.  Joint venture investments
The Company accounts for seven entities under proportionate consolidation:

Entity name 
Badger Creek Limited 
Chambers 
Koma Kulshan Associates 
Mid-Georgia Cogen LP 
Orlando Cogen Limited LP 
Stockton Cogen Company 
Topsham Hydro Assets 

Proportion consolidated
50.0%
40.0%
49.8%
50.0%
50.0%
50.0%
50.0%

The following summarizes the balance sheets at December 31, 2008 and 2007, and operating results and distributions paid to 
the Company for the years ended December 31, 2008 and 2007 for the Company’s proportionate share of the seven entities:

Assets
Current Assets 
Non-current assets 

Liabilities
Current Assets 
Non-current assets 

Operating results
Revenue 
Net income (loss) 
Distributions paid to the Company 

5.  Property, plant and equipment

Cost  
Less accumulated depreciation 

Company’s share
2008 

2007

$  63,055 
  426,047 
$  489,102 

$ 
57,045
  397,951
$  454,996

$  27,950 
  141,356 
$   169,306 

40,498
  184,173
$  224,671

$  160,410 
73,728 
$  18,742 

  192,935
(153,926)
29,003

$ 

2008 
$  514,020 
(80,478) 
$  433,542 

2007
$  477,042
(64,002)
$  413,040

Depreciation expense of $15,801 and $18,014 was recorded for the years ended December 31, 2008 and 2007, respectively.
In 2008, management reviewed the recoverability of its investment in the Stockton project. The review was undertaken 
as a result of the current status of negotiations to extend the Project’s PPA and the recent deterioration of current and long-
term market conditions for coal-ﬁ red generation assets in California, including the price of natural gas which sets marginal 
electricity prices.

Based on this review, management determined that the carrying value of the Stockton project will not be recovered and 
recorded a pre-tax long-lived asset impairment of $18,471, which represents the entire value of the Project’s property, plant 
and equipment at December 31, 2008. The Company has extended the PPA through March 2010 and is also considering a 
variety of options to recover some of its remaining investment in the Stockton project. The impairment charge is included in 
asset impairments in the consolidated statements of income (loss), comprehensive income (loss) and deﬁ cit. 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

51

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6.  Goodwill

Goodwill, beginning of year 2007 
Adjustments to purchase price allocations 
Impairment loss 
Goodwill, end of year 2007 and 2008 

Path 15  
7,432 
1,486 
– 
8,918 

$ 

$ 

  Chambers 
71,726 
$ 
– 
(71,726) 
– 

Total
79,158
1,486
(71,726)
8,918

$ 

$ 

The impairment of goodwill in the amount of $71,726 at Chambers in 2007, resulted from the signiﬁ cant increase in the 
book value of the reporting unit due to the Project’s PPA being recorded as a ﬁ nancial instrument at fair value. The fair value 
accounting for the PPA and the impairment of goodwill have no impact on the underlying economic value of or anticipated 
future cash distributions from the Chambers Project. See Note 14(c) for additional details on the Chambers PPA.

7.  Other intangible assets and transmission system rights
Other intangible assets include power purchase contracts that are not separately recorded as ﬁ nancial instruments and fuel 
supply agreements. Transmission system rights represent the long-term right to approximately 72% of the capacity of the 
Path 15 transmission line.

Amortization expense of $33,123 and $30,015 was recorded for the years ended December 31, 2008 and 2007, respectively.

Transmission system rights 
Power purchase agreements 
Fuel supply agreements 
Less accumulated amortization 

2008 
$  218,846 
  112,394 
  106,873 
(54,094) 
$  384,019 

2007
$  218,846
70,232
77,518
(29,648)
$  336,948

8.  Long-term investments
The Company has investments accounted for under the equity method and the cost method. The entities under the equity 
method of accounting are Delta-Person Limited Partnership and Rumford Cogeneration Company LP. The entities under the 
cost method of accounting are Gregory Power Partners LP and Selkirk Cogen Partners LP. An analysis of the investments is 
presented below:

Long-term investments, beginning of year 
Proceeds from disposal of Jamaica Project (Note 3(c)) 
Equity earnings (loss), net of impairment charges  
Distributions received from equity investments 
Long-term investments, end of year 

2008 
64,815 
– 
1,692 
(2,742) 
63,765 

$ 

$ 

2007
76,973
(6,175)
(1,898)
(4,085)
64,815

$ 

$ 

52 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9.  Gas transportation contract liability
Prior to June 2007, Onondaga had certain long-term commitments for the provision of natural gas transportation service 
to the Onondaga Project through the year 2013. The contracts provided for ﬁ xed monthly demand charges, in addition to 
variable commodity charges based on the quantity of gas transported. Obligations related to the long-term gas transportation 
agreements were recognized as liabilities in purchase accounting upon the acquisition of Onondaga by the Company. 
These obligations were previously being amortized over the remaining lives of the contracts. In June 2007, Onondaga paid 
$9.75 million to an unrelated third party in exchange for the assumption by the third party of the obligations under the long-
term gas transportation agreements. The carrying value of the transportation contract liability at the date of the transaction 
exceeded the amount paid by Onondaga to extinguish the liability, resulting in a gain of approximately $10 million in the 
second quarter of 2007. The gain was recorded in other project income in the consolidated statement of income (loss), 
comprehensive income (loss) and deﬁ cit. The Onondaga Project funded the transaction with a $9.75 million contribution from 
the Company, which was partially funded by a $9.4 million release of restricted cash at the Path 15 Project. 

10. Credit facility
In August 2007, the Company amended its credit facility. Under the terms of the amendment, the total amount available under 
the credit facility was increased from $75 million to $100 million, of which $50 million may be utilized for letters of credit. The 
November 2008 maturity date of the credit facility has been extended to August 2012. 

Outstanding amounts under the amended credit facility bear interest at the London Interbank Oﬀ ered Rate (“LIBOR”) 
plus an applicable margin that varies based on a credit ratio of a subsidiary of the Company. The range of applicable margin 
is 0.875% to 1.625%. Based on the credit statistics at December 31, 2008, the applicable margin is currently 0.875%. Prior to 
the amendment, the applicable margin was ﬁ xed at 1.50%.

As of December 31, 2008 and 2007, $36,442 and $23,307 was allocated, but not drawn, to support letters of credit for 
contractual credit support at several Projects. In March 2007, the Company borrowed $31,000 under the credit facility 
and used the proceeds to repay the acquisition credit facility related to the acquisition of Path 15. In September 2007, 
the outstanding amount on the credit facility was repaid with proceeds from the permanent ﬁ nancing arrangement for the 
Path 15 Project. In November 2008, the Company borrowed $55,000 under the credit facility and used the proceeds to par-
tially fund the acquisition of Auburndale (Note 3(a)).

The Company must meet certain ﬁ nancial covenants, under the terms of the credit facility, which are generally based 
on the Company’s cash ﬂ ow coverage ratios and not on balance sheet ratios. The facility is secured by pledges of assets and 
interests in certain subsidiaries. The Company expects to be in compliance with its covenants for at least the next year.

11. Long-term debt
Long-term debt represents the Company’s consolidated and proportionately consolidated share of Project long-term debt and 
the unamortized balance of purchase accounting adjustments that were recorded in connection with the Path 15 acquisition 
in order to adjust the debt to its fair value on the acquisition date. Project debt is non-recourse to the Company and amortizes 
during the term of the respective revenue generating contracts of the Projects.

Project debt, interest rates ranging from 2.06% to 9.5% maturing through 2028 
Plus: purchase accounting fair value adjustments  
Less: deferred ﬁ nancing costs 
Less: current portion of Project debt 
Long-term debt 

2008 
$  377,719 
17,564 
(6,616) 
(24,512) 
$  364,155 

2007
$  381,097
19,758
(7,741)
(36,926)
$  356,188

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

53

 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Principal payments due under the terms of short-term and long-term debt in the next ﬁ ve years and thereafter are as follows:

2009 1 
2010 
2011 
2012 
2013 
Thereafter 

$ 

79,512
32,492
34,143
33,306
32,228
221,038
$  432,719

1 

Includes $55 million borrowing under the credit facility to partially fund the Auburndale acquisition. Under the terms of the credit facility, the 
Company has the option to extend the due date of this borrowing up to maturity of the credit facility in August 2012.

The Project debt of joint ventures is secured by the respective facility and its contracts with no other recourse to the 
Company. The loans have certain ﬁ nancial covenants that must be met. At December 31, 2008, all of the Company’s Projects 
were in compliance with the covenants contained in Project-level debt. All of the debt in the table above is represented by 
non-recourse debt of joint ventures, except for the $55,000 outstanding balance with the credit facility as a result of the 
Auburndale acquisition. The Company has executed interest rate swaps to ﬁ x the interest rate on $40 million of this borrow-
ing (Note 14(c)).

12. Subordinated Notes

Subordinated Notes (Cdn$390,946; 2007 – Cdn$392,696) 
Less deferred ﬁ nancing costs 

2008 
$  320,974 
(10,390) 
$  310,584 

2007
$  397,459
(11,367)
$  386,092

The Subordinated Notes will mature in November 2016 subject to redemption under speciﬁ ed conditions at the option of the 
Company, commencing on or after November 18, 2009 (Note 14(c)). Interest is payable monthly in arrears and the principal 
repayment will occur at maturity. 

The Subordinated Notes are denominated in Canadian dollars and are secured by a subordinated pledge of the Company’s 
interest in Holdings and certain subsidiaries, and contain certain restrictive covenants. Cdn$39,501 principal value of the Sub-
ordinated Notes are separately held by two investors and the remaining amount of the outstanding Subordinated Notes form 
a part of the Company’s publicly traded IPSs. 

Interest expense related to the Subordinated Notes was $40,169 and $40,818 for the years ended December 31, 2008 and 

2007, respectively. 

13. Convertible Debentures
On October 11, 2006, the Company issued Cdn$60,000 ($48,790, net of deferred ﬁ nancing costs, at December 31, 2008) 
aggregate principal amount of 6.25% Convertible Secured Debentures (“Debentures”) for gross proceeds of $52,780. The 
Debentures pay interest semi-annually on April 30 and October 31 of each year. The Debentures mature on October 31, 2011 
and are convertible into approximately 80.6452 IPSs per Cdn$1,000 principal amount of Debentures, at any time, at the option 
of the holder, representing a conversion price of Cdn$12.40 per IPS. 

Interest expense was $3,490 and $3,532 for the years ended December 31, 2008 and 2007, respectively. 

54 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. Financial instruments
A.  CLASSIFICATION OF FINANCIAL INSTRUMENTS
The following table contains the carrying value and classiﬁ cation of the Company’s ﬁ nancial instruments as of December 31, 
2008 and 2007:

Financial assets:
Held for trading measured at fair value:

Cash and cash equivalents 
Restricted cash 
Current portion of derivative instruments asset 

  Derivative instruments asset 
Loans and receivables, measured at amortized cost: 

Accounts receivable 
Income tax recoverable 
Long-term deposits 

Financial liabilities:
Held for trading, measured at fair value:

Current portion of derivative instruments liability 

  Derivative instruments liability 
Other fi nancial liabilities, measured at amortized cost: 

Accounts payable and accrued liabilities 
Interest payable on Subordinated Notes and  Convertible Debentures 

  Dividends payable 

Current portion of long-term and short-term debt 
Long-term debt 
Subordinated Notes 
Convertible Debentures 

2008 

2007

$ 

50,071 
25,372 
15,001 
  109,482 

$ 

48,128 
2,300 
664 

$ 

10,031 
22,132 

$ 

31,783 
3,455 
1,918 
79,512 
  364,155 
  310,584 
48,790 

$ 

$ 

$ 

$ 

55,990
38,304
23,753
79,611

38,134
10,261
–

7,822
8,044

32,886
4,271
2,127
36,926
356,188
386,092
59,912

The fair value of ﬁ nancial assets and current ﬁ nancial liabilities which are measured at amortized cost approximate their carrying 
value because of the short-term nature of the instruments. The fair-value of long-term ﬁ nancial liabilities at December 31, 2008 
was determined using quoted market prices, as well as discounting the remaining contractual cash ﬂ ows using a rate at which 
the Company could issue debt with a similar maturity as of the balance sheet date and are summarized below:

Long-term debt 
Subordinated Notes 
Convertible Debentures 

$  467,300
264,739
46,675

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

55

 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

B.  CHANGE IN FAIR VALUE OF DERIVATIVE INSTRUMENTS
The following table contains the components of income (expense) related to changes in the fair value of the Company’s 
derivative ﬁ nancial instruments:

Change in fair value of derivative instruments
Chambers power purchase agreement 
Onondaga indexed swap and hedge 
Project-level interest rate swaps 
Project-level natural gas swaps 

2008 

2007

$ 

$ 

74,608 
(10,844) 
(5,325) 
(3,378) 
55,061 

$  (106,113)
(20,290)
(1,974)
–
$  (128,377)

C.  DERIVATIVE INSTRUMENTS
The components of derivative instruments assets and liabilities as of December 31, 2008 and 2007 are set forth in the follow-
ing table:

Current portion of derivative instrument asset:
Chambers power purchase agreement 
Onondaga index swap hedge 
Project-level interest rate swaps 

Derivative instruments asset
Chambers power purchase agreement 
Foreign currency forward contracts 
Lake natural gas swaps 

Current portion of derivative instruments liability
Lake natural gas swaps 
Auburndale natural gas swaps 
Foreign currency forward contracts 
Onondaga index swap and hedge 
Interest rate swaps 

Derivative instruments liability
Lake natural gas swaps 
Foreign currency forward contracts 
Interest rate swaps 

2008 

2007

$ 

$ 

15,001 
– 
– 
15,001 

$  109,258 
– 
224 
$  109,482 

$ 

$ 

$ 

$ 

4,017 
4 
744 
– 
5,266 
10,031 

595 
12,998 
8,539 
22,132 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

5,607
17,689
457
23,753

44,045
35,566
–
79,611

–
–
–
6,845
977
7,822

–
–
8,044
8,044

Chambers Power Purchase Agreement  
The power purchase agreement (“PPA”) at the proportionately consolidated Chambers Project meets the accounting deﬁ nition 
of a derivative instrument. The PPA does not qualify for exclusion from CICA Handbook Section 3855, “Financial Instruments 
– Recognition and Measurement”, and has not been designated as a hedge. Accordingly, the PPA has been recorded at its fair 
value in the consolidated balance sheets and changes in the fair value are recognized in change in fair value of derivative 
instruments in the consolidated statements of income (loss), comprehensive income (loss) and deﬁ cit.

56 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the PPA is measured by comparing the net present value of the cash ﬂ ows expected to be received under 
the terms of the PPA to the net present value of the cash ﬂ ows that would be received if the same volumes were sold at projected 
market power prices over the term of the contract expiring in 2024. Accordingly, periodic changes to the fair value of the PPA 
reﬂ ect changes in forward market conditions and do not directly impact the amount of cash ﬂ ow the Chambers Project will 
receive under the terms of the PPA. The most signiﬁ cant factor that impacts the calculated fair value of the PPA is the projected 
forward market prices of power, and such prices can vary signiﬁ cantly from period to period. As of December 31, 2008, a 10% 
change in the projected average forward power prices through the term of PPA expiring in 2024 would change the fair value 
of the PPA by approximately $27 million. 

Onondaga indexed swap and hedge
A swap agreement (“Indexed Swap”) between a utility company and Onondaga, which had replaced Onondaga’s original 
power purchase contract, expired on June 30, 2008. The Indexed Swap was a derivative ﬁ nancial instrument under which the 
utility company made monthly payments to Onondaga based upon the diﬀ erential between an indexed contract price and 
a market reference price for electricity. The indexed contract price ﬂ uctuated in relation to the market cost of natural gas and 
a prescribed index of inﬂ ation. The notional quantity of electricity for the purpose of these calculations was ﬁ xed for the full 
term of the Indexed Swap.

In addition, Onondaga was party to a commodity derivative instrument (“Indexed Swap Hedge”), which locked in 

favourable gas, power and capacity pricing under the Indexed Swap. The Indexed Swap Hedge expired on June 30, 2008.

Foreign currency forward contracts
The Company uses forward foreign currency contracts to manage its exposure to changes in foreign exchange rates, as the 
Company earns its income in the United States but has the obligation to make distributions to shareholders predominantly 
in Canadian dollars. Since its inception, the Company has established a hedging strategy for the purpose of reinforcing the 
long-term sustainability of its distributions. The Company has executed this strategy by entering into forward contracts to 
purchase Canadian dollars at ﬁ xed rates of exchange suﬃ  cient to make monthly distributions through December 2013 at the 
current annual dividend level of Cdn$0.46 per common share, as well as interest payments on the Subordinated Notes and 
Debentures. It is the Company’s intention to periodically consider extending the length of these forward contracts. Changes in 
the fair value of the Company’s forward contracts partially oﬀ set foreign exchange gains or losses on the U.S. dollar equivalent 
of the Company’s Canadian dollar obligations. 

The following table summarizes the Company’s forward foreign currency contracts with monthly settlement terms as of 

December 31, 2008:

Period  
2009  
2010 - 2013  

Notional monthly amounts

Sell 
U.S. dollars  
4,974  
5,289  

 Buy 
 Cdn. dollars  
6,000  
6,000  

  Average
rate
1.2062
1.1344

In addition to the forward contracts in the table above that settle on a monthly basis, the Company has executed forward 
contracts to purchase Canadian dollars at ﬁ xed rates of exchange suﬃ  cient to make semi-annual payments on the Debentures. 
The contracts provide for the purchase of Cdn$1.9 million in April and in October of 2008 through 2011 at a rate of 1.1075 
Canadian dollars per U.S. dollar.

The foreign exchange forward contracts are carried at estimated fair value based on quoted market prices. Changes in 
the fair value of the foreign currency forward contracts are reﬂ ected in foreign exchange loss (gain) in the consolidated 
statements of income (loss), comprehensive income (loss) and deﬁ cit. 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

57

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the components of recorded foreign exchange gain (loss) for the periods indicated:

Unrealized foreign exchange gains (losses):
Subordinated Notes and Convertible Debentures 
Forward contracts and other 

Realized foreign exchange gains on forward contract settlements 

2008 

2007

$ 

$ 

85,212 
(48,537) 
36,675 
8,044 
44,719 

$ 

$ 

(68,419)
30,703
(37,716)
7,574
(30,142)

The following table illustrates the income (loss) that would be recorded on the Company’s ﬁ nancial instruments in the event 
of a 10% hypothetical decrease in the value of the U.S. dollar compared to the Canadian dollar as of December 31, 2008: 

Subordinated Notes 
Convertible Debentures 
Foreign currency forward contracts 

$ 

$ 

(32,097)
(4,926)
33,874
(3,149)

Pasco natural gas swaps
The Pasco Project’s operating margin was exposed to changes in natural gas prices for the second half of 2008 as a result of 
the expiry of its favorably-priced natural gas supply contract on June 30, 2008 before the expiry of its PPA at the end of 2008. 
In the second quarter of 2008, the Company entered into a series of ﬁ nancial swaps that eﬀ ectively ﬁ xed the price of natural 
gas at the Pasco Project during the second half of 2008 at a weighted average price of $12.24/Mmbtu. 

These natural gas swaps are derivative ﬁ nancial instruments and were recorded in the consolidated balance sheet at fair 
value. Changes in the fair value of the natural gas swaps were recorded in change in fair value of derivative instruments in the 
consolidated statements of income (loss), comprehensive income (loss) and deﬁ cit. The natural gas swaps at Pasco expired 
in December 2008.

Beginning January 1, 2009, a new 10-year PPA at the Pasco Project requires the PPA counterparty to provide natural gas 
needed to operate the plant and, as a result, the Pasco Project is no longer exposed to changes in market prices of natural gas.

Lake and Auburndale natural gas swaps
The Lake Project’s operating margin is exposed to changes in natural gas prices from the expiry of its natural gas supply 
contract on June 30, 2009 through the expiry of its PPA on July 31, 2013. The Auburndale Project purchases natural gas under 
a fuel supply agreement which provides approximately 80% of the Company’s fuel requirements through June 30, 2012. 
The remaining 20% is purchased at spot market prices and therefore the Project is exposed to changes in natural gas prices 
through the termination of the fuel supply agreement. 

 The  Company  is  executing  a  strategy  to  mitigate  the  future  exposure  to  changes  in  natural  gas  prices  at  Lake  and 
Auburndale by periodically entering into ﬁ nancial swaps that eﬀ ectively ﬁ x the price of natural gas required at these projects.
These natural gas swaps are derivative ﬁ nancial instruments and are recorded in the consolidated balance sheet at fair 
value. Changes in the fair value of the natural gas swaps are recorded in other comprehensive income (loss) as they have been 
designated as a hedge of the risk associated with changes in market prices of natural gas.

58 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   
 
 
 
 
 
 
 
 
 
 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Subordinated notes prepayment option
The Company has the option to redeem the Subordinated Notes beginning on November 18, 2009 at an initial redemption 
price equal to 105% of the principal amount being redeemed. The Company has determined that the redemption option is 
an embedded derivative that is recorded at fair value and periodic changes in fair value are recorded in other expenses in the 
consolidated statements of income (loss), comprehensive income (loss) and deﬁ cit. As of December 31, 2008, the fair value 
of the redemption option is zero.

Interest rate swaps
The Company’s proportionately consolidated Mid-Georgia and Chambers Projects have executed interest rate swaps to 
economically ﬁ x a portion of the respective Project’s exposure to changes in interest rates related to variable-rate project debt. 
These interest rate swaps are derivative ﬁ nancial instruments and are not designated as hedges for accounting purposes. 
Interest rate swaps are recorded as derivative instruments liability in the consolidated balance sheet and changes in fair value 
are recorded in change in fair value of derivative instruments in the consolidated statements of income (loss), comprehensive 
income (loss) and deﬁ cit. The primary factor that inﬂ uences the fair value of interest rate swaps is changes in projected forward 
market interest rates. 

The fair value of interest rate swaps reﬂ ects the cash ﬂ ows due to or from the Company on the balance sheet date. Cash 
settlements related to interest rate swaps are recorded in interest expense in the consolidated statements of income (loss), 
comprehensive income (loss) and deﬁ cit.

The Company has executed interest rate swaps on the revolving credit facility (Note 10) and at its proportionately 
consolidated Auburndale Project to economically ﬁ x a portion of the their respective exposure to changes in interest rates 
related to variable-rate debt. The interest rate swap agreements were designated as a cash ﬂ ow hedge of the forecasted 
interest  payments  under  the  existing  credit  facility  as  of  November  2008. The  interest  rate  swap  termination  date  for 
Auburndale is November 30, 2009 and for the revolving credit facility is November 30, 2011. 

The interest rate swap is a derivative ﬁ nancial instrument and is recorded in the balance sheet at fair value. Changes in 
the fair value of the interest rate swap are recorded in other comprehensive income (loss) as they have been designated as a 
hedge of the risks associated with the changes in the market interest rates.

D.  AUCTION RATE SECURITIES
As of December 31, 2007, approximately $26 million of the Company’s cash and cash equivalents were invested in auction-rate 
securities (“ARSs”). ARSs typically have an underlying maturity of up to 40 years but have historically traded in seven- or 28-day 
intervals in a highly liquid market. The ARSs that were held at December 31, 2007 were redeemed at auctions held in January 
2008 and the proceeds were re-invested in ARSs.

In February 2008, the overall market for ARSs suﬀ ered a signiﬁ cant decline in liquidity. Since early March 2008, most of 
the auctions of ARSs have been unsuccessful, resulting in the Company continuing to hold these securities and the issuers 
paying interest at the maximum contractual rate. 

In September and November 2008, all of the Company’s investments in ARS were sold at par plus accrued interest, for 

$36.5 million. 

E.  LOANS AND RECEIVABLES
Accounts receivable is primarily comprised of amounts due to the Company’s consolidated and proportionately consolidated 
Projects for sales of electricity under long-term contracts. As of December 31, 2008, there are no signiﬁ cant amounts of 
accounts receivable past due. The carrying value of loans and receivables approximates their fair value due to the short-term 
maturity of those ﬁ nancial instruments.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

59

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

F.  OTHER FINANCIAL LIABILITIES
Convertible Debentures 
The 6.25% Convertible Secured Debentures (“Debentures”) are due October 31, 2011. Interest is payable semi-annually in 
arrears on April 30 and October 31 of each year. The Debentures are convertible into 80.6452 IPS per Cdn$1,000 principal 
amount of Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per IPS.

G.  FINANCIAL RISK MANAGEMENT
The Company has exposure to market risk, credit risk and liquidity risk from its use of ﬁ nancial instruments:

Market risk  
Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and commodity prices, will 
aﬀ ect the Company’s cash ﬂ ows or the value of its holdings of ﬁ nancial instruments. The objective of market risk management 
is to minimize the impact that market risks have on the Company’s cash ﬂ ows as described in the following paragraphs.

The Company is exposed to changes in foreign currency exchange rates because it earns all of its income in U.S. dollars 
but has substantial obligations in Canadian dollars. The Company manages this risk through the use of foreign currency 
forward contracts and, where possible, establishing any new obligations in U.S. dollars instead of Canadian dollars. See Note 
14(c) – foreign currency forward contracts for additional details about the Company’s exposure to changes in currency ex-
change rates and the ﬁ nancial instruments that mitigate this risk through 2013. 

The impact of changes in interest rates do not have a signiﬁ cant impact on cash payments that are required on the 
Company’s debt instruments as approximately 90% of the Company’s debt, including non-recourse project-level debt, bears 
interest at ﬁ xed rates. Some of the non-recourse debt obligations at the Company’s proportionately consolidated Auburndale, 
Mid-Georgia and Chambers projects bear interest at variable rates. 

Exposure to changes in interest rates related to this variable rate debt has been mitigated through the use of interest 
rate swaps. See Note 14(c) – interest rate swaps for additional details. After considering the impact of interest rate swaps, the 
Company’s share of variable-rate debt at consolidated and proportionately consolidated projects was $40.7 million at 
December 31, 2008. A hypothetical change in average interest rates of 100 basis points would change interest expense by 
approximately $0.4 million on an annual basis.

The Company’s current and future cash ﬂ ows are impacted by changes in electricity, natural gas and coal prices. 
The combination of long-term energy sales and fuel purchase agreements are designed to mitigate the impacts to cash ﬂ ows 
of changes in commodity prices by generally passing on changes in fuel prices to the buyer of the energy. 

Credit risk  
Credit risk is the risk of ﬁ nancial loss to the Company if a customer or counterparty to a ﬁ nancial instrument fails to meet 
its contractual obligations. The Company’s maximum exposure to credit risk is the carrying value of ﬁ nancial assets included 
in the consolidated balance sheet.

The Company’s exposure to credit losses from accounts receivable at its Projects is mitigated by the fact that most 
Projects sell power under long-term contracts with investment-grade utilities and other counterparties. The Company does 
not have a history of credit losses related to long-term contracts at the Projects and no signiﬁ cant amounts are currently past 
due. The Company’s risk of credit loss on other ﬁ nancial instruments is managed by conducting business with ﬁ nancial 
institutions that have superior credit ratings. 

Liquidity risk  
Liquidity  risk  is  the  risk  that  the  Company  will  not  be  able  to  meet  its  ﬁ nancial  obligations  as  they  become  due. The 
Company believes that future cash ﬂ ows from operating activities and access to additional liquidity through capital and bank 
markets will be adequate to meet its ﬁ nancial obligations. 

60 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. Capital management
The Company’s overall objectives in capital management are to optimize the cost of capital related to existing assets 
and growth opportunities, as well as maintaining a prudent capital structure whose risk characteristics do not jeopardize 
realization of long-term value from the Company’s assets. The capital structure of the Company consists of non-recourse 
Project-level debt, a credit facility, Subordinated Notes, Debentures and Common Stock.

The Company’s IPSs each consist of one Common Share and Cdn$5.767 principal amount of Subordinated Notes. 
The Company currently pays monthly distributions at an annual rate of Cdn$1.094 per IPS, which consists of a dividend per 
common share of Cdn$0.46 per year and interest on the Subordinated Notes.

The Company has historically raised debt capital at the operating or Project-level at lower interest rates than what would 
be required for corporate-level debt. These ﬁ nancings are structured as non-recourse to the Company and an adverse impact 
to debt at any single Project has no inﬂ uence on debt at other Projects, and in virtually all cases the principal fully amortizes 
before the primary power purchase agreement expires. 

In  some  cases  the  Company  may  raise  an  additional  tranche  of  non-recourse,  fully-amortizing  debt  at  a  holding 

company that owns the Project equity. 

The appropriate degree of total operating leverage is a function of assessing the potential volatility of projected cash 
ﬂ ows to maintain a low probability that a temporary Project operating issue could cause the Company’s equity in the Project 
to be at risk before resolving the problem. There are also lender safeguards in these ﬁ nancings such as debt service and major 
maintenance reserves that help mitigate impacts to the Company’s cash ﬂ ow from temporary Project operating issues. 

The credit facility is designed for several purposes: 1) to support letters of credit covering certain contingent performance 
risks at several Projects, 2) to provide corporate liquidity in the case of signiﬁ cant unexpected temporary interruption or 
reductions to operating cash ﬂ ows, and 3) to contribute to bridge ﬁ nancing for potential acquisitions. The credit facility has 
a total capacity of $100 million with two equal bank participants. Acquisition bridge facilities have also historically been placed 
at this senior corporate level with the revolving credit facility lenders.

The capital structure is periodically reviewed by the Company’s management and Board of Directors to determine 
whether  changes  are  required  to  meet  the  objectives  outlined  above. The  Company  has  the  option  to  redeem  the 
Subordinated Notes beginning on November 18, 2009 at an initial redemption price equal to 105% of the principal amount 
being redeemed. Management will periodically assess this option beginning in November 2009 and will consider exercising 
the call option if the Subordinated Notes can be recapitalized in a manner that beneﬁ ts the Company’s shareholders. 

The Company is not required to repay Subordinated Notes before they become due in November 2016 and will exercise 
its call option only if alternatives exist to reﬁ nance the called debt on terms that beneﬁ t the Company on a long-term basis. 
Examples  of  potentially  positive  alternatives  could  include:  reduction  of  foreign  currency  risk  by  reﬁ nancing  the 
Subordinated Notes with U.S. dollar-denominated debt; reducing interest expense by reﬁ nancing the Subordinated Notes 
at lower interest rates; and reducing the Company’s overall debt by reﬁ nancing any or all of the Subordinated Notes by 
issuing equity. All of these options are subject to market conditions at the time the option is being considered.

There were no changes in the Company’s approach to capital management during the period. Neither the Company 

nor any of its subsidiaries is subject to externally imposed capital requirements.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

61

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. Income taxes

Current income tax expense (beneﬁ t) 
Future tax expense (beneﬁ t) 

2008 
(12) 
12,535 
12,523 

$ 

$ 

2007
3,974
(51,748)
(47,774)

$ 

$ 

The following is a reconciliation of income taxes calculated at the Canadian enacted statutory rate of 33.5% and 36.12% at 
December 31, 2008 and 2007, respectively, to the provision for income taxes in the consolidated statements of income (loss), 
comprehensive income (loss) and deﬁ cit:

Computed income tax recovery at Canadian statutory rate 
Decrease resulting from:
Operating countries with diﬀ erent income tax rates 

Valuation allowance 

Non-taxable foreign-source income 
Permanent diﬀ erences 
Canadian loss carryforwards 
Branch proﬁ ts tax 
Prior year true-up 
Other 

Income tax expense (beneﬁ t) 

2008 
41,276 

$ 

2007
(71,149)

$ 

8,009 
49,285 
(39,840) 
9,445 
– 
4,367 
(2,786) 
2,368 
(1,078) 
207 
3,078 
12,523 

$ 

(7,643)
(78,792)
52,710
(26,082)
(475)
(8,682)
(12,051)
993
(1,544)
67
(21,692)
(47,774)

$ 

The tax eﬀ ect of temporary diﬀ erences that give rise to signiﬁ cant portions of the future tax assets and future tax liabilities at 
December 31, 2008 and 2007 are presented below:

Future tax assets:
Intangible assets 
Loss carryforwards 
Gas transportation contract and other accrued liabilities 
Unrealized foreign exchange loss on Subordinated Notes 
IPS issuance costs 
Natural gas and interest rate hedges 
Total future tax assets 
Valuation allowance 

Future tax liabilities:
Property, plant and equipment 
Unrealized foreign exchange gain 
Other 
Total future tax liabilities 
Net future tax asset (liability) 

62 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

2008 

2007

$ 

$ 

18,888 
41,512 
16,182 
5,497 
540 
2,136 
84,755 
(49,524) 
35,231 

(72,024) 
(6,713) 
(1,377) 
(80,114) 
(44,883) 

$ 

$ 

26,725
38,152
9,889
28,387
3,199
–
106,352
(89,364)
16,988

(48,614)
(13,835)
(1,453)
(63,902)
(46,914)

 
  
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
  
 
 
 
 
 
 
  
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2008, the Company had the following net operating loss carryforwards that are scheduled to expire in 
the following years:

2014 
2015 
2026 
2027 
2028 

$ 

5,258
28,752
29,786
38,246
34,929
$  136,971

These losses relate to the Canadian entity and may only be used to oﬀ set the future income of the Canadian entity for Canadian 
income tax purposes. At December 31, 2008, a full valuation allowance was taken against the future tax assets set up in respect 
of the Canadian entity’s loss carryforwards as the Company believes that it is not more likely than not that the Canadian entity 
would be able to use any of these loss carryforwards.

17. Common Stock and normal course issuer bid

Balance, December 31, 2007 
Issuance of Common Stock 
Shares acquired in normal course issuer bid 
Balance, December 31, 2008 

Number
of shares  
61,470 
30 
(559) 
60,941 

  Amount
$  216,636
127
(1,875)
$  214,888

On July 18, 2008, the Company approved a normal course issuer bid to purchase up to four million IPSs, representing 
approximately 8% of the Company’s public ﬂ oat. The Toronto Stock Exchange (“TSX”) approved the issuer bid on July 23, 2008, 
and purchases under the bid commenced on July 25, 2008. As of December 31, 2008, the Company had acquired 558,620 
IPSs at an average price of Cdn$8.78 under the terms of the issuer bid. The issuer bid will terminate on July 24, 2009 or such 
earlier date that the Company has acquired the maximum number of IPSs under the issuer bid. Atlantic Power will pay the 
market price at the time of acquisition for any IPSs purchased through the facilities of the TSX, and all IPSs acquired under 
the bid will be canceled.

The purchase price in excess of the average book value of the shares in the amount of $275 has been allocated to 

deﬁ cit.

18.  Long-term incentive plan
On March 26, 2008 and March 28, 2007, the Board of Directors approved grants of notional units to acquire a maximum of 
142,717 and 172,071 IPSs, respectively, under the terms of the LTIP. The weighted average fair value per notional unit granted 
was  Cdn$10.18  and  Cdn$10.93  for  2008  and  2007,  respectively. The  measurement  date  for  the  awards  for  accounting 
purposes occurred when participants were informed of the details of their awards in April 2008 and April 2007, respectively. 
As a result, compensation expense related to the LTIP was recorded in the amounts of $770 and $970 for the years ended 
December 31, 2008 and 2007, respectively.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

63

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
  
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

19. Basic and diluted earnings (loss) per share
The following table sets forth the weighted average numbers of IPSs outstanding and potentially dilutive shares utilized in 
per share calculations:

Basic IPSs outstanding 
Dilutive potential IPSs:
Convertible Debentures 
LTIP notional units 
Fully diluted IPSs 

2008 
61,290 

4,839 
221 
66,350 

2007
61,471

–
–
61,471

Diluted earnings (loss) per share is computed including dilutive potential IPSs as if they were outstanding IPSs during the 
year. Dilutive potential IPSs include IPSs that would be issued if all of the convertible debentures were converted into IPSs at 
January 1, 2008. Dilutive potential IPSs also include the weighted average number of IPSs, as of the date such notional units 
were granted, that would be issued if the unvested notional units outstanding under the Company’s LTIP were vested and 
redeemed for IPSs under the terms of the LTIP.

Because the Company reported a loss during the year ended December 31, 2007, the eﬀ ect of including potentially 

dilutive shares in the calculation during those periods is anti-dilutive.

20. Accumulated other comprehensive loss
The components of accumulated other comprehensive loss are as follows:

Cumulative unrealized loss on natural gas hedges 
Cumulative unrealized loss on interest rate swaps 
Future tax beneﬁ t 

2008 
(4,393) 
(947) 
2,136 
(3,204) 

$ 

$ 

$ 

$ 

2007
–
–
–
–

21. Related party transactions
In connection with the Company’s initial public oﬀ ering, ArcLight Energy Partners Funds I, L.P. (“Fund I”) and ArcLight En-
ergy Partners Funds II, L.P. (“Fund II”, and, together with Fund I, the “ArcLight Funds”) and Caithness Energy, LLC (“Caithness”) 
(together with the ArcLight Funds, the “Former Investors”) acquired the right to request, at any time, that Holdings purchase 
for cancellation all or any portion of the Former Investors’ interests in Holdings, subject to a minimum remaining 10% interest 
for a two-year period from November 18, 2004. This liquidity right was treated as a liability of the Company and recorded at fair 
value on the consolidated balance sheets. Any change in the non-controlling interest liability was recognized in the consoli-
dated statements of income (loss), comprehensive income (loss) and deﬁ cit as a change in non-controlling interest liability. 

64 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Former Investors have exercised the liquidity right in a series of transactions since the initial public oﬀ ering through 
February 2007 as follows:

October 2005 
October 2006 
February 2007 

Amount
paid to former 
Investors 
64,374 
87,287 
76,888 

$ 

Incremental 
share acquired(i) 

12.0% 
15.5% 
14.4% 

Former Investors’
remaining share
29.9%
14.4%
0.0%

(i) 

Represents incremental portion of Holdings purchased by the Company from the Former Investors in the transaction.

The amounts paid to the Former Investors in the transactions above were ﬁ nanced by the Company through the sale of IPSs 
and Convertible Debentures.

At January 1, 2007, $74,433 of restricted cash included in the consolidated balance sheet was held in escrow pending 
regulatory approval of a transaction whereby the remaining interests of the Former Investors were acquired by Holdings. In 
February 2007, the required regulatory approval was obtained and the transaction was completed. Holdings is now a wholly- 
owned subsidiary of the Company and the liquidity right of the Former Investors has been extinguished.

During the year ended December 31, 2008, in accordance with the management agreement between the Company and 
Atlantic Power Management, LLC (that is owned by the ArcLight Funds), the Company incurred management and incentive 
fees of $356 and $864, respectively. During the year ended December 31, 2007, the Company incurred management and 
incentive fees of $344 and $869, respectively.

On November 21, 2008, the Company acquired Auburndale from an entity owned by the ArcLight Funds and Caisse 
de dépôt et placement du Québec, which owns approximately 19% of the Company’s IPSs and Cdn$36.5 million of its 
outstanding Subordinated Notes. See Note 3(a).

22. Commitments and contingencies
From time to time, the Company, its subsidiaries and the Projects are parties to disputes and litigation that arise in the normal 
course of business. The Company assesses its exposure to these matters and records estimated loss contingencies when a 
loss is likely and can be reasonably estimated. There are no matters pending as of December 31, 2008 which are expected to 
have a material impact on the Company’s ﬁ nancial position or results of operations.

23. Subsequent events
On  March  23,  2009,  Path  15,  FERC  staﬀ ,  and  the  intervenors  in  the  Project’s  rate  case  for  the  2008-10  period  ﬁ led  an 
uncontested settlement with the FERC. The Company expects the FERC to approve the settlement in the next two to three 
months. Management does not expect the settlement to have a signiﬁ cant impact on the ﬁ nancial position or results of 
operations of the Company.

24. Comparative fi gures
Certain 2007 ﬁ gures have been reclassiﬁ ed to conform to the ﬁ nancial statement presentation adopted in 2008.

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T   

65

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Atlantic Power Corporation

Atlantic Power Corporation Directors

Exchange Listing
IPSs Issued and Outstanding: 60,940,731
Ticker Symbol: ATP.UN 

Cdn$60 million 6.25% Convertible Debentures 
due October 31, 2011
Ticker Symbol: ATP.DB  

Irving Gerstein
Chairman of the Board 
Toronto, Ontario
Senator Gerstein is a retired executive and is 
currently a Director of Medical Facilities Corporation, 
Economic Investment Trust Limited and Student 
Transportation of America.

Ken Hartwick
Chairman of the Audit Committee
Toronto, Ontario
Mr. Hartwick is President and CEO of Ontario 
Energy Savings Corp., which is a wholly-owned 
subsidiary of, and provides administrative services 
to, Energy Savings Income Fund, an income trust 
traded on the TSX.

John McNeil
Toronto, Ontario
Mr. McNeil is President of BDR North America Inc., an 
energy consulting ﬁ rm based in Toronto, Ontario.

Barry Welch
Boston, Massachusetts
Mr. Welch is President and CEO of 
Atlantic Power Management, LLC.

Bill Whitman
Ridgewood, New Jersey
Mr. Whitman is currently an independent 
consultant advising and representing clients on 
energy-from-waste matters. 

Exchange: TSX

Investor Relations 
Contact: Barry Welch
Tel:  617.977.2700

Corporate Headquarters
355 Burrard Street, Suite 1900
Vancouver, BC  V6C 2G8

Website
www.atlanticpowercorporation.com

Annual Meeting 
Friday, June 19, 2009 at 10:00 AM EDT
The King Edward Hotel
Chelsea Room
37 King Street East
Toronto, ON  M5C 1E9

Transfer Agent
Computershare Investor Services, Inc.
100 University Avenue
Toronto, ON  M5J 2Y1

Independent Auditors 
KPMG LLP
Commerce Court West 
199 Bay Street
Toronto, ON  M5L 1B2

Legal Counsel
Goodmans LLP
250 Yonge Street
Toronto, ON  M5B 2M6

66 

ATLANTIC PO WER CORPORATION    2008 ANNUAL REPOR T

Directors 

from left to right: 

Barry Welch, 

John McNeil, 

Irving Gerstein, 

Bill Whitman

and Ken Hartwick

Atlantic Power Management

200 Clarendon Street
Floor 25
Boston, MA 02116
t  617.977. 2400
f   617.977. 2410
info@atlanticpowercorporation.com

Barry Welch 
President and Chief 
Executive Offi  cer

Patrick Welch 
Chief Financial Offi  cer and 
Corporate Secretary

Paul Rapisarda 
Managing Director, Asset 
Management & Acquisitions

Atlantic Power Management, LLC
200 Clarendon Street, Floor 25
Boston, Massachusetts  02116
Telephone: 617. 977. 2400
Fax: 617. 977. 2410

www.atlanticpowercorporation.com