- Securities Registration Statement (S-1/A)
16 September 2011 - 12:07PM
Edgar (US Regulatory)
Table of Contents
As filed with the Securities and Exchange Commission on September 15, 2011
Registration No. 333-176257
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
AMENDMENT NO. 1
TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
ATLANTIC POWER CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
|
|
|
|
|
British Columbia, Canada
(State or Other Jurisdiction of
Incorporation or Organization)
|
|
4900
(Primary Standard Industrial
Classification Code Number)
|
|
55-0886410
(I.R.S. Employer
Identification Number)
|
200 Clarendon St., Floor 25
Boston, Massachusetts 02116
(617) 977-2400
(Address, Including Zip Code, and Telephone Number, Including
Area Code, of Registrant's Principal Executive Offices)
Barry E. Welch
President and Chief Executive Officer
Atlantic Power Corporation
200 Clarendon St., Floor 25
Boston, Massachusetts 02116
(617) 977-2400
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)
|
|
|
Copies to:
|
Laura Hodges Taylor, Esq.
Yoel Kranz, Esq.
Goodwin Procter LLP
Exchange Place
Boston, Massachusetts 02109
Tel: (617) 570-1000
Fax: (617) 523-1231
|
|
Christopher J. Cummings, Esq.
Paul, Weiss, Rifkind, Wharton & Garrison LLP
1285 Avenue of the Americas
New York, New York 10019-6064
Tel: (212) 373-3000
Fax: (212) 757-3990
|
Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes
effective.
If
any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the
following box:
o
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check
the following box and list
the Securities Act registration statement number of the earlier effective registration statement for the same offering.
o
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and
list the
Securities Act registration statement number of the earlier effective registration statement for the same offering.
o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and
list the
Securities Act registration statement number of the earlier effective registration statement for the same offering.
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting
company. See the definition of "larger accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
|
|
|
|
|
|
|
Large accelerated filer
o
|
|
Accelerated filer
o
|
|
Non-accelerated filer
ý
(Do not check if a
smaller reporting company)
|
|
Smaller reporting company
o
|
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall
file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as
amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may
determine.
Table of Contents
The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the
registration statement filed with the Securities and Exchange Commission is declared effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer
to buy these securities in any jurisdiction where the offer or sale of such securities is not permitted.
Subject to Completion
Preliminary Prospectus dated September 15, 2011
PROSPECTUS
Shares
Common Shares
We are offering of our common shares, no par value per share.
Our common shares are listed on the New York Stock Exchange under the symbol "AT" and on the Toronto Stock Exchange under the symbol "ATP." On September 14, 2011,
the last
reported sale price of our common shares on the New York Stock Exchange and the Toronto Stock Exchange was $14.79 and C$14.65, respectively, per share.
Investing in our common shares involves a high degree of risk. Before buying any shares you should carefully read the discussion of material
risks of investing in our common shares under the heading "Risk factors" beginning on page 19 of this prospectus.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined
if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
|
|
|
|
|
|
|
|
|
|
Per Share
|
|
Total
|
|
Public offering price
|
|
$
|
|
|
$
|
|
|
Underwriting discounts and commissions
|
|
$
|
|
|
$
|
|
|
Proceeds, before expenses, to us
|
|
$
|
|
|
$
|
|
|
This
offering is made in contemplation of our acquisition of all the outstanding limited partnership interests in Capital Power Income L.P. pursuant to a plan of arrangement (the
"Plan of Arrangement") under the Canada Business Corporations Act, as more fully described herein. We intend to use the net proceeds of this offering to finance a portion of the cash payable by us
under the Plan of Arrangement. However, this offering is not conditioned on the completion of the Plan of Arrangement and there can be no assurance that the Plan of Arrangement will be completed. The
shares offered hereby will remain outstanding whether or not the Plan of Arrangement is completed.
The
underwriters may also purchase up to an additional common shares from us at the public offering price, less the underwriting discounts and commissions payable by us
to cover over-allotments, if any, within 30 days from the date of this prospectus.
The
underwriters expect to deliver the common shares on or about , 2011.
Joint Book-Running Managers
|
|
|
TD Securities
|
|
Morgan Stanley
|
The
date of this prospectus is , 2011.
Table of Contents
TABLE OF CONTENTS
You should rely only on information contained in this document or to which we have referred you. We have not, and our
underwriters have not, authorized anyone to provide any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared.
If anyone provides you with different or inconsistent information, you should not rely on it. We take no responsibility for, and can provide no assurance as to the reliability of, any other
information that others may give you. We are not, and the underwriters are not, making an offer to sell the securities in any jurisdiction where the offer or sale is not permitted. This document may
only be used where it is legal to sell these securities.
As
used in this prospectus, the terms "Atlantic Power," the "Company," "we," "our" and "us" refer to Atlantic Power Corporation, together with those entities owned or controlled by
Atlantic Power Corporation, unless the context indicates otherwise. Unless otherwise noted, all references to "C$" and "Canadian dollars" are to the lawful currency of Canada and all references to
"$," "US$" and "U.S. dollars" are to the lawful currency of the United States. This prospectus includes our trademarks and other trade names identified herein. All other trademarks and trade names
appearing in this prospectus are the property of their respective holders.
Table of Contents
PROSPECTUS SUMMARY
The following summary may not contain all the information that may be important to you or that you should
consider before deciding to purchase any common shares and is qualified in its entirety by the more detailed information appearing elsewhere in this prospectus. You should read the entire prospectus,
especially the risks set forth under the heading "Risk factors" in this prospectus, as well as the financial and other information included or incorporated by reference herein, before making an
investment decision.
Atlantic Power Corporation
Atlantic Power Corporation owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Our
power generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to changes
in commodity prices. Our power
generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 megawatts ("MW") in which our ownership interest is approximately 871 MW. Our current
portfolio consists of interests in 12 operational power generation projects across nine states, one biomass project under construction in Georgia, and a 500 kilovolt 84-mile electric
transmission line located in California. We also own a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development.
The
following map shows the location of our currently-owned projects, including joint venture interests, across the United States:
1
Table of Contents
We sell the capacity and energy from our power generation projects under PPAs with a variety of utilities and other parties. Under terms of the PPAs, which have
expiration dates ranging
from 2012 to 2037, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). We
also sell steam from a number of our projects under steam sales agreements to industrial purchasers. The transmission system rights ("TSRs") we own in our power transmission project entitle us to
payments indirectly from the utilities that make use of the transmission line.
Our power generation projects generally operate pursuant to long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases,
the
fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel
costs to our customers. In cases where there is no pass-through of fuel costs, we use a financial hedging strategy designed to mitigate the market price risk of fuel purchases.
We partner with recognized leaders in the independent power industry to operate and maintain our projects, including Caithness Energy, LLC ("Caithness"), Power
Plant Management
Services ("PPMS"), Delta Power Services and the Western Area Power Administration ("Western"). Under these operation, maintenance and management agreements, the operator is typically responsible for
operations, maintenance and repair services.
Atlantic
Power Corporation is organized under the laws of the Province of British Columbia. Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British
Columbia, Canada V6C 2G8 and our headquarters are located at 200 Clarendon Street, Floor 25, Boston, Massachusetts, USA 02116, telephone number (617) 977-2400. Our website is
www.atlanticpower.com. Information contained on our website is not part of this prospectus.
We completed our initial public offering on the Toronto Stock Exchange ("TSX") in November 2004. At the time of our initial public offering, or IPO, our publicly
traded security was an
income participating security ("IPS") comprised of one common share and C$5.767 principal value of 11% subordinated notes due 2016. On November 24, 2009, our shareholders approved a conversion
from the IPS structure to a traditional common share structure. Each IPS was exchanged for one new common share and each old common share that did not form part of an IPS was exchanged for
approximately 0.44 of a new common share. Our shares trade on the TSX under the symbol "ATP" and began trading on July 23, 2010 on the New York Stock Exchange ("NYSE") under the symbol "AT."
As described in further detail below, on June 20, 2011 we entered into an arrangement agreement, as amended effective July 25, 2011 (the "Arrangement
Agreement"), pursuant
to which we agreed to acquire all of the issued and outstanding limited partnership units of Capital Power Income L.P., a publicly traded Canadian partnership ("CPILP"), in exchange for up to
C$506.5 million in cash and up to 31.5 million of our common shares. CPILP's current portfolio consists of 19 wholly-owned power generation assets located in both Canada and the United
States, a 50.15% interest in a power generation asset in Washington State, and a 14.3% common equity interest in Primary Energy Recycling Holdings LLC. CPILP's assets have a total net
generating capacity of 1,400 MW and more than four million pounds per hour of thermal energy. In addition, pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities
located in North Carolina to an affiliate of Capital Power Corporation, a publicly traded Canadian company, for approximately C$121.4 million. We cannot be certain that our acquisition of CPILP
will be completed. See "Risk factorsRisks related to the Plan of Arrangement."
2
Table of Contents
Our Competitive Strengths
We believe we distinguish ourselves from other independent power producers through the following competitive
strengths:
-
-
Access to
capital.
Our shares are publicly traded on the NYSE and the TSX. We have a history of successfully raising public equity in Canada and
the U.S. and issuing public convertible debentures in Canada. We have also issued securities by way of private placement in Canada. In addition, we have used non-recourse project-level
financing as a source of capital. Project-level financing can be attractive as it typically has a lower cost than equity, is non-recourse to the Company and amortizes over the term of the
project's power purchase agreement. Having significant experience in accessing all of these markets provides flexibility such that we can pursue transactions in the most cost-effective
market at the time capital is needed for growth opportunities.
-
-
Experienced management
team.
Our management team has a tremendous depth of experience in project development, asset management, mergers and acquisitions,
finance and accounting. Our network of industry contacts and our reputation allow us to see proprietary acquisition opportunities on a regular basis.
-
-
Diversified
projects.
Our power generation projects have an aggregate gross electric generation capacity of approximately 1,948 MW, and our net
ownership interest in the electric generation capacity of these projects is approximately 871 MW. These projects are diversified by fuel type, electricity and steam customers, and project operators.
Many are located in the deregulated and more liquid electricity markets of California, Mid-Atlantic, New York, and Texas.
Our
power transmission project, known as the Path 15 project, is an 84-mile, 500-kilovolt transmission line built in order to alleviate north-south transmission congestion in
California. It is a traditional rate-base asset whose revenues are regulated by the Federal Energy Regulatory Commission ("FERC") and is owned and operated by Western, a U.S. Federal power
agency. We also have a 53.5 MW biomass project under construction in Georgia.
-
-
Stability of project cash
flow.
Many of our power generation projects currently in operation have been in operation for over ten years. Cash flows from each
project are generally supported by PPAs with investment-grade utilities and other creditworthy counterparties. We believe that each project's combination of PPAs, fuel supply agreements and/or
commodity hedges help stabilize operating margins as fuel prices fluctuate.
-
-
Strong customer
base.
Our customers are generally large utilities and other parties with investment-grade credit ratings. The largest customers of our
power generation projects are Progress Energy Florida, Inc. ("PEF"), Tampa Electric Company ("TECO"), and Atlantic City Electric ("ACE"), which purchase approximately 37%, 14% and 10%,
respectively, of the net electric generation capacity of our projects. No other electric customer purchases more than 7% of the net electric generation capacity of our power generation projects.
-
-
Leading third-party
operators.
Our power generation projects utilize experienced firms for their operation and maintenance, which are recognized leaders in
independent power. Affiliates of Caithness, PPMS and Babcock and Wilcox Power Generation Group, Inc. operate projects representing approximately 46%, 19% and 12%, respectively, of the net
electric generation capacity of our power generation projects. No other operator is responsible for the operation of projects representing more than 8% of the net electric generation capacity of our
power generation projects.
3
Table of Contents
Our Objectives and Business Strategies
Our objectives include maintaining the stability and sustainability of dividends to shareholders and maximizing the value of our
company. In order to achieve these objectives, we intend to focus on enhancing the operating and financial performance of our current projects and pursuing additional accretive acquisitions primarily
in the electric power industry in the United States and Canada.
Organic growth
We intend to enhance the operation and financial performance of our projects through:
-
-
achievement of improved operating efficiencies, output, reliability and operation and maintenance costs through the
upgrade or enhancement of existing equipment or plant configurations;
-
-
optimization of commercial arrangements such as PPAs, fuel supply and transportation contracts, steam sales agreements,
operations and maintenance agreements and hedge agreements; and
-
-
expansion of existing projects.
Extending PPAs following their expiration
PPAs in our portfolio have expiration dates ranging from 2012 to 2037. In each case, we plan for expirations by evaluating various
options in the market for maximizing long-term project cash flows and passing through to purchasers as effectively as possible the potential changes in fuel costs. New arrangements may
involve responses to utility solicitations for capacity and energy, direct negotiations with the original purchasing utility for PPA extensions, "reverse" request for proposals by the projects to
likely bilateral counterparty arrangements with creditworthy energy trading firms for tolling agreements, full service PPAs or the use of derivatives to lock in value. We do not assume that revenues
or operating margins under existing PPAs will necessarily be sustained after PPA expirations, since most original PPAs included capacity payments related to return of and return on original capital
invested, and counterparties or evolving regional electricity markets may or may not provide similar payments under new or extended PPAs.
Acquisition and investment strategy
We believe that new electricity generation projects will be required in the United States and Canada over the next several years as a
result of growth in electricity demand, transmission constraints and the retirement of older generation projects due to obsolescence or environmental concerns. In addition, Renewable Portfolio
Standards in over 31 states and the recently extended American Recovery and Reinvestment Act's 1603 grant program have greatly facilitated strong PPAs and financial returns for significant renewable
project opportunities. There is also a very active secondary market for existing projects.
We
intend to expand our operations by making accretive acquisitions with a focus on power generation, transmission, distribution and related facilities in the United States and Canada.
We may also invest in other forms of energy-related projects, utility projects and infrastructure projects, as well as make additional investments in development stage projects or companies where the
prospects for creating long-term predictable cash flows are attractive. Since the time of our initial public offering on the TSX in late 2004, we have twice acquired the interest of
another partner in one of our existing projects and will continue to look for such opportunities.
Our
senior management has significant experience in the independent power industry and we believe that their experience, reputation and industry relationships will provide us with
enhanced access to future acquisition opportunities on a proprietary basis.
4
Table of Contents
Acquisition guidelines
We use the following general guidelines when reviewing and evaluating possible acquisitions:
-
-
each acquisition or investment should result in an increase in cash available for distribution to shareholders;
-
-
in the case of an acquisition of power generation facilities, facilities with long-term PPAs with investment
grade electrical utilities or other creditworthy customers will be preferred; and, for facilities without such agreements, market electricity price assumptions used in acquisition evaluations will be
obtained from a recognized independent source; and
-
-
the expected useful life of the facility and associated structures will, with regular maintenance, be long enough to
conform with our objective of providing stable long-term dividends to shareholders.
Acquisition of Capital Power Income L.P.
The Arrangement Agreement and Plan of Arrangement
On June 20, 2011, we entered into an Arrangement Agreement, as amended effective July 25, 2011, with Capital Power
Income L.P. ("CPILP"), a publicly traded Canadian limited partnership, CPILP's general partner and a related entity. The Arrangement Agreement provides that we will acquire, directly or
indirectly, all of the issued and outstanding CPILP units pursuant to a plan of arrangement under the
Canada Business Corporations Act
(the "Plan of
Arrangement"). Under the terms of the Plan of Arrangement, CPILP unitholders will be permitted to exchange each of their CPILP units for, at their election, C$19.40 in cash or 1.3 Atlantic Power
common shares. All cash elections will be subject to proration if total cash elections exceed approximately C$506.5 million and all share elections will be subject to proration if total share
elections exceed approximately 31.5 million Atlantic Power common shares.
CPILP's
primary business is the ownership and operation of power plants in Canada and the United States, which generate electricity and steam, from which it derives its earnings and
cash flows. The power plants generate electricity and steam from a combination of natural gas, waste heat, wood waste, water flow, coal and tire-derived fuel. CPILP's generation projects
sell electricity to utilities and other large commercial customers under long-term PPAs, which seek to minimize exposure to changes in commodity prices. At present, CPILP's portfolio
consists of 19 wholly-owned power generation assets located in both Canada (in the provinces of British Columbia and Ontario) and the United States (in the states of California, Colorado, Illinois,
New Jersey, New York and North Carolina), a 50.15% interest in a power generation asset in Washington State, and a 14.3% common equity interest in Primary Energy Recycling Holdings LLC. CPILP's
assets have a total net generating capacity of 1,400 MW and more than four million pounds per hour of thermal energy. The CPILP units trade on the TSX under the symbol "CPA.UN."
Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power Corporation, a
publicly traded
Canadian company, for approximately C$121.4 million. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power
Corporation and CPILP and certain of its subsidiaries will be terminated (or assigned) in consideration of a payment of C$10.0 million. Atlantic Power or its subsidiaries will assume the
management of CPILP and intends to enter into a transitional services agreement with Capital Power Corporation for a term of up to 12 months following the completion of the Plan of Arrangement,
which will facilitate the integration of CPILP into Atlantic Power. In addition, upon completion of the Plan of Arrangement, Atlantic Power will fully and unconditionally guarantee the cumulative
redeemable preferred shares, Series 1, cumulative rate reset preferred shares, Series 2 and cumulative floating rate preferred shares, Series 3 issued by CPI Preferred Equity
Ltd., a subsidiary of CPILP, on a subordinated basis as to: (i) payment
5
Table of Contents
of dividends, as and when declared; (ii) payment of amounts due on redemption; and (iii) payment of amounts due on liquidation, dissolution or winding up of CPI Preferred Equity Ltd.
The
Arrangement Agreement contains customary representations, warranties and covenants. Among these covenants, CPILP and its affiliates have each agreed not to solicit alternative
transactions, except that CPILP may respond to an alternative transaction proposal that constitutes, or would reasonably be expected to lead to, a superior proposal. In addition, we or CPILP may be
required to pay a C$35.0 million fee if the Arrangement Agreement is terminated in certain circumstances.
We currently expect to complete the Plan of Arrangement in the fourth quarter of 2011, subject to receipt of required shareholder/unitholder, court and regulatory
approvals and the
satisfaction or waiver of the financing and other conditions contained in the Arrangement Agreement. However, we cannot be certain that the Plan of Arrangement will be completed. The shares offered
hereby will remain outstanding whether or not the Plan of Arrangement is completed. See "Risk factorsRisks related to the Plan of Arrangement."
A
copy of the Arrangement Agreement, including the Plan of Arrangement, is included as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange
Commission on June 24, 2011, which is incorporated by reference into this prospectus. The foregoing description of the proposed transaction and the Arrangement Agreement does not purport to be
complete and is qualified in its entirety by reference to such exhibit.
Reasons for the Arrangement Agreement and Plan of Arrangement
Our board of directors believes that the combination of Atlantic Power and CPILP, if completed, will result in significant strategic
benefits to the combined company. These strategic benefits include:
-
-
Atlantic Power will become a leading publicly traded power generation and infrastructure company, with a larger and more
diversified portfolio of contracted power generation assets in the United States and Canada;
-
-
the transaction will combine Atlantic Power's proven management team with CPILP's highly qualified operations,
maintenance, commercial management, accounting, human resources, legal and other personnel;
-
-
Atlantic Power's market capitalization and enterprise value are expected to increase significantly, which is expected to
add liquidity and enhance access to capital to fuel the long term growth of Atlantic Power's asset base throughout North America;
-
-
the combination will expand and diversify Atlantic Power's asset portfolio to include projects in Canada and regions of
the United States where we do not currently have a presence; and
-
-
the transaction will further diversify the fuel types used by Atlantic Power's projects to include additional hydro,
biomass and natural gas.
Our board of directors also believes that the combination of Atlantic Power and CPILP, if completed, will result in significant financial benefits to Atlantic Power's
shareholders.
These financial benefits include:
-
-
upon completion of the Plan of Arrangement, our board of directors anticipates being able to increase dividends by 5%,
from C$1.094 to C$1.15 per share on an annual basis;
-
-
the transaction is expected to strengthen Atlantic Power's dividend sustainability for the foreseeable future with
immediate accretion to cash available for distribution;
-
-
the transaction is expected to result in a significant improvement in Atlantic Power's dividend payout ratio starting in
2012;
6
Table of Contents
-
-
the transaction extends Atlantic Power's average PPA term from 8.8 to 9.1 years and enhances the credit quality of
Atlantic Power's power offtakers; and
-
-
following completion of the Plan of Arrangement, we expect to benefit from cost savings attributable to synergies from
combining the two entities and eliminating the public company reporting costs for CPILP.
Financing transactions
We intend to use the net proceeds from this offering to pay a portion of the cash consideration required under the Plan of Arrangement
and related fees and expenses. We plan to fund the remainder of the cash consideration payable by us under the Plan of Arrangement, including related fees and expenses, with the net proceeds from a
senior unsecured notes offering and/or drawings under a $625 million senior secured credit facility, each as described below.
Under a separate offering memorandum or otherwise, we may offer senior unsecured notes to fund a portion of the cash consideration payable by us under the Plan of
Arrangement, pursuant
to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the "Securities Act"). The completion of this offering of common shares is not subject to the completion of an
offering of senior unsecured notes and the completion of an offering of senior unsecured notes will not be subject to the completion of this offering. No assurance can be given that a notes offering
will be commenced or completed or, if completed, as to the final terms of the notes offering.
We do not intend to register any notes under the Securities Act or the securities laws of any other jurisdiction, and notes may not be offered or sold in the United
States absent
registration or an applicable exemption from registration requirements. Any such notes will be offered only to qualified institutional buyers in the United States pursuant to Rule 144A under
the Securities Act and outside the United States pursuant to Regulation S under the Securities Act. This description and other information regarding a possible notes offering is included in
this prospectus solely for information purposes. Nothing in this prospectus should be construed as an offer to sell, or the solicitation of an offer to buy, any notes.
We
have received the written commitment of a Canadian chartered bank and another financial institution to structure, arrange, underwrite and syndicate a senior secured credit facility
in the amount of $625 million in order to finance the cash consideration payable by us under the Plan of Arrangement. Funding under this facility is subject to certain conditions, including,
without limitation, that there shall not have occurred a material adverse effect with respect to Atlantic Power, CPILP, CPI Services Ltd. and CPI Investments Inc. taken as a whole.
The combined company
As a result of the Plan of Arrangement, if completed, we will emerge as a leading publicly traded, power generation and infrastructure
company with a well diversified portfolio of assets in the United States and Canada. The transaction will increase the net generating capacity of our projects by 143% from 871 MW to approximately
2,116 MW. The combined portfolio of assets will consist of interests in 30 operational power generation projects across 11 states and two provinces, one 53.5 MW biomass project under construction in
Georgia, and an 84-mile, 500 kilovolt electric transmission line located in California. We will remain headquartered in Boston and will add offices in Chicago, Toronto, Ontario and
Richmond, B.C. We expect to add personnel from Capital Power Corporation who have a strong track record of managing, operating and maintaining CPILP's assets, allowing us to have direct control across
the vast majority of the CPILP portfolio by taking advantage of the valuable expertise of this new personnel.
7
Table of Contents
The
following map is a pro forma company structure showing the location of our projects following the Plan of Arrangement, if completed:
The following charts show the fuel type and geographic diversity of Atlantic Power and CPILP and the pro forma fuel type and geographic diversity of the combined
company following the
Plan of Arrangement, if completed:
-
(1)
-
Includes 53.5MW Piedmont project that is currently under construction.
-
(2)
-
Excludes
North Carolina assets.
8
Table of Contents
The following chart shows the Standard & Poor's credit rating of the electricity purchasers, or "off takers," of the combined company following
the Plan
of Arrangement, if completed:
As a result of the Plan of Arrangement, if completed, we believe our larger size and broader-based ownership will improve our access to capital and facilitate the
pursuit of sustained
growth initiatives. Following the Plan of Arrangement, if completed, Atlantic Power will be the second largest publicly traded power generation and infrastructure company on the TSX by enterprise
value.
-
*
-
Source: Bloomberg as of September 14, 2011
Power Industry Overview
Historically, the North American electricity industry was characterized by vertically-integrated monopolies. The trend towards
restructuring the electric power industry and the introduction of competition in electricity generation began with the passage and implementation of the Public Utility Regulatory Policies Act of 1978.
During the late 1980s, several jurisdictions began a process of restructuring by moving away from vertically integrated monopolies toward more competitive market models. Rapid growth in electricity
demand, environmental concerns, increasing electricity rates, technological advances and other concerns prompted government policies to encourage the supply of electricity from independent power
producers.
In the independent power generation sector, electricity is generated from a number of energy sources, including natural gas, coal, water, waste products such as
biomass
(e.g., wood, wood waste, agricultural waste), landfill gas, geothermal, solar and wind. According to the North American Electric Reliability Corporation's Long-Term Reliability
Assessment, published in October 2010, summer peak
9
Table of Contents
demand within the United States in the ten-year period from 2010 through 2019 is projected to increase 1.3%, while winter peak demand in Canada is projected to increase 0.9%.
The non-utility power generation industry in the U.S.
Our 12 power generation projects are non-utility electric generating facilities that operate in the U.S. electric power
generation industry. The electric power industry is one of the largest industries in the United States, generating retail electricity sales of approximately $353 billion in 2009, based on
information published by the Energy Information Administration. A growing portion of the power produced in the United States is generated by non-utility generators. According to the Energy
Information Administration, there were approximately 8,448 non-utility generators representing approximately 475 gigawatts of capacity (equal to 47% of total generating plants and 42% of
nameplate capacity) in 2009, the most recent year for which data is available. Non-utility generators sell the electricity that they generate to electric utilities and other
load-serving entities (such as municipalities and electric cooperatives) by way of bilateral contracts or open power exchanges. The electric utilities and other load-serving
entities, in turn, generally sell this electricity to industrial, commercial and residential customers.
The power generation industry in Canada
In its 2009 outlook of Canada's energy supply, the National Energy Board of Canada ("NEB") forecast Canadian electricity production to
grow at a compound average annual rate of over 1% between 2011 and 2020. The combined effect of demand growth and facility retirements is expected to result in a need for new generation in the coming
years. The British Columbia and Ontario markets remain price regulated, and provincial regulatory bodies have continued to issue requests for proposals or other procurements for the development of new
generation.
A major trend identified by the NEB is a push towards reducing greenhouse gas emissions. This includes energy efficiency initiatives, as well as emphasizing clean
energy alternatives
such as natural gas, hydro, biomass, wind, solar, nuclear and coal with carbon capture and storage technologies. Natural gas will continue to be relied upon to meet increased electricity demand.
Natural gas-fired generation capacity is forecast to increase by 8,146 MW by 2020 in Canada, particularly in Ontario where 3,917 MW of combined-cycle gas and 1,337 MW of combustion
turbine/cogeneration facilities will be relied on to help meet demand following the phase-out of coal-fired generation by 2014. Hydroelectric capacity is also expected to
continue to be the major source of electricity with hydroelectric-based capacity projected to increase from 72,853 MW in 2008 to 80,604 MW by 2020. Extensive development of new hydro projects is
expected in British Columbia, Quebec, Newfoundland and Labrador.
In addition, installed unconventional emerging technology generation continues to remain small however is expected to become a major source of generation capacity in
the future. The
NEB's outlook incorporates increased provincial renewable targets reflecting both increased public interest in clean
sources of electricity and greater confidence on the part of system operators with their ability to integrate wind power into electric systems. Wind power is experiencing exceptionally strong growth
with generation capacity projected to grow from 2,369 MW in 2008 to 16,400 MW by 2020. While wind power generation is expected to contribute the most, other generation technologies such as biomass,
landfill gas, waste heat, solar and tidal are expected to contribute 3,750 MW by 2020.
10
Table of Contents
Our Power Projects
The following table outlines our portfolio of power generating and transmission assets in operation and under construction as of
September 14, 2011, including our interest in each facility. Management believes the portfolio is well diversified in terms of electricity and steam buyers, fuel type, regulatory jurisdictions
and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project Name
|
|
Location
(State)
|
|
Type
|
|
Total
MW
|
|
Economic
Interest
(1)
|
|
Net
MW
(2)
|
|
Primary Electricity
Purchaser
|
|
Power
Contract
Expiry
|
|
Customer
S&P
Credit
Rating
|
Auburndale
|
|
Florida
|
|
Natural Gas
|
|
155
|
|
100.00%
|
|
155
|
|
Progress Energy Florida
|
|
2013
|
|
BBB+
|
Lake
|
|
Florida
|
|
Natural Gas
|
|
121
|
|
100.00%
|
|
121
|
|
Progress Energy Florida
|
|
2013
|
|
BBB+
|
Pasco
|
|
Florida
|
|
Natural Gas
|
|
121
|
|
100.00%
|
|
121
|
|
Tampa Electric Co.
|
|
2018
|
|
BBB+
|
Chambers
|
|
New Jersey
|
|
Coal
|
|
262
|
|
40.00%
|
|
89
|
|
ACE
(3)
|
|
2024
|
|
BBB+
|
|
|
|
|
|
|
|
|
|
|
16
|
|
DuPont
|
|
2024
|
|
A
|
Path 15
|
|
California
|
|
Transmission
|
|
N/A
|
|
100.00%
|
|
N/A
|
|
California utilities via
CAISO
(4)
|
|
N/A
(5)
|
|
BBB+ to A
(6)
|
Orlando
|
|
Florida
|
|
Natural Gas
|
|
129
|
|
50.00%
|
|
46
|
|
Progress Energy Florida
|
|
2023
|
|
BBB+
|
|
|
|
|
|
|
|
|
|
|
19
|
|
Reedy Creek Improvement District
|
|
2013
(7)
|
|
AA-
(8)
|
Selkirk
|
|
New York
|
|
Natural Gas
|
|
345
|
|
17.70%
(9)
|
|
15
|
|
Merchant
|
|
N/A
|
|
N/R
|
|
|
|
|
|
|
|
|
|
|
49
|
|
Consolidated Edison
|
|
2014
|
|
A-
|
Gregory
|
|
Texas
|
|
Natural Gas
|
|
400
|
|
17.10%
|
|
59
|
|
Fortis Energy Marketing and Trading
|
|
2013
|
|
AA
(10)
|
|
|
|
|
|
|
|
|
|
|
9
|
|
Sherwin Alumina
|
|
2020
|
|
NR
|
Badger Creek
|
|
California
|
|
Natural Gas
|
|
46
|
|
50.00%
|
|
23
|
|
Pacific Gas & Electric
|
|
2012
(11)
|
|
BBB+
|
Koma Kulshan
|
|
Washington
|
|
Hydro
|
|
13
|
|
49.80%
|
|
6
|
|
Puget Sound Energy
|
|
2037
|
|
BBB
|
Delta-Person
|
|
New Mexico
|
|
Natural Gas
|
|
132
|
|
40.00%
|
|
53
|
|
Public Service Company of New Mexico
|
|
2020
|
|
BB-
|
Cadillac
|
|
Michigan
|
|
Biomass
|
|
40
|
|
100.00%
|
|
40
|
|
Consumers Energy
|
|
2028
|
|
BBB-
|
Idaho Wind
|
|
Idaho
|
|
Wind
|
|
183
|
|
27.56%
|
|
50
|
|
Idaho Power Co.
|
|
2030
|
|
BBB
|
Piedmont
(12)
|
|
Georgia
|
|
Biomass
|
|
54
|
|
98.00%
|
|
53
|
|
Georgia Power
|
|
2032
|
|
A
|
-
(1)
-
Except
as otherwise noted, economic interest represents the percentage ownership interest in the project held indirectly by Atlantic Power.
-
(2)
-
Represents
our interest in each project's electric generation capacity based on our economic interest.
-
(3)
-
Includes
a separate power sales agreement in which the project and Atlantic City Electric ("ACE") share profits on spot sales of energy and capacity not
purchased by ACE under the base PPA.
-
(4)
-
California
utilities pay transmission access charges to the California Independent System Operator ("CAISO"), who then pays owners of TSRs, such as Path
15, in accordance with its annual revenue requirement approved every three years by the Federal Energy Regulatory Commission ("FERC").
-
(5)
-
Path
15 is a FERC regulated asset with a FERC-approved regulatory life of 30 years: through 2034.
-
(6)
-
Largest
payers of transmission access charges supporting Path 15's annual revenue requirement are Pacific Gas & Electric (BBB+), Southern California
Edison (BBB+) and San Diego Gas & Electric (A). The CAISO imposes minimum credit quality requirements for any participants rated A or better unless collateral is posted per the CAISO imposed
schedule.
-
(7)
-
Upon
the expiry of the Reedy Creek Improvement District PPA, the associated capacity and energy will be sold to Progress Energy Florida under the terms of
the current agreement.
-
(8)
-
Fitch
rating on Reedy Creek Improvement District bonds.
-
(9)
-
Represents
our residual interest in the project after all priority distributions are paid to us and the other partners, which is estimated to occur in
2012.
-
(10)
-
The
guarantor under the Fortis Energy Marketing and Trading PPA is Fortis Bank S.A./N.V., which is rated AA.
-
(11)
-
Entered
into a one-year interim agreement in April 2011.
-
(12)
-
Project
currently under construction and is expected to be completed in late 2012.
11
Table of Contents
CPILP's Power Projects
CPILP's power projects generate electricity and steam from a combination of natural gas, waste heat, wood waste, water flow, coal and
tire-derived fuel. CPILP's Canadian operations consist of:
-
-
four natural gas-fired plants with a combined generating capacity of 163 MW;
-
-
two biomass, wood waste plants with a combined generating capacity of 101 MW; and
-
-
two hydroelectric facilities with a combined generating capacity of 56 MW.
CPILP's
United States operations consist of:
-
-
one simple-cycle natural gas-fired power plant with a generating capacity of 300 MW;
-
-
one combined-cycle natural gas-fired power plant with a generating capacity of 125 MW;
-
-
seven natural gas-fired combined heat and power ("CHP") plants, three of which can also use distillate fuel,
with a combined generating capacity of 440 MW and steam generating capacity of 2,537 mlbs/hr; and
-
-
a hydroelectric plant with a total generating capacity of 60 MW.
Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power Corporation, a
publicly traded
Canadian company, for approximately C$121.4 million.
The following table summarizes each of CPILP's power plants in each of Canada and the United States, and their respective operating characteristics (other than the
Roxboro and Southport
facilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project Name
|
|
Location
|
|
Type
|
|
Net
MW
|
|
Economic
Interest
|
|
Primary Electric Purchaser
|
|
Power
Contract
Expiry
|
|
Customer
S&P Credit
Rating
|
Calstock
|
|
Ontario
|
|
Biomass
|
|
|
35
|
|
|
100%
|
|
Ontario Electricity Financial Corporation
|
|
|
2020
|
|
AA-
|
Kapuskasing
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100%
|
|
Ontario Electricity Financial Corporation
|
|
|
2017
|
|
AA-
|
Nipigon
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100%
|
|
Ontario Electricity Financial Corporation
|
|
|
2012
|
(1)
|
AA-
|
North Bay
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100%
|
|
Ontario Electricity Financial Corporation
|
|
|
2017
|
|
AA-
|
Tunis
|
|
Ontario
|
|
Natural Gas
|
|
|
43
|
|
|
100%
|
|
Ontario Electricity Financial Corporation
|
|
|
2014
|
|
AA-
|
Mamquam
|
|
British Columbia
|
|
Hydro
|
|
|
50
|
|
|
100%
|
|
British Columbia Hydro and Power Authority
|
|
|
2027
|
(2)
|
AAA
|
Moresby Lake
|
|
British Columbia
|
|
Hydro
|
|
|
6
|
|
|
100%
|
|
British Columbia Hydro and Power Authority
|
|
|
2022
|
|
AAA
|
Williams Lake
|
|
British Columbia
|
|
Biomass
|
|
|
66
|
|
|
100%
|
|
British Columbia Hydro and Power Authority
|
|
|
2018
|
(3)
|
AAA
|
Frederickson
|
|
Washington
|
|
Natural Gas
|
|
|
125
|
(4)
|
|
50.15%
|
(5)
|
3 Public Utility Districts
(6)
|
|
|
2022
|
|
A to A+
|
Greeley
|
|
Colorado
|
|
Natural Gas
|
|
|
72
|
|
|
100%
|
|
Public Service Company of Colorado
|
|
|
2013
|
|
A-
|
Manchief
|
|
Colorado
|
|
Natural Gas
|
|
|
300
|
|
|
100%
|
|
Public Service Company of Colorado
|
|
|
2022
|
(7)
|
A-
|
Naval Station
|
|
California
|
|
Natural Gas
|
|
|
47
|
|
|
100%
|
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
Naval Training Centre
|
|
California
|
|
Natural Gas
|
|
|
25
|
|
|
100%
|
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
North Island
|
|
California
|
|
Natural Gas
|
|
|
40
|
|
|
100%
|
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
Oxnard
|
|
California
|
|
Natural Gas
|
|
|
49
|
|
|
100%
|
|
Southern California Edison
|
|
|
2020
|
|
BBB+
|
Curtis Palmer
|
|
New York
|
|
Hydro
|
|
|
60
|
|
|
100%
|
|
Niagara Mohawk Power Corp.
|
|
|
2027
|
|
A-
|
Kenilworth
|
|
New Jersey
|
|
Natural Gas
|
|
|
30
|
|
|
100%
|
|
Schering-Plough Corporation
|
|
|
2012
|
(8)
|
AA
|
Morris
|
|
Illinois
|
|
Natural Gas
|
|
|
177
|
|
|
100%
|
|
Equistar Chemicals, LP
(9)
|
|
|
2023
|
(10)
|
BB-
|
-
(1)
-
CPILP
has the option to extend the PPA for ten years at existing terms.
-
(2)
-
British
Columbia Hydro and Power Authority ("BC Hydro") has an option exercisable in 2021 and every five years thereafter to buy the Mamquam facility or
extend the contract.
-
(3)
-
BC
Hydro has an option to extend the agreement by up to 10 years, on the basis of two five-year term extensions.
-
(4)
-
In
addition, there is 10 MW duct firing.
-
(5)
-
Represents
CPILP's 50.15% ownership interest in Frederickson. Puget Sound Energy, Inc. owns the remaining 49.85% ownership interest.
-
(6)
-
Public
Utility Districts ("PUDs") are: Benton (A+), Franklin (A) and Grays Harbor (A).
-
(7)
-
Public
Service Company of Colorado has an option during the latter part of the extension term to purchase the Manchief facility.
-
(8)
-
Pursuant
to the ESA, Schering-Plough Corporation has the option to purchase the Kenilworth facility. The ESA can be extended automatically for successive
five year periods.
-
(9)
-
100
MW is sold forward through April 2014 into the Pennsylvania, New Jersey, and Maryland market.
-
(10)
-
Equistar
Chemicals, LP has a right to purchase the Morris facility at fair market value at the end of 2013, 2018 and 2023.
12
Table of Contents
The Offering
|
|
|
Issuer
|
|
Atlantic Power Corporation, a British Columbia corporation.
|
Common shares to be offered by us
|
|
shares.
|
Common shares to cover over-allotments
|
|
We have granted the underwriters an option to purchase up to additional common shares to cover over-allotments.
|
Common shares to be outstanding after this offering
|
|
shares
(or shares if the underwriters exercise their over-allotment option in full). If our acquisition of CPILP is completed, there would be
approximately shares outstanding, including the approximately 31.5 million common shares we expect to issue in exchange for CPILP units in connection with the Plan of
Arrangement.
|
Risk factors
|
|
Prospective purchasers should carefully review and evaluate certain risk factors relating to an investment in the common shares and risks related to the Plan of Arrangement. See "Risk
factors."
|
United States and Canadian federal income tax considerations
|
|
You should consult your tax advisor with respect to the U.S. and Canadian federal income tax consequences of owning the common shares in light of your own particular situation and with respect to any
tax consequences arising under the laws of any state, local, foreign or other taxing jurisdiction. See "Certain United States federal income tax considerations" and "Certain Canadian federal income tax considerations."
|
Use of proceeds
|
|
We expect to receive net proceeds from this offering of approximately $ million after deducting the underwriting discount and our
estimated expenses (or approximately $ million if the underwriters exercise their over-allotment option to purchase additional shares in full). We intend to use the net proceeds
from this offering to fund a portion of the cash consideration payable by us under the Plan of Arrangement and, to the extent that any proceeds remain thereafter, or the Plan of Arrangement is not completed, to fund additional growth opportunities
and for general corporate purposes. This offering is not conditioned on the completion of the Plan of Arrangement and there can be no assurance that the Plan of Arrangement will be completed. The shares offered hereby will remain outstanding whether
or not the Plan of Arrangement is completed. See "Use of proceeds."
|
Listing
|
|
Our outstanding common shares are listed on the TSX under the symbol "ATP" and on the NYSE under the symbol "AT."
|
13
Table of Contents
The number of common shares to be outstanding after this offering is based upon 68,984,192 shares outstanding as of September 14,
2011. Unless otherwise stated, the number of common shares to be outstanding after this offering does not include:
-
-
approximately 31.5 million common shares we expect to issue in exchange for CPILP units in connection with the Plan of
Arrangement;
-
-
409,295 unvested notional units granted under the terms of our Long Term Incentive Plan; and
-
-
13,643,645 shares issuable upon conversion, redemption, purchase for cancellation or maturity of our outstanding
convertible debentures.
14
Table of Contents
Summary Historical Consolidated Financial Data of Atlantic Power
The following table presents summary consolidated financial information for Atlantic Power. The annual historical information as of
December 31, 2010 and 2009 and for the years ended December 31, 2010, 2009 and 2008 has been derived from the audited consolidated financial statements appearing in Atlantic Power's
Annual Report on Form 10-K for the year ended December 31, 2010, incorporated by reference into this prospectus. The annual historical information as of December 31,
2008, 2007 and 2006 and for the years ended December 31, 2007 and 2006 has been derived from historical financial statements not incorporated by reference into this prospectus. The historical
information as of, and for the six-month periods ended June 30, 2011 and 2010 has been derived from the unaudited consolidated financial statements appearing in Atlantic Power's Quarterly
Report on Form 10-Q for the quarter ended June 30, 2011, incorporated by reference into this prospectus. Data for all periods have been prepared under U.S. GAAP. You
should read the following selected consolidated financial information together with Atlantic Power's consolidated financial statements and the notes thereto and the discussion under "Management's
Discussion and Analysis of Financial Condition and Results of Operations" included as part of Atlantic Power's Annual Report on Form 10-K for the year ended December 31, 2010
and Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, each of which is incorporated by reference into this prospectus. See "Where you can find more
information" beginning on page 85 of this prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
Ended June 30,
|
|
|
|
Year Ended December 31,
|
|
(in thousands of US dollars, except per share/subordinated note data and as otherwise stated)
|
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
|
2006
(a)
|
|
2011
(a)
|
|
2010
(a)
|
|
Project revenue
|
|
$
|
195,256
|
|
$
|
179,517
|
|
$
|
173,812
|
|
$
|
113,257
|
|
$
|
69,374
|
|
$
|
106,923
|
|
$
|
95,125
|
|
Project income
|
|
|
41,879
|
|
|
48,415
|
|
|
41,006
|
|
|
70,118
|
|
|
57,247
|
|
|
27,900
|
|
|
19,405
|
|
Net (loss) income attributable to Atlantic Power Corporation
|
|
|
(3,752
|
)
|
|
(38,486
|
)
|
|
48,101
|
|
|
(30,596
|
)
|
|
(2,408
|
)
|
|
19,322
|
|
|
(4,618
|
)
|
Basic earnings (loss) per share
|
|
$
|
(0.06
|
)
|
$
|
(0.63
|
)
|
$
|
0.78
|
|
$
|
(0.50
|
)
|
$
|
(0.05
|
)
|
$
|
0.28
|
|
$
|
(0.08
|
)
|
Basic earnings (loss) per share, C$
(b)
|
|
$
|
(0.06
|
)
|
$
|
(0.72
|
)
|
$
|
0.84
|
|
$
|
(0.53
|
)
|
$
|
(0.06
|
)
|
$
|
0.28
|
|
$
|
(0.08
|
)
|
Diluted earnings (loss) per share
(c)
|
|
$
|
(0.06
|
)
|
$
|
(0.63
|
)
|
$
|
0.73
|
|
$
|
(0.50
|
)
|
$
|
(0.05
|
)
|
$
|
0.28
|
|
$
|
(0.08
|
)
|
Diluted earnings (loss) per share, C$
(b)
(c)
|
|
$
|
(0.06
|
)
|
$
|
(0.72
|
)
|
$
|
0.78
|
|
$
|
(0.53
|
)
|
$
|
(0.06
|
)
|
$
|
0.28
|
|
$
|
(0.08
|
)
|
Distribution per subordinated note
(d)
|
|
$
|
|
|
$
|
0.51
|
|
$
|
0.60
|
|
$
|
0.59
|
|
$
|
0.57
|
|
$
|
|
|
$
|
|
|
Dividend declared per common share
|
|
$
|
1.06
|
|
$
|
0.46
|
|
$
|
0.40
|
|
$
|
0.40
|
|
$
|
0.37
|
|
$
|
0.57
|
|
$
|
0.52
|
|
Total assets
|
|
$
|
1,013,012
|
|
$
|
869,576
|
|
$
|
907,995
|
|
$
|
880,751
|
|
$
|
965,121
|
|
$
|
1,008,980
|
|
$
|
862,525
|
|
Total long-term liabilities
|
|
$
|
518,273
|
|
$
|
402,212
|
|
$
|
654,499
|
|
$
|
715,923
|
|
$
|
613,423
|
|
$
|
523,351
|
|
$
|
407,413
|
|
-
(a)
-
Unaudited.
-
(b)
-
The
C$ amounts were converted using the average exchange rates for the applicable reporting periods.
-
(c)
-
Diluted
earnings (loss) per share is computed including dilutive potential shares, which include those issuable upon conversion of convertible debentures
and under our long term incentive plan. Because we reported a loss during the years ended December 31, 2010, 2009, 2007 and 2006, and for the six-month period ended June 30, 2010, the
effect of including potentially dilutive shares in the calculation during those periods is anti-dilutive. Please see the notes to our historical consolidated financial statements
incorporated by reference into this prospectus for information relating to the number of shares used in calculating basic and diluted earnings per share for the periods presented.
-
(d)
-
At
the time of our initial public offering, our publicly traded security was an income participating security, or an "IPS," each of which was comprised of
one common share and C$5.767 principal amount of 11% subordinated notes due 2016. On November 27, 2009,we converted from the IPS structure to a traditional common share structure. In connection
with the conversion, each IPS was exchanged for one new common share.
15
Table of Contents
Summary Historical Consolidated Financial Information of CPILP
The following table presents summary consolidated financial information for CPILP. The selected historical financial data as of, and
for the years ended, December 31, 2010, 2009 and 2008 has been derived from CPILP's audited consolidated financial statements for those periods prepared under Canadian generally accepted
accounting principles and appearing elsewhere in this prospectus. Data as of, and for the years ended, December 31, 2010 and 2009 has been reconciled to U.S. generally accepted accounting
principles as noted below. The selected historical financial data as of, and for the years ended, December 31, 2007 and 2006 has been derived from the audited consolidated financial statements
of CPILP prepared under Canadian generally accepted accounting principles not appearing in this prospectus. The selected historical financial data as of, and for the six-month periods ended
June 30, 2011 and 2010 has been derived from CPILP's unaudited consolidated financial statements for those periods prepared using International Financial Reporting Standards and appearing
elsewhere in this prospectus.
Data for all periods presented below is reported in Canadian dollars. You should read the following selected consolidated financial data together with CPILP's
consolidated financial
statements and the notes thereto included elsewhere in this prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Six Months Ended
June 30,
|
|
(in thousands of Canadian dollars,
except per unit data)
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
|
2006
|
|
2011
(a)(b)
|
|
2010
(a)
(b)
|
|
Revenue
|
|
$
|
532,377
|
|
$
|
586,491
|
|
$
|
499,267
|
|
$
|
549,872
|
|
$
|
326,900
|
|
$
|
261,524
|
|
$
|
241,453
|
|
Depreciation, amortization and accretion
|
|
$
|
98,227
|
|
$
|
93,249
|
|
$
|
88,313
|
|
$
|
85,553
|
|
$
|
65,200
|
|
$
|
45,461
|
|
$
|
47,826
|
|
Financial charges and other, net
|
|
$
|
40,179
|
|
$
|
46,462
|
|
$
|
94,836
|
|
$
|
8,574
|
|
$
|
42,200
|
|
$
|
21,457
|
|
$
|
21,384
|
|
Net income before tax and preferred share dividends
|
|
$
|
35,224
|
|
$
|
56,812
|
|
$
|
(91,918
|
)
|
$
|
108,953
|
|
$
|
67,400
|
|
$
|
18,741
|
|
$
|
4,705
|
|
Net income (loss) attributable to equity holders of CPILP
|
|
$
|
30,500
|
|
$
|
57,553
|
|
$
|
(67,893
|
)
|
$
|
30,816
|
|
$
|
62,121
|
|
$
|
10,529
|
|
$
|
8,410
|
|
Basic and diluted net income (loss) per unit, C$
|
|
$
|
0.55
|
|
$
|
1.07
|
|
$
|
(1.26
|
)
|
$
|
0.59
|
|
$
|
1.28
|
|
$
|
0.19
|
|
$
|
0.15
|
|
Distributions declared per unit, C$
|
|
$
|
1.76
|
|
$
|
1.95
|
|
$
|
2.52
|
|
$
|
2.52
|
|
$
|
2.52
|
|
$
|
0.88
|
|
$
|
0.88
|
|
Total assets
|
|
$
|
1,583,910
|
|
$
|
1,668,057
|
|
$
|
1,809,225
|
|
$
|
1,852,573
|
|
$
|
1,883,400
|
|
$
|
1,471,772
|
|
$
|
1,667,775
|
|
Total long-term liabilities
|
|
$
|
874,190
|
|
$
|
853,314
|
|
$
|
935,248
|
|
$
|
730,940
|
|
$
|
757,800
|
|
$
|
821,382
|
|
$
|
900,995
|
|
Operating margin
(c)
|
|
$
|
187,567
|
|
$
|
211,680
|
|
$
|
111,446
|
|
$
|
216,188
|
|
$
|
185,900
|
|
$
|
99,675
|
|
$
|
77,753
|
|
-
(a)
-
Unaudited.
-
(b)
-
Results
have been prepared using International Financial Reporting Standards.
-
(c)
-
Operating
margin is a non-GAAP financial measure. CPILP uses operating margin as a performance measure. Operating margin is not a defined financial
measures according to Canadian generally accepted accounting principles or International Financial Reporting Standards and does not have a standardized meaning prescribed by Canadian generally
accepted accounting principles or International Financial Reporting Standards. Therefore, operating margin may not be comparable to similar measures presented by other enterprises.
Under U.S. GAAP, the following differences are noted for the years indicated below:
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
(in thousands of Canadian dollars,
except per unit data)
|
|
2010
|
|
2009
|
|
Revenue
|
|
$
|
532,377
|
|
$
|
586,491
|
|
Depreciation, amortization and accretion
|
|
$
|
98,277
|
|
$
|
93,249
|
|
Financial charges and other, net
|
|
$
|
40,179
|
|
$
|
46,462
|
|
Net income before tax and preferred share dividends
|
|
$
|
39,179
|
|
$
|
54,753
|
|
Net income (loss) attributable to equity holders of CPILP
|
|
$
|
34,455
|
|
$
|
55,529
|
|
Basic and diluted net income (loss) per unit, C$
|
|
$
|
0.63
|
|
$
|
1.03
|
|
Distributions declared per unit, C$
|
|
$
|
1.76
|
|
$
|
1.95
|
|
Total assets
|
|
$
|
1,588,352
|
|
$
|
1,673,059
|
|
Total long-term liabilities
|
|
$
|
878,632
|
|
$
|
858,317
|
|
Operating margin
|
|
$
|
191,530
|
|
$
|
209,621
|
|
16
Table of Contents
Summary Unaudited Pro Forma Condensed Combined Consolidated Financial Information
The following table sets forth selected information about the pro forma financial condition and results of operations, including per
share data, of Atlantic Power after giving effect to the completion of the Plan of Arrangement with CPILP. The table sets forth selected unaudited pro forma condensed combined consolidated statements
of operations for the six months ended June 30, 2011 and the year ended December 31, 2010, as if the Plan of Arrangement had been completed on January 1, 2010, and the selected
unaudited pro forma condensed combined consolidated balance sheet data as of June 30, 2011, as if the Plan of Arrangement had been completed on that date. The information presented below was
derived from Atlantic Power's and CPILP's consolidated historical financial statements, and should be read in conjunction with these financial statements and the notes thereto, included elsewhere or
incorporated by reference into this prospectus and the other unaudited pro forma financial data, including related notes, included elsewhere in this prospectus. CPILP's historical consolidated
financial statements have been prepared in accordance with Canadian GAAP (or, in the case of the six months ended June 30, 2011, International Financial Reporting Standards) and include a
discussion of the significant differences between Canadian GAAP and U.S. GAAP in Note 27 to the CPILP audited consolidated financial statements for the year ended December 31,
2010. For purposes of the unaudited pro forma condensed combined consolidated financial data, CPILP's balance sheet financial data has been translated from Canadian dollars into U.S. dollars using a
C$/$ exchange rate of C$0.9643 to $1.00 and is presented in accordance with U.S. GAAP. CPILP's statement of operations financial data has been translated from Canadian dollars
into U.S. dollars using an average C$/$ exchange rate of C$0.9766 to $1.00 and C$1.0295 to $1.00 for the six months ended June 30, 2011 and the year ended December 31, 2010,
respectively, and is presented in accordance with U.S. GAAP.
The
unaudited pro forma financial data is based on estimates and assumptions that are preliminary and does not purport to represent the financial position or results of operations that
would actually have occurred had the Plan of Arrangement been completed as of the dates or at the beginning of the periods presented or what the combined company's results will be for any future date
or any future period. See the sections entitled "Cautionary statements regarding forward-looking statements" and "Risk factors."
Unaudited Pro Forma Condensed Combined Consolidated Financial Information
|
|
|
|
|
|
|
|
|
(in thousands of U.S. dollars, except per share data
and number of shares outstanding)
|
|
Six Months
Ended
June 30, 2011
|
|
Year Ended
December 31, 2010
|
|
Combined consolidated statement of operations information
|
|
|
|
|
|
|
|
Project revenues
|
|
$
|
346,015
|
|
$
|
669,985
|
|
Project income
|
|
|
60,937
|
|
|
91,687
|
|
Net income
|
|
|
19,817
|
|
|
11,135
|
|
Net income attributable to noncontrolling interest
|
|
|
6,952
|
|
|
13,597
|
|
Net income (loss) attributable to Atlantic Power Corporation/CPILP
|
|
|
12,865
|
|
|
(2,462)
|
(1)
|
Earnings (loss) per share
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.11
|
|
$
|
(0.02
|
)
|
|
Diluted
|
|
$
|
0.11
|
|
$
|
(0.02
|
)
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
112,757
|
|
|
106,347
|
|
|
Diluted
|
|
|
113,184
|
|
|
106,347
|
|
17
Table of Contents
|
|
|
|
|
(in thousands of U.S. dollars)
|
|
As of
June 30, 2011
|
|
Balance sheet information
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
145,409
|
|
Total assets
|
|
|
3,456,478
|
|
Long-term debt and convertible debentures
|
|
|
1,602,699
|
|
Total liabilities
|
|
|
2,096,958
|
|
|
|
|
|
Total Atlantic Power Corporation shareholders' equity
|
|
|
1,128,671
|
|
Noncontrolling interest
|
|
|
230,849
|
|
|
|
|
|
Total equity
|
|
$
|
1,359,520
|
|
-
(1)
-
Net
income (loss) attributable to Atlantic Power/CPILP on a pro forma basis reflects:
-
a.
-
a
significant increase in amortization expense as a result of the estimated increase in fair value associated with CPILP PPAs (see Note 5(e) in the
notes to the unaudited pro forma condensed combined consolidated financial statements included elsewhere in this prospectus);
-
b.
-
timing
differences in Atlantic Power's deferred tax expense; and
-
c.
-
timing
differences in CPILP's deferred tax benefit.
18
Table of Contents
RISK FACTORS
Investing in our common shares involves a high degree of risk. In addition to other information contained in
this prospectus you should carefully consider the risks described below in evaluating our company and our business before making a decision to invest in our common shares. These risks are not the only
ones faced by us. Additional risks not presently known or that we currently deem immaterial could also materially and adversely affect our financial condition, results of operations, business and
prospects. The trading price of our common shares could decline due to any of these risks, and you may lose all or part of your investment. This prospectus also contains forward-looking statements
that involve risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including the risks faced by us
described below and elsewhere in this prospectus. Please refer to the section entitled "Cautionary statements regarding forward-looking statements" in this prospectus.
Risks Related to Our Business and Our Projects
Our revenue may be reduced upon the expiration or termination of our power purchase agreements.
Power generated by our projects, in most cases, is sold under PPAs that expire at various times. For example, the PPA at our Badger
Creek project expires in 2012 and represents 23 MWs of our net generating capacity. PPAs at our Auburndale, Lake and Gregory projects expire by the end of 2013 and represent 335 MWs of our net
generating capacity. The table on page 11 contains details about our projects' PPAs. In addition, these PPAs may be subject to termination in certain circumstances, including default by the
project. When a PPA expires or is terminated, it is possible that the price received by the project for power under subsequent arrangements may be reduced significantly. It is possible that subsequent
PPAs may not be available at prices that permit the operation of the project on a profitable basis. If this occurs, the affected project may temporarily or permanently cease operations.
Our projects depend on their electricity, thermal energy and transmission services customers.
Each of our projects rely 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 largest customers of our power generation projects, including projects recorded under the equity method of accounting, are Progress Energy
Florida, Inc. ("PEF"), Tampa Electric Company ("TECO"), and Atlantic City Electric ("ACE"), which purchase approximately 37%, 14% and 10%, respectively, of the net electric generation capacity
of our projects. The amount of cash available to pay dividends to shareholders is highly dependent upon customers under such agreements fulfilling their contractual obligations. There is no assurance
that these customers will perform their obligations or make required payments.
Certain of our projects are exposed to fluctuations in the price of electricity.
Those of our projects with no PPA or PPAs based on spot market pricing will be exposed to fluctuations in the wholesale price of
electricity. In addition, should any of the
long-term PPAs expire or terminate, the relevant project will be required to either negotiate a new PPA or sell into the electricity wholesale market, in which case the prices for
electricity will depend on market conditions at the time.
Our most significant exposure to market power prices is at the Selkirk and Chambers projects. At Chambers, the project has the right to sell a portion of the plant's
output to our
utility customer at spot market prices if it is economical to do so and the Chambers project shares in the profits from these sales. In addition, during periods of low spot electricity prices the
customer takes less generation, which negatively affects the project's profitability. At Selkirk, approximately 23% of the capacity of the
19
Table of Contents
facility is not contracted and is sold at market prices or not sold at all if market prices do not support the profitable operation of that portion of the facility.
Our projects may not operate as planned.
The revenue generated by our power generation projects is dependent, in whole or in part, on their availability, performance and the
amount of electric energy and steam generated by them. The ability of our projects to meet availability requirements and generate the required amount of power to be sold to customers under the PPAs
are primary determinants of the amount of cash that will be distributed from the projects to us, and that will in turn be available for dividends paid to our shareholders. There is a risk of equipment
failure due to wear and tear, latent defect, design error or operator error, or force majeure events among other things, which could adversely affect revenues and cash flow. To the extent that our
projects' equipment requires more frequent and/or longer than forecasted down times for maintenance and repair, or suffers disruptions of plant availability and power generation for other reasons, the
amount of cash available for dividends may be adversely affected.
In
general, our power generation projects transmit electric power to the transmission grid for purchase under the PPAs through a single step up transformer. As a result, the transformer
represents a single point of vulnerability and may exhibit no abnormal behavior in advance of a catastrophic failure that could cause a temporary shutdown of the facility until a replacement
transformer can be found or manufactured.
If
the reason for a shutdown is outside of the control of the operator, a power generation project may be able to make a force majeure claim for temporary relief of its obligations
under the project contracts such as the PPA, fuel supply, steam sales agreement, or otherwise mitigate impacts through business interruption insurance policies maintenance and debt service reserves.
If successful, such insurance claims may prevent a default or reduce monetary losses under such contracts. However, a
force majeure claim may be challenged by the contract counterparty and, to the extent the challenge is successful, the outage may still have a materially adverse effect on the project.
We provide letters of credit under our senior credit facility for contractual credit support at some of our projects. If the projects fail to perform under the
related project-level
agreements, the letters of credit could be drawn and the Company would be required to reimburse our senior lenders for the amounts drawn.
Our projects depend on suppliers under fuel supply agreements and increases in fuel costs may adversely affect the profitability of the projects.
Revenues earned by our projects may be affected by the availability, or lack of availability, of a stable supply of fuel at reasonable
or predictable prices. To the extent possible, the projects attempt to match fuel cost setting mechanisms in supply agreements to energy payment formulas in the PPA. To the extent that fuel costs are
not matched well to PPA energy payments, increases in fuel costs may adversely affect the profitability of the projects.
The
amount of energy generated at the projects is highly dependent on suppliers under certain fuel supply agreements fulfilling their contractual obligations. The loss of significant
fuel supply agreements or an inability or failure by any supplier to meet its contractual commitments may adversely affect our results.
Upon the expiration or termination of existing fuel supply agreements, we or our project operators will have to renegotiate these agreements or may need to source
fuel from other
suppliers. Our project operators may not 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 difficult to accurately predict the future prices of fuel.
20
Table of Contents
For example, a portion of the required natural gas at our Auburndale project and all of the natural gas required at our Lake project is purchased at market prices, but the projects' PPAs that expire
in 2013 do not effectively pass through changes in natural gas prices.
The
amount of energy generated at the projects is dependent upon the availability of natural gas, coal, oil or biomass. The long-term availability of such resources could
change in the future.
Generation from windpower projects may be less than anticipated.
We now own an interest in a windpower project, which is exposed to the risk of its wind resource having unfavorable characteristics,
which could result in unfavorable financial impacts to its generation and revenues.
Our operations are subject to the provisions of various energy laws and regulations.
Generally, in the United States, our projects are subject to regulation by the Federal Energy Regulatory Commission, or "FERC,"
regarding the terms and conditions of wholesale service and rates, as well as by state agencies regarding PPAs entered into by qualifying facility projects and the siting of the generation facilities.
The majority of our generation is sold by qualifying facility projects under PPAs that required approval by state authorities.
In
August 2005, the Energy Policy Act of 2005 was enacted, which removed certain regulatory constraints on investment in utility power producers. The Energy Policy Act of 2005 also
limited the requirement that electric utilities buy electricity from qualifying facilities to certain markets that lack competitive characteristics, potentially making it more difficult for our
current and future projects to negotiate favorable PPAs with these utilities. Finally, the Energy Policy Act of 2005 amended and expanded the reach of the FERC's merger approval authority.
If any project that is a qualifying facility were to lose its status as a qualifying facility, then such project may no longer be entitled to exemption from
provisions of the Public
Utility Holding Company Act of 2005 or from provisions of the Federal Power Act of 1935 and state law and regulations. Such project may be able to obtain exempt wholesale generator status to maintain
its exemption from the provisions of the Public Utility Holding Company Act of 2005; however, our projects may not be able to obtain such exemptions. Loss of qualifying facility status could trigger
defaults under covenants to maintain qualifying facility status in the PPAs and project-level debt agreements and if not cured within allowed cure periods, could result in termination of agreements,
penalties or acceleration of indebtedness under such agreements, plus interest.
Our
projects require licenses, permits and approvals which can be in addition to any required environmental permits. No assurance can be provided that we will be able to obtain, comply
with and renew, as required, all necessary licenses, permits and approvals for these facilities. If we cannot comply with and renew as required all applicable licenses, permits and approvals, our
business, results of operations and financial condition could be adversely affected.
The
Energy Policy Act of 2005 provides incentives for various forms of electric generation technologies, which may subsidize our competitors. In addition, pursuant to the Energy Policy
Act of 2005, the FERC selected an electric reliability organization to impose mandatory reliability rules and standards. Among other things, the FERC's rules implementing these provisions allow such
reliability organizations to impose sanctions on generators that violate their new reliability rules.
The
introductions of new laws, or other future regulatory developments, may have a material adverse impact on our business, operations or financial condition.
21
Table of Contents
Future FERC rate determinations could negatively impact Path 15's cash flows.
The stability of Path 15's cash flows will continue to be subject to the risk of the FERC's adjusting the expected formulation of
revenues upon its rate review every three years. Such a rate review has commenced in February 2011. The cost-of-service methodology currently applied by the FERC is well
established and transparent; however, certain inputs in the FERC's determination of rates are subject to its discretion, including its response to protests from intervenors in such rate cases, which
include return on equity and the recovery of certain extraordinary expenses. Unfavorable decisions on these matters could adversely affect Path 15 and our cash flow, financial position and results of
operations, and could adversely affect our cash available for dividends.
Noncompliance with federal reliability standards may subject us and our projects to penalties.
Our operations are subject to the regulations of the North American Electric Reliability Corporation ("NERC"), a
self-regulatory non-governmental organization which has statutory responsibility, granted by the FERC, to regulate bulk power system users, owners and operators. NERC groups
the users, owners, and operators of the bulk power system into 15 categories, known as functional entitiese.g., Generator Owner, Generator Operator, Purchasing-Selling Entity,
etc.according to the tasks they perform. The NERC Compliance Registry lists the users, owners and operators of the bulk power system and the functional entity type(s) under which they are
registered. All registered entities are responsible for complying with the applicable mandatory reliability standards and the FERC, or NERC or a regional reliability organization, with FERC's
approval, may assess financial penalties or other enforcement actions against any responsible entity found to be in noncompliance. Violations may be discovered through self-certification,
compliance audits, spot checking, self-reporting, compliance investigations by NERC (or a regional
reliability organization) and the FERC, periodic data submittals, exception reporting, and complaints. The penalty that might be imposed for violating the requirements of the standards is a function
of the Violation Risk Factor, a pre-violation assessment of the potential risk to the reliability of the bulk power system that a violation of a particular reliability standard requirement presents,
and the Violation Security Level, a post-violation measurement of the degree to which a reliability standard requirement was violated. Penalties for the most severe violations can reach as high as
$1 million per violation, per day, and our projects could be exposed to these penalties and other enforcement actions if violations occur.
Our projects are subject to significant environmental and other regulations.
Our projects are subject to numerous and significant 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; ash disposal; the storage, handling,
use, disposal, transportation and distribution of dangerous goods and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the
environment; the presence and remediation of hazardous materials in soil and groundwater, both on and off site; the protection of natural resources; land use and zoning matters; and workers' health
and safety matters. As such, the operation of our projects carries an inherent risk of environmental, health and safety liabilities (including potential civil actions, compliance or remediation
orders, fines and other penalties), and may result in the projects being involved from time to time in administrative and judicial proceedings relating to such matters.
The Clean Air Act and related regulations and programs of the Environmental Protection Agency extensively regulate the air emissions of sulfur dioxide, nitrogen
oxides, mercury and
other compounds by power plants. Environmental laws and regulations have generally become more stringent over time, and this trend may continue. In particular, the Environmental Protection Agency
promulgated regulations under the federal Clean Air Interstate Rule ("CAIR") requiring additional reductions in nitrogen oxides, or "NOX," and sulphur dioxide, or "SO
2
," emissions,
beginning in 2009
22
Table of Contents
and 2010 respectively, and also promulgated regulations requiring reductions in mercury emissions from coal-fired electric generating units, beginning in 2010 with more substantial
reductions expected 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.
While CAIR was set aside by a court decision in 2008, that decision allowed the CAIR requirements to remain in place pending further rulemaking by the Environmental
Protection Agency.
On August 8, 2011, the Environmental Protection Agency promulgated the final Cross-State Air Pollution Rule (which will replace CAIR as of October 7, 2011) which requires
27 states and the District of Columbia to curb emissions of sulfur dioxide and nitrogen oxides from power plants through more aggressive state-by-state emissions limits
for nitrogen oxides and sulfur dioxide. The
first phase of compliance would begin on January 1, 2012 and the second (and more restrictive) phase would begin on January 1, 2014. Compliance with the new rule may have a material
adverse impact on our business, operations or financial condition.
The Environmental Protection Agency proposed new mercury emissions standards for power plants on March 16, 2011 and is expected to have new standards in place by
November 2011.
Meeting these new standards at our coal-fired facility may have a material adverse impact on our business, operations or financial condition.
The Resource Conservation and Recovery Act has historically exempted fossil fuel combustion wastes from hazardous waste regulation. However, in June 2010 the
Environmental Protection
Agency proposed two alternative sets of regulations governing coal ash. One set of proposed regulations would designate coal ash as "special waste" and bring ash impoundments at coal-fired
power plants under federal regulations governing hazardous solid waste under Subtitle C of the Resource Conservation and Recovery Act. Another set of proposed regulations would regulate coal ash as a
non-hazardous solid waste. In March 2011, the Environmental Protection Agency announced that, due to the volume of public comments received on the two alternative sets of proposed coal ash
regulations, it would not issue final regulations governing coal ash in 2011. If the Environmental Protection Agency ultimately decides to regulate coal ash as a hazardous waste, our
coal-fired facility may be subject to increased compliance obligations and costs that may have a material adverse impact on our business, operations or financial condition.
Significant expenditures may be required for either capital improvements or the purchase of allowances under any or all of these programs to keep the projects
compliant with
environmental laws and regulations. The projects' PPAs do not allow for the pass through of emissions allowance or emission reduction capital expenditure costs, with the exception of Pasco. If it is
not economical to make those expenditures it may be necessary to retire or mothball facilities, or restrict or modify our operations to comply with more stringent standards.
Our
projects have obtained environmental permits and other approvals that are required for their operations. Compliance with applicable environmental laws, regulations, permits and
approvals and material future changes to them could materially impact our businesses. Although we believe the operations of the projects are currently in material compliance with applicable
environmental laws, licenses, permits and other authorizations required for the operation of the projects and although there are environmental monitoring and reporting systems in place with respect to
all the projects, there is no guarantee that more stringent laws will not be imposed, that there will not be more stringent enforcement of applicable laws or that such systems may not fail, which may
result in material expenditures. Failure by the projects to comply with any environmental, health or safety requirements, or increases in the cost of such compliance, including as a result of
unanticipated liabilities or expenditures for investigation, assessment, remediation or prevention, could result in additional expense, capital expenditures, restrictions and delays in the projects'
activities, the extent of which cannot be predicted.
23
Table of Contents
Our projects are subject to regulation of CO
2
and other greenhouse gases.
Ongoing public concerns about emissions of CO
2
and other greenhouse gases have resulted in the enactment of, and proposals
for, laws and regulations at the federal, state and regional levels, some of which do or could apply to some of our project operations. For example, the multi-state CO
2
cap-and-trade program known as the Regional Greenhouse Gas Initiative applies to our fossil fuel facilities in the Northeast region. The Regional Greenhouse Gas Initiative
program went into effect on January 1, 2009. CO
2
allowances are auctioned quarterly, with a clearing price for the June 2011 auction of $1.89/ton, and can be traded within a
secondary market at a similar price in 2011. The State of Florida has conducted stakeholder meetings and workshops as part of the process of developing greenhouse gas emissions regulations, the most
recent of which was in 2009. In October 2010, the Florida DEP issued its "Comparative Study of Selected Offset Protocols for Greenhouse Gas Reduction and Reporting Programs." These regulatory efforts
could result in stringent limits on CO
2
emissions in that state.
California, New Mexico, Washington and other states and Canadian Provinces are part of the Western Climate Initiative, which is developing a regional
cap-and-trade program to reduce greenhouse gas emissions in the region to 15% below 2005 levels by 2020.
In
2006, the State of California passed legislation initiating two programs to control/reduce the creation of greenhouse gases. 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 specific provisions. Development towards the implementation of these programs continues.
Under AB 32 (the California Global Warming Solutions Act of 2006) the California Air Resources Board ("CARB") is required to adopt a greenhouse gas 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 verification of greenhouse gas emissions and to reduce state-wide
emissions of greenhouse gases to 1990 levels by 2020. This will most likely require that electric generating facilities reduce their emissions of greenhouse gases or pay for the right to emit by the
implementation date of January 1, 2012. The program has yet to be finalized 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 auction-based allocation program.
The legality of AB 32 has been challenged by several parties. On January 21, 2011, the San Francisco Superior Court issued a proposed decision that could
significantly delay the
implementation of AB 32. In
Association of Irritated Residents, et al. v. California Air Resources Board
, Case No.
CPF-09-509562, the Court held that the CARB failed to comply with the California Environmental Quality Act. The Court found the CARB to have neglected to conduct a sufficient
environmental impact review prior to adopting the AB 32 Scoping Plan. Specifically, CARB failed to adequately analyze all potential alternatives and prematurely adopted the Scoping Plan prior to fully
responding to public comment. CARB has appealed that decision but, in the interim, has revised its alternatives analysis on which public comment was accepted until July 28, 2011.
SB 1368 required the California Energy Commission, in consultation with the California Public Utilities Commission (the "CPUC") and the CARB to establish greenhouse
gas emission
performance standards and implement regulations for power purchase agreements that exceed five years entered into prospectively by publicly-owned electric utilities. The regulations have been
finalized and establish a performance standard for greenhouse gas emissions from power plants not exceeding the rate of greenhouse gas emitted per megawatt-hour associated with
combined-cycle, gas turbine baseload generation, such as our Badger Creek project.
In
addition to the regional initiatives, legislation for the reduction of greenhouse gases has been introduced at the federal level and if passed, may eventually override the regional
efforts with a
24
Table of Contents
national
cap and trade program. Federal bills to create both a cap-and-trade allowance system and a renewable/efficiency portfolio standard have been introduced in both the
House and Senate. Separately, the Environmental Protection Agency has taken several recent actions proposing possible regulation of greenhouse gas emissions.
The Environmental Protection Agency's actions include its finding of "endangerment" to public health and welfare from greenhouse gases, its issuance in September 2009
of the Final
Mandatory Reporting of Greenhouse Gases Rule which requires large sources, including power plants, to monitor and report greenhouse gas emissions to the Environmental Protection Agency annually
starting in 2011, and its publication in May 2010 of its final Prevention of Significant Deterioration and Title V Greenhouse
Gas Tailoring Rule, effective January 2, 2011, which requires large industrial facilities, including power plants, to obtain permits to emit, and to use best available control technology to
curb emissions of, greenhouse gases.
The
implementation of existing CO
2
and other greenhouse gas legislation or regulation, the introduction of new regulation, or other future regulatory developments may
subject the Company to increased compliance obligations and costs that could have a material adverse impact on our business, operations or financial condition.
All of our generating facilities met the March 31, 2011 requirement to submit 40 CFR Part 98 Mandatory Greenhouse Gas reporting for the emission of eligible
site generated
greenhouse gases in 2010.
Increasing competition could adversely affect our performance and the performance of our projects.
The power generation industry is characterized by intense competition, and our projects encounter competition from utilities,
industrial companies and other independent power producers, in particular with respect to uncontracted output. In recent years, there has been increasing competition among generators for power sales
agreements, and this has contributed to a reduction in electricity prices in certain markets where supply has surpassed demand plus appropriate reserve margins. In addition, many states have
implemented or are considering regulatory initiatives designed to increase competition in the U.S. power industry. Increasing competition among participants in the power generation industry may
adversely affect our performance and the performance of our projects.
We have limited control over management decisions at certain projects.
In a number of cases, our projects are not wholly-owned by us or we have contracted for their operations and maintenance, and in some
cases we have limited control over the operation of the projects. Although we generally prefer to acquire projects where we have control, we may make acquisitions in non-control situations
to the extent that we consider it advantageous to do so and consistent with regulatory requirements and restrictions, including the Investment Company Act of 1940. Third-party operators (such as
Caithness, PPMS and Western) operate many of the projects. As such, we must rely on the technical and management expertise of these third-party operators, although typically we are represented on a
management or operating committee if we do not own 100% of a project. To the extent that such third-party operators do not fulfill their obligations to manage the operations of the projects or are not
effective in doing so, the amount of cash available to pay dividends may be adversely affected.
We may face significant competition for acquisitions and may not successfully integrate acquisitions.
Our business plan includes growth through identifying suitable acquisition opportunities, pursuing such opportunities, consummating
acquisitions and effectively integrating them with our business. We may be unable to identify attractive acquisition candidates in the power industry in the future, and we may not be able to make
acquisitions on an accretive basis or be sure that acquisitions
25
Table of Contents
will
be successfully integrated into our existing operations, any of which could negatively impact our ability to continue paying dividends in the future at current rates.
Although
electricity demand is expected to grow, creating the need for more generation, and the U.S. power industry is continuing to undergo consolidation and may offer attractive
acquisition opportunities, we are likely to confront significant competition for those opportunities and, to the extent that any opportunities are identified, we may be unable to effect acquisitions
or investments.
Any
acquisition or investment may involve potential risks, including an increase in indebtedness, the inability to successfully integrate operations, the potential disruption of our
ongoing business, the diversion of management's attention from other business concerns and the possibility that we pay more than the acquired company or interest is worth. There may also be
liabilities that we fail to discover, or are unable to discover, in our due diligence prior to the consummation of an acquisition, and we may not be indemnified for some or all these liabilities. In
addition, our funding requirements associated with acquisitions and integration costs may reduce the funds available to us to make dividend payments.
Insurance may not be sufficient to cover all losses.
Our business involves significant operating hazards related to the generation of electricity. While we believe that the projects'
insurance coverage addresses all material insurable risks, provides coverage that is similar to what would be maintained by a prudent owner/operator of similar facilities, and are subject to
deductibles, limits and exclusions which are customary or reasonable given the cost of procuring insurance, current operating conditions and insurance market conditions, there can be no assurance that
such insurance will continue to be offered on an economically feasible basis, nor that all events that could give rise to a loss or liability are insurable, nor that the amounts of insurance will at
all times be sufficient to cover each and every loss or claim that may occur involving our assets or operations of our projects. Any losses in excess of those
covered by insurance, which may include a significant judgment against any project or project operator, the loss of a significant permit or other approval or the imposition of a significant fine or
penalty, could have a material adverse effect on our business, financial condition and future prospects and could adversely affect dividends to our shareholders.
Financing arrangements could negatively impact our business.
Our current or future borrowings could increase the level of financial risk to us and, to the extent that the interest rates are not
fixed and rise, or that borrowings are refinanced at higher rates, then cash available for dividends could be adversely affected. As of June 30, 2011, we had no borrowings outstanding under our
revolving credit facility, $209.7 million of outstanding convertible debentures, and $285.1 million of outstanding non-recourse project-level debt. Covenants in these
borrowings may also adversely affect cash available for dividends. In addition, most of the projects currently have non-recourse term loans or other financing arrangements in place with
various lenders. These financing arrangements are typically secured by all of the project assets and contracts as well as our equity interests in the project. The terms of these financing arrangements
generally impose many covenants and obligations on the part of the borrower. For example, some agreements contain requirements to maintain specified debt service coverage ratios before cash may be
distributed from the relevant project to us, which is currently the case with a number of our projects. In many cases, a default by any party under key project agreements (such as a PPA or a fuel
supply agreement) will also constitute a default under the project's term loan or other financing arrangement. Failure to comply with the terms of these term loans or other financing arrangements, or
events of default thereunder, may prevent cash distributions by the project to us and may entitle the lenders to demand repayment and/or enforce their security interests.
26
Table of Contents
Our
failure to refinance or repay any indebtedness when due could constitute a default under such indebtedness. Under such circumstances, it is expected that dividends to our
shareholders would not be permitted until such indebtedness was refinanced or repaid and we may be required to sell assets or take other actions, including the initiation of bankruptcy proceedings or
the commencement of an out-of-court debt restructuring.
Our equity interests in our projects may be subject to transfer restrictions.
The partnership or other agreements governing some of the projects may limit a partner's ability to sell its interest. Specifically,
these agreements may prohibit any sale, pledge,
transfer, assignment or other conveyance of the interest in a project without the consent of the other partners. In some cases, other partners may have rights of first offer or rights of first refusal
in the event of a proposed sale or transfer of our interest. These restrictions may limit or prevent us from managing our interests in the projects in the manner we see fit, and may have an adverse
effect on our ability to sell our interests in these projects at the prices we desire.
The projects are exposed to risks inherent in the use of derivative instruments.
We and the projects may use derivative instruments, including futures, forwards, options and swaps, to manage commodity and financial
market risks. In the future, the project operators could recognize financial losses on these arrangements as a result of volatility in the market values of the underlying commodities or if a
counterparty fails to perform under a contract. If actively quoted market prices and pricing information from external sources are not available, the valuation of these contracts would involve
judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Most of these contracts are recorded at fair value with changes in fair value recorded currently in earnings, resulting in significant volatility in our income (as
calculated in
accordance with U.S. GAAP) that does not significantly affect current period cash flows or the underlying risk management purpose of the derivative instruments. As a result, we may be unable to
accurately predict the impact that our risk management decisions may have on our quarterly and annual income (as calculated in accordance with U.S. GAAP).
If
the values of these financial contracts change in a manner that we do not anticipate, or if a counterparty fails to perform under a contract, it could harm our financial condition,
results of operations and cash flows. We have executed natural gas swaps to reduce our risks to changes in the market price of natural gas, which is the fuel consumed at many of our projects. Due to
declining natural gas prices, we have incurred losses on these natural gas swaps. We execute these swaps only for the purpose of managing risks and not for speculative trading.
Our Piedmont project is subject to construction risk.
The Piedmont project commenced construction in November 2010 and is expected to be completed in late 2012. In any construction
project, there is a risk that circumstances occur which prevent the timely completion of a project, cause construction costs to exceed the level budgeted, or result in operating performance standards
not being met.
In
the event a power project does not achieve commercial operation by its expected date, the project may be subject to increased construction costs associated with the continuing
accrual of interest on the project's construction loan, which customarily matures at the start of commercial operation and converts to a term loan. A delay in completion of construction may also
impact a project under its PPA which may include penalty provisions for a delay in commercial operation date or in situations of extreme delay, termination of the PPA.
27
Table of Contents
Construction
cost overruns which exceed the project's construction contingency amount may require that the project owner infuse additional funds in order to complete construction.
At
the completion of construction, the power project may not meet its expected operating performance levels. Adverse circumstances may impact the design, construction, and commissioning
of the project that could result in reduced output, increased heat rate or excessive air emissions.
Risks Related to Our Structure
We are dependent on our projects for virtually all cash available for dividends.
We are dependent on the operations and assets of the projects through our indirect ownership of interests in the projects. The actual
amount of cash available for dividends to our shareholders depends upon numerous factors, including profitability, changes in revenues, fluctuations in working capital, availability under existing
credit facilities, capital expenditure levels, applicable laws, compliance with contracts and contractual restrictive covenants contained in any debt documentation.
Distribution of available cash may restrict our potential growth.
A payout of a significant portion of substantially all of our operating cash flow will make additional capital and operating
expenditures dependent on increased cash flow or additional financing in the future. Lack of these funds could limit our future growth and cash flow. In addition, we may be precluded from pursuing
otherwise attractive acquisitions or investments if the projected short-term cash flow from the acquisition or investment are not adequate to service the capital raised to fund the
acquisition or investment.
Future dividends are not guaranteed.
Dividends to shareholders are paid at the discretion of our board of directors. Future dividends, if any, will depend on, among other
things, the results of operations, working capital requirements, financial condition, restrictive covenants, business opportunities, provisions of applicable law and other factors that our board of
directors may deem relevant. Our board of directors may decrease the level of or entirely discontinue payment of dividends.
Exchange rate fluctuations may impact the amount of cash available for dividends.
Our payments to shareholders and convertible debenture holders are denominated in Canadian dollars. Conversely, all of our projects'
revenues and expenses are denominated in U.S. dollars. As a result, we are exposed to currency exchange rate risks. Despite our hedges against this risk through 2013, any arrangements to mitigate this
exchange rate risk may not be sufficient to fully protect against this risk. If hedging transactions do not fully protect against this risk, changes in the currency exchange rate between U.S. and
Canadian dollars could adversely affect our cash available for distribution.
Our indebtedness could negatively impact our business and our projects.
The degree to which we are leveraged on a consolidated basis could increase and have important consequences for our shareholders,
including:
-
-
our ability in the future to obtain additional financing for working capital, capital expenditures, acquisitions or other
purposes may be limited;
-
-
our ability to refinance indebtedness on terms acceptable to us or at all; and
-
-
our ability to react to competitive pressures.
As of June 30, 2011, our consolidated long-term debt and our share of the debt of our unconsolidated affiliates represented approximately 53.4% of our total
capitalization, comprised of debt and balance sheet equity.
28
Table of Contents
Changes in our creditworthiness may affect the value of our common shares.
Changes to our perceived creditworthiness may affect the market price or value and the liquidity of our common shares. The interest
rate we pay on our credit facility may increase if certain credit ratios deteriorate.
Future issuances of our common shares could result in dilution.
Our articles of incorporation authorize the issuance of an unlimited number of common shares for such consideration and on such terms
and conditions as are established by our board of directors without the approval of any of our shareholders. We may issue additional common shares in connection with a future financing or acquisition.
The issuance of additional common shares may dilute an investor's investment in us and reduce cash available for distribution per common share.
Investment eligibility.
There can be no assurance that our common shares will continue to be qualified investments under relevant Canadian tax laws for trusts
governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans, registered education savings plans, registered disability savings plans and
tax-free savings accounts.
We are subject to Canadian tax.
As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes, and dividends that we pay are
generally subject to Canadian withholding tax if paid to a shareholder that is not a resident of Canada. In connection with our conversion from an IPS structure to a traditional common share structure
in 2009 and the related reorganization of our organizational structure, we received a note from our primary U.S. holding company (the "Intercompany Note"). We are required to include in computing our
taxable income interest on the Intercompany Note. We expect that our existing tax attributes initially will be available to offset this income inclusion such that it will not result in an immediate
material increase to our liability for Canadian taxes. However, once we fully utilize our existing tax attributes (or if, for any reason, these attributes were not available), our Canadian tax
liability would materially increase. Although we intend to explore potential opportunities in the future to preserve the tax efficiency of our structure, no assurances can be given that our Canadian
tax liability will not materially increase at that time.
Our prior and current structure may be subject to additional U.S. federal income tax liability.
Under our prior IPS structure, we treated the subordinated note component of each IPS as debt for U.S. federal income tax purposes.
Accordingly, we deducted the interest payments on the subordinated notes and reduced our net taxable income treated as "effectively connected income" for U.S. federal income tax purposes. Under our
current structure, our subsidiaries that are incorporated in the United States are subject to U.S. federal income tax on their income at regular corporate rates (currently as high as 35%, plus state
and local taxes), and our primary U.S. holding company will claim interest deductions with respect to the Intercompany Note in computing its income for U.S. federal income tax purposes. To the extent
this interest expense is disallowed or is otherwise not deductible, the U.S. federal income tax liability of our primary U.S. holding company will increase, which could materially affect our after-tax
cash available for distribution. While we received advice from our U.S. tax counsel, based on certain representations by us and our primary U.S. holding company and determinations made by our
independent advisors, as applicable, that the subordinated notes and the Intercompany Note should be treated as debt for U.S. federal income tax purposes, it is possible that the Internal Revenue
Service ("IRS") could successfully challenge those positions and assert that the subordinated notes or the Intercompany Note should be treated as equity rather than debt for U.S. federal income tax
purposes. In this case, the otherwise deductible interest on the subordinated notes or the Intercompany Note would be treated as non-deductible distributions, and interest payments on
29
Table of Contents
the subordinated notes would be subject to branch profits tax to the extent we had effectively connected earnings and profits, and interest payments on the Intercompany Note would be subject to U.S.
withholding tax to the extent that our primary U.S. holding company had current or accumulated earnings and profits. The determination of whether the subordinated notes and the Intercompany Note are
debt or equity for U.S. federal income tax purposes is based on an analysis of the facts and circumstances. There is no clear statutory definition of debt for U.S. federal income tax purposes, and its
characterization is governed by principles developed in case law, which analyzes numerous factors that are intended to identify the nature of the purported creditor's interest in the borrower.
Furthermore,
not all courts have applied this analysis in the same manner, and some courts have placed more emphasis on certain factors than other courts have. To the extent it were
ultimately determined that the subordinated notes or the Intercompany Note were not debt, our U.S. federal income tax liability for the applicable open tax years would materially increase, which could
materially affect our after-tax cash available for distribution. Alternatively, the IRS could argue that the interest on the subordinated notes or the Intercompany Note exceeded or exceeds an arm's
length rate, in which case only the portion of the interest expense that does not exceed an arm's length rate may be deductible and, the remainder would be treated as an equity distribution and
potentially subject to withholding tax as described above. We have received advice from independent advisors that the interest rates on the subordinated notes and the Intercompany Note were, when
issued, commercially reasonable under the circumstances, but the advice is not binding on the IRS.
Furthermore,
pursuant to the U.S. "earnings stripping" limitations, our primary U.S. holding company's deductions attributable to the interest expense on the Intercompany Note may be
limited by the amount by which its net interest expense (the interest paid by the U.S. holding company on all debt, including the Intercompany Note, less its interest income) exceeds 50% of its
adjusted taxable income (generally, U.S. federal taxable income before net interest expense, net operating loss carryovers, depreciation and amortization). Any disallowed interest expense may
currently be carried forward to future years. Moreover, proposed legislation has been introduced, though not enacted, several times in recent years that would further limit the 50% of adjusted taxable
income cap described above to 25% of adjusted taxable income. Furthermore, if our primary U.S. holding company does not make regular interest payments as required under the Intercompany Note, other
limitations on the deductibility of interest under U.S. federal income tax laws could apply to defer and/or eliminate all or a portion of the interest deduction that the U.S. holding company would
otherwise be entitled to with respect to the Intercompany Note.
Passive foreign investment company treatment.
We do not believe that we are a passive foreign investment company, and we do not expect to become a passive foreign investment
company. However, if we were a passive foreign investment company while a taxable U.S. holder held common shares, such U.S. holder could be subject to an interest charge on any deferred taxation and
the treatment of gain upon the sale of our stock as ordinary income.
Risks Related to the Plan of Arrangement
There can be no assurance that the Plan of Arrangement will be completed and this offering is not conditioned upon the completion of the Plan of Arrangement.
The Arrangement Agreement provides that we will acquire, directly or indirectly, all of the issued and outstanding CPILP units
pursuant to a Plan of Arrangement under the
Canada Business Corporations Act
. Completion of the Plan of Arrangement is conditioned upon the receipt of
certain governmental authorizations, consents, orders or other approvals, including but not limited to approval under the
Investment Canada Act
, the
Competition
Act
(Canada), the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as
amended
(United States) and the
United States Federal Power Act
. The Plan of Arrangement must also be approved by the Court of
Queen's Bench of Alberta and both our
30
Table of Contents
shareholders and CPILP's unitholders. No assurance can be given that the required approvals will be obtained, and, even if such approvals are obtained, no assurance can be given as to the terms,
conditions and timing of the approvals or that they will satisfy the terms of the Arrangement Agreement.
This
offering is not conditioned on the completion of the Plan of Arrangement and there can be no assurance that the Plan of Arrangement will be completed. The common shares offered
hereby will remain outstanding whether or not the Plan of Arrangement is completed.
If the financing for the transactions contemplated by the Arrangement Agreement becomes unavailable, the Plan of Arrangement may not be completed.
We intend to use the net proceeds from this offering to finance a portion of the cash purchase price necessary to complete the Plan of
Arrangement. We plan to fund the remainder of the cash consideration payable by us under the Plan of Arrangement, including related fees and expenses, with the net proceeds from a senior unsecured
notes offering and/or drawings under a $625 million senior secured credit facility, for which we have received the written commitment of a Canadian chartered bank and another financial
institution. However, funding under this facility is subject to certain conditions, including, without limitation, that there shall not have occurred a material adverse effect with respect to Atlantic
Power, CPILP, CPI Income Services Ltd. and CPI Investments Inc. taken as a whole. In the event that the lenders under the facility fail to provide funding for this or any other reason, we may not be
able to complete the Plan of Arrangement and may be subject to a termination fee of C$35.0 million.
If the Arrangement Agreement is terminated, we may be required to pay a termination fee or make an expense reimbursement payment.
The Arrangement Agreement provides that we will pay a C$35.0 million termination fee to CPILP if CPILP terminates the
Arrangement Agreement on account of certain actions or events, including the failure of our board of directors to maintain its favorable recommendation for the issuance of Atlantic Power common shares
in connection with the Plan of Arrangement, failure of financing or a breach of our obligations under the Arrangement Agreement. If the Arrangement Agreement is terminated under circumstances where no
termination fee is payable, we may still be required to make an expense reimbursement payment to CPILP, up to a maximum of C$8.0 million, in certain circumstances, including, but not limited
to, if our shareholders do not approve issuance of our common shares in exchange for CPILP units pursuant to the Plan of Arrangement.
Failure to complete the Plan of Arrangement could negatively impact our share price and our future business and financial results.
If the Plan of Arrangement is not completed for any reason, our ongoing business may be adversely affected and we will be subject to a
number of risks, including the following:
-
-
we may be required, under certain circumstances, to pay a termination fee in the amount of C$35.0 million to CPILP
or make a reimbursement of expenses payment to CPILP of up to C$8 million in connection with a termination of the Arrangement Agreement in certain circumstances;
-
-
we will be required to pay certain other costs relating to the Arrangement Agreement and Plan of Agreement, whether or not
completed, such as legal, accounting, financial advisor and printing fees; and
-
-
matters relating to the Arrangement Agreement and Plan of Arrangement (including integration planning) require substantial
commitments of time and resources by our management, whether or not the Plan of Arrangement is completed, which could otherwise
31
Table of Contents
If
the Plan of Arrangement is not completed, these risks may materialize and may adversely affect our business, operations, financial results and financial condition, as well as the
trading price of our common shares.
We have not identified any specific use of the net proceeds of this offering in the event the Plan of Arrangement is not completed.
Consummation of the Plan of Arrangement is subject to a number of conditions and approvals, and, if the Plan of Arrangement is not
completed for any reason, our board of directors and management will have broad discretion over the use of the net proceeds we receive following this offering and might not apply the net proceeds in
ways that increase the trading price of our common shares. Since the primary purpose of this offering is to provide funds to pay a portion of the cash amount we are required to pay in connection with
the Plan of Arrangement, we have not identified a specific use for the net proceeds in the event the Plan of Arrangement is not completed. Any funds received may be used by us for any corporate
purpose, which may include pursuit of other business combinations, expansion of our operations, share repurchases or other uses. The failure of our management to use the net proceeds from this
offering effectively could have an adverse effect on our business and may have an adverse effect on our earnings per share.
The failure to integrate successfully the businesses of Atlantic Power and CPILP in the expected timeframe would adversely affect the combined company's future results.
The success of the Plan of Arrangement will depend, in large part, on our ability to realize the anticipated benefits, including cost
savings, from combining the businesses of Atlantic Power and CPILP. To realize these anticipated benefits, the businesses of Atlantic Power and CPILP must be successfully integrated. This integration
will be complex and time-consuming. The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in the combined company
not fully achieving the anticipated benefits of the Plan of Arrangement.
Potential
difficulties that may be encountered in the integration process include the following:
-
-
challenges and difficulties associated with managing the larger, more complex, combined business;
-
-
conforming standards, controls, procedures and policies, business cultures and compensation structures between the
entities;
-
-
integrating personnel from the two entities while maintaining focus on developing, producing and delivering consistent,
high quality services;
-
-
consolidating corporate and administrative infrastructures;
-
-
coordinating geographically dispersed organizations;
-
-
potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Plan of
Arrangement;
-
-
performance shortfalls at one or both of the entities as a result of the diversion of management's attention caused by
completing the Plan of Arrangement and integrating the entities' operations; and
-
-
the ability of the combined company to deliver on its strategy going forward.
32
Table of Contents
Our growth plans upon completion of the Plan of Arrangement are dependent on future acquisitions and growth opportunities that may not be realized.
The ability to expand through acquisitions and growth opportunities is integral to our business strategy following completion of the
Plan of Arrangement and requires that we identify and consummate suitable acquisition or investment opportunities that meet our investment criteria and are compatible with our growth strategy. We may
not be successful in identifying and consummating acquisitions or investments that meet our investment criteria on satisfactory terms or at all. The failure to identify and consummate suitable
acquisitions, to take advantage of other investment opportunities, or to integrate successfully any acquisitions without substantial expense, delay or other operational or financial problems, would
impede our growth and negatively affect our results of operations and cash available for distribution to our shareholders.
We may be adversely affected by increased debt and debt service obligations.
We plan to fund a significant portion of the cash consideration payable by us under the Plan of Arrangement, including related fees
and expenses, with the net proceeds from a senior unsecured notes offering and/or drawings under a $625 million senior secured credit facility, for which we have received the written commitment
of a Canadian chartered bank and another financial institution. Such facility will be guaranteed by us and each of our existing and subsequently acquired or organized direct or indirect subsidiaries
(excluding CPILP and each of its subsidiaries), and will contain covenants restricting certain actions by us and our subsidiaries (including CPILP and its subsidiaries), including financial,
affirmative and negative covenants, which may include limitations on the ability to incur indebtedness, create liens and merge and consolidate with other companies, in each case, subject to exceptions
and baskets that may be mutually agreed upon by us and the lender parties thereto, the exact terms of which will be negotiated before the effective time for the Plan of Arrangement.
Assuming completion of the Plan of Arrangement, we will have an increased amount of indebtedness. On a pro forma basis assuming the completion of this offering and
that the Plan of
Arrangement was consummated on , we would have had $ of
indebtedness. We may also obtain additional long-term debt and working capital lines of credit to meet
future financing needs, subject to certain restrictions under our existing indebtedness, which would further increase our total debt.
The
potential significant negative consequences on our financial condition and results of operations that could result from our increased amount of debt
include:
-
-
limitations on our ability to obtain additional debt or equity financing;
-
-
instances in which we are unable to meet the financial covenants contained in our debt agreements or to generate cash
sufficient to make required debt payments, which circumstances would have the potential of accelerating the maturity of some or all of our outstanding indebtedness;
-
-
the allocation of a material portion of our cash flow from operations to service our debt, thus reducing the amount of our
cash flow available for other purposes, including funding operating costs and capital expenditures that could improve our competitive position, results of operations or share price;
-
-
requiring us to sell debt or equity securities or to sell some of our core assets, possibly on unfavorable terms, to meet
payment obligations;
-
-
compromising our flexibility to plan for, or react to, competitive challenges in our business and the power industry;
33
Table of Contents
-
-
the possibility of us being put at a competitive disadvantage with our competitors that do not have as much debt as we
have, and competitors that may be in a more favorable position to access additional capital resources in a timely manner; and
-
-
limitations on our ability to execute business development activities to support our strategies.
A downgrade in Atlantic Power's or CPILP's credit ratings or any deterioration in their credit quality could negatively affect our ability to access capital and our ability
to hedge and could trigger termination rights under certain contracts.
A downgrade in Atlantic Power's or CPILP's credit ratings or deterioration in their credit quality could adversely affect our ability
to renew existing, or obtain access to new, credit facilities and could increase the cost of such facilities and trigger termination rights or enhanced disclosure requirements under certain contracts
to which CPILP is a party. Any downgrade of CPILP's corporate credit rating could cause counterparties and financial derivative markets to require CPILP to post letters of credit or other collateral,
make cash prepayments, obtain a guarantee agreement or provide other security, all of which would expose CPILP to additional costs.
Our results of operations may differ significantly from the unaudited pro forma condensed combined consolidated financial information included in this prospectus.
This prospectus includes unaudited pro forma condensed combined consolidated financial statements to illustrate the effects of the
Plan of Arrangement on our historical financial position and operating results. The unaudited pro forma condensed combined consolidated statements of operations for the fiscal year ended
December 31, 2010 and for the six months ended June 30, 2011 combine the historical consolidated statements of operations of Atlantic Power and CPILP, giving effect to the Plan of
Arrangement, as if it had occurred on January 1, 2010. The unaudited pro forma condensed combined consolidated balance sheet as of June 30, 2011 combines the historical consolidated
balance sheets of Atlantic Power and CPILP, giving effect to the Plan of Arrangement as if it had occurred on June 30, 2011. This unaudited pro forma financial information is presented for
illustrative purposes only and does not necessarily indicate the results of operations or the combined financial position that would have resulted had the Plan of Arrangement been completed as of the
dates or at the beginning of the periods presented, as applicable, nor is it indicative of the results of operations in future periods or the future financial position of the combined company.
We expect to incur significant expenses related to the integration of Atlantic Power and CPILP.
We have incurred significant expenses in connection with the Plan of Arrangement and expect to incur additional significant expenses
in connection with the integration of Atlantic Power and CPILP. There are a large number of processes, policies, procedures, operations, technologies and systems that must be integrated. While we have
assumed that a certain level of expenses will be incurred, there are many factors beyond our control that could affect the total amount or the timing of the integration expenses. Moreover, many of the
expenses that will be incurred are, by their nature, difficult to estimate accurately. These integration expenses likely will result in our taking significant charges against earnings following the
completion of the Plan of Arrangement, and the amount and timing of such charges are uncertain at present.
If goodwill or other intangible assets that we record in connection with the Plan of Arrangement become impaired, we could have to take significant charges against earnings.
In connection with the accounting for the Plan of Arrangement, we expect to record a significant amount of goodwill and other
intangible assets. Under U.S. GAAP, we must assess, at least annually and potentially more frequently, whether the value of goodwill and other indefinite-lived intangible assets has been
impaired. Amortizing intangible assets will be assessed for impairment in the event of an impairment indicator. Any reduction or impairment of the value of goodwill or other
34
Table of Contents
intangible
assets will result in a charge against earnings, which could materially adversely affect our results of operations and shareholders' equity in future periods.
We must continue to retain, motivate and recruit executives and other key employees, which may be difficult in light of the uncertainty regarding the Plan of Arrangement,
and failure to do so could negatively affect us.
We must be successful at retaining, recruiting and motivating key employees following the completion of the Plan of Arrangement.
Experienced employees in the power industry are in high demand and competition for their talents can be intense. Employees of both Atlantic Power and CPILP may experience uncertainty about their
future role with the combined company until, or even after, strategies with regard to the combined company are announced or executed. These potential distractions of the Plan of Arrangement may
adversely affect our ability to attract, motivate and retain executives and other key employees and keep them focused on applicable
strategies and goals. A failure to retain and motivate executives and other key employees during the period prior to or after the completion of the Plan of Arrangement could have an adverse impact on
our business.
There are factors that could cause the Plan of Arrangement not to be accretive and could cause dilution to our distributable cash flow per share, which may negatively affect
the market price of our common shares.
We could encounter transaction and integration-related costs or other factors such as the failure to realize benefits anticipated in
the Plan of Arrangement. All of these factors could cause dilution to our distributable cash flow per share or decrease or delay the expected accretive effect of the Plan of Arrangement and cause a
decrease in the market price of our common shares. Accordingly, we may not be able to increase our dividends following completion of the Plan of Arrangement as currently planned.
CPI Preferred Equity Ltd. is subject to Canadian tax, as is Atlantic Power's income from CPILP.
As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes. See "Risk
factorsRisks related to our structureWe are subject to Canadian tax". Following completion of the Plan of Arrangement, we will be required to include in computing our taxable
income any income earned by CPILP. In addition, CPI Preferred Equity Ltd., a subsidiary of CPILP, is also a Canadian corporation and is generally subject to Canadian federal, provincial and
other taxes. CPI Preferred Equity Ltd. is, and following the completion of the Plan of Arrangement will continue to be, liable to pay material Canadian cash taxes.
Our incorporation of the CPILP structure following the Plan of Arrangement may be subject to additional U.S. federal income tax liability.
CPILP's U.S. structure has in place certain intercompany financing arrangements (the "CPILP Financing Arrangements"). While CPILP has
received advice from its U.S. accountants, based on certain representations by its holding companies, that the payments on the CPILP Financing Arrangements should be deductible for U.S. federal income
tax purposes, it is possible that the IRS could successfully challenge the deductibility of these payments. If the IRS were to succeed in characterizing these payments as non-deductible,
the adverse consequences discussed above with respect to the Intercompany Loan could apply in connection with the CPILP Financing Arrangements. See "Risk factorsRisks related to our
structureOur prior and current structure may be subject to additional U.S. federal income tax liability." In addition, even if the payments are respected as interest, the deduction
thereof could nevertheless be limited by the earnings stripping limitations, as discussed above with respect to our current structure. The earnings stripping limitations will also apply to other
indebtedness of CPILP's U.S. group that is guaranteed by CPILP or Atlantic Power. Finally, the applicability of recent changes to the U.S.-Canada Income Tax Treaty to the structure associated with
certain of the CPILP Financing Arrangements may result in distributions from CPILP's U.S. group to
35
Table of Contents
its Canadian parent being subject to a 30% rate of withholding tax instead of the 5% rate that would otherwise have applied.
Risks Related to Our Common Shares
Market conditions and other factors may affect the value of our common shares.
The trading price of our common shares will depend on many factors, which may change from time to time,
including:
-
-
conditions in the power generation markets and the energy markets generally;
-
-
interest rates;
-
-
the market for similar securities;
-
-
government action or regulation;
-
-
general economic conditions or conditions in the financial markets;
-
-
our past and future dividend practice; and
-
-
our financial condition, performance, creditworthiness and prospects.
Accordingly,
the common shares that an investor purchases, whether in this offering or in the secondary market, may trade at a price lower than that at which they were purchased.
The market price and trading volume of our common shares may be volatile.
The market price of our common shares may be volatile, particularly given the current economic environment. In addition, the trading
volume in our common shares may fluctuate and cause significant price variations to occur. If the market price of our common shares declines significantly, you may be unable to resell your shares at
or above the purchase price. The market price of our common shares may fluctuate or decline significantly in the future.
Some
of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common shares include:
-
-
quarterly variations in our operating results or the quality of our assets;
-
-
changes in applicable regulations or government action;
-
-
operating results that vary from the expectations of management, securities analysts and investors;
-
-
changes in expectations as to our future financial performance;
-
-
announcements of innovations, new products, strategic developments, significant contracts, acquisitions and other material
events by us or our competitors;
-
-
changes in financial estimates or publication of research reports and recommendations by financial analysts or actions
taken by rating agencies with respect to us or other companies in our industry;
-
-
the operating and securities price performance of other companies that investors believe are comparable to us;
-
-
changes in general market conditions, such as interest or foreign exchange rates, stock or commodity valuations, or
volatility; and
-
-
actions by our current shareholders, including sales of our common shares by existing shareholders and/or directors and
executive officers.
36
Table of Contents
Stock
markets in general have experienced significant volatility over the past two years, and continue to experience significant price and volume volatility. As a result, the market
price of our common shares may continue to be subject to similar market fluctuations that may be unrelated to our operating performance or prospects. Increased volatility could result in a decline in
the market price of our common shares.
Present and future offerings of debt or equity securities, ranking senior to our common shares, may adversely affect the market price of our common shares.
If we decide to issue debt or equity securities ranking senior to our common shares in the future it is likely that they will be
governed by an indenture or other instrument containing covenants restricting our operating flexibility. Additionally, any convertible or exchangeable securities that we issue in the future may have
rights, preferences and privileges more favorable than those of holders of our common shares and may result in dilution to holders of our common shares. We and, indirectly, our shareholders, will bear
the cost of issuing and servicing such securities. Because our decision to issue debt or equity securities in any future offering will depend on market conditions and other factors, we cannot predict
or estimate the amount, timing or nature of our future offerings. Thus, holders of our common shares will bear the risk of our future offerings reducing the market price of our common shares and
diluting the value of their share holdings in us.
The number of shares available for future sale could adversely affect the market price of our common shares.
We cannot predict whether future issuances of our common shares or the availability of shares for resale in the open market will
decrease the market price per common share. We may issue additional common shares, including securities that are convertible into or exchangeable for, or that represent the right to receive common
shares. Sales of a substantial number of common shares in the public market or the perception that such sales might occur could materially adversely affect the market price of our common shares.
Because our decision to issue securities in any future offering will depend on market conditions and other factors, we cannot predict or estimate the amount,
timing or nature of our future offerings. Thus, our shareholders bear the risk of our future offerings reducing the market price of our common shares and diluting their share holdings in us.
The
exercise of the underwriters' option to purchase additional common shares, the exercise of any options granted to directors, executive officers and other employees under our stock
compensation plans, and other issuances of our common shares could have an adverse effect on the market price of our common shares, and the existence of options may materially adversely affect the
terms upon which we may be able to obtain additional capital through the sale of equity securities. In addition, future sales of our common shares may be dilutive to existing shareholders.
The redemption of our outstanding debentures for or repayment of principal by issuing common shares may cause common shareholders dilution.
We may determine to redeem outstanding debentures for common shares or to repay outstanding principal amounts thereunder at maturity
of the debentures by issuing additional common shares. The issuance of additional common shares may have a dilutive effect on shareholders and an adverse impact on the price of our common shares.
Provisions of our articles of continuance could discourage potential acquisition proposals and could deter or prevent a change in control.
We are governed by the Business Corporations Act (British Columbia). Our articles of continuance contain provisions that could have
the effect of delaying, deferring or discouraging another party from acquiring control of our company by means of a tender offer, a proxy contest or otherwise. These provisions may make it more
difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire a substantial number of our common shares or to launch other takeover attempts
that a shareholder might consider to be in his or her best interest. These provisions could limit the price that some investors might be willing to pay in the future for our common shares.
37
Table of Contents
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS
This prospectus and the documents incorporated by reference herein contain forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995
with respect to the financial condition, results of operations, business strategies, operating
efficiencies, synergies, revenue enhancements, competitive positions, plans and objectives of management and growth opportunities of Atlantic Power and CPILP, and with respect to the Plan of
Arrangement and the markets for CPILP units and Atlantic Power common shares and other matters. Statements in this prospectus and the documents incorporated by reference herein that are not historical
facts are hereby identified as forward-looking statements for the purpose of the safe harbor provided by Section 27A of the Securities Act and Section 21E of the Exchange Act and
forward-looking information within the meaning defined under applicable Canadian securities legislation (collectively, "forward-looking statements").
These forward-looking statements relate to, among other things, the expected benefits of the Plan of Arrangement, such as accretion, the ability to pay increased
dividends, enhanced
cash flow, growth potential, liquidity and access to capital, market profile and financial strength, the position of the
combined company and the expected timing of the completion of the Plan of Arrangement, if completed.
Forward-looking
statements can generally be identified by the use of words such as "should," "intend," "may," "expect," "believe," "anticipate," "estimate," "continue," "plan,"
"project," "will," "could," "would," "target," "potential" and other similar expressions. In addition, any statements that refer to expectations, projections or other characterizations of future
events or circumstances are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, such statements involve risks and
uncertainties, and undue reliance should not be placed on such statements. Certain material factors or assumptions are applied in making forward-looking statements, including, but not limited to,
factors and assumptions regarding the items outlined above. Actual results may differ materially from those expressed or implied in such statements. Important factors that could cause actual results
to differ materially from these expectations include, among other things:
-
-
the failure to receive, on a timely basis or otherwise, the required approvals by Atlantic Power shareholders, CPILP
unitholders and government or regulatory agencies (including the terms of such approvals);
-
-
the risk that a condition to closing of the Plan of Arrangement may not be satisfied;
-
-
the possibility that the anticipated benefits and synergies from the Plan of Arrangement cannot be fully realized or may
take longer to realize than expected;
-
-
the possibility that costs or difficulties related to the integration of Atlantic Power and CPILP operations will be
greater than expected;
-
-
the ability of the combined company to retain and hire key personnel and maintain relationships with customers, suppliers
or other business partners;
-
-
the impact of legislative, regulatory, competitive and technological changes;
-
-
the risk that the credit ratings of the combined company may be different from what the companies expect;
-
-
the amount of distributions expected to be received from our projects and our estimated net cash tax refunds;
38
Table of Contents
-
-
the expected use of proceeds from this offering and any private offering of senior unsecured notes;
and
-
-
other risk factors relating to us and the power industry, as detailed from time to time in our filings with the SEC and
the Canadian Securities Administrators (the "CSA").
Additional
information about these factors and about the material factors or assumptions underlying such forward-looking statements may be found in this prospectus under the section
entitled "Risk factors," beginning on page 19.
You
are cautioned that any forward-looking statement speaks only as of the date of this prospectus or, if such statement is included in a document incorporated by reference into this
prospectus, as of the date of such other document. We undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise,
except as may be required by applicable law.
39
Table of Contents
EXCHANGE RATE INFORMATION
The following table sets forth, for each period indicated, the high and low exchange rates for one U.S. dollar, expressed in Canadian
dollars, the average of such exchange rates on the last day of each month during such period and the exchange rate at the end of such period, based on the noon buying rate as quoted by the Bank of
Canada. On September 14, 2011, the noon buying rate was $1.00 = C$0.9913.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
Twelve Months Ended
December 31,
|
|
|
|
2011
|
|
2010
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
|
2006
|
|
High
|
|
C$
|
1.0022
|
|
C$
|
1.0778
|
|
C$
|
1.0778
|
|
C$
|
1.3000
|
|
C$
|
1.2969
|
|
C$
|
1.1853
|
|
C$
|
1.1726
|
|
Low
|
|
C$
|
0.9486
|
|
C$
|
0.9961
|
|
C$
|
0.9946
|
|
C$
|
1.0292
|
|
C$
|
0.9719
|
|
C$
|
0.9170
|
|
C$
|
1.0990
|
|
Average
|
|
C$
|
0.9769
|
|
C$
|
1.0338
|
|
C$
|
1.0299
|
|
C$
|
1.1420
|
|
C$
|
1.0660
|
|
C$
|
1.0748
|
|
C$
|
1.1341
|
|
Period End
|
|
C$
|
0.9643
|
|
C$
|
1.0606
|
|
C$
|
0.9946
|
|
C$
|
1.0466
|
|
C$
|
1.2246
|
|
C$
|
1.0120
|
|
C$
|
1.1653
|
|
40
Table of Contents
USE OF PROCEEDS
We expect to receive net proceeds from this offering of approximately
$ million after deducting the underwriting
discount and our estimated expenses (or approximately $ million if the underwriters exercise their over-allotment option to purchase additional shares in full). We intend to
use
the net proceeds from this offering to:
-
(i)
-
fund
a portion of the cash consideration payable by us under the Plan of Arrangement; and
-
(ii)
-
to
the extent that any proceeds remain thereafter, or the Plan of Arrangement is not completed, to fund additional growth opportunities and for general
corporate purposes.
This
offering is not conditioned on the completion of the Plan of Arrangement and there can be no assurance that the Plan of Arrangement will be completed. The shares offered hereby
will remain outstanding whether or not the Plan of Arrangement is completed.
We
intend to fund the remainder of the cash consideration payable by us under the Plan of Arrangement, including related fees and expenses, with the net proceeds from a senior unsecured
notes offering and/or borrowings under a $625 million senior secured credit facility, for which we have received the written commitment of a Canadian chartered bank and another financial
institution. This offering is not conditioned upon the successful completion of a private offering of senior unsecured notes and any private offering of senior unsecured notes will not be conditioned
upon the successful completion of this offering.
41
Table of Contents
DIVIDENDS AND DIVIDEND POLICY
On November 24, 2009, our shareholders approved our conversion to a common share structure. Subsequent to the conversion, we
have continued to maintain our business strategy and our current distribution levels. Each IPS has been exchanged for one new common share. Our entire current monthly cash distribution of C$0.0912 per
common share is being paid as a dividend on the new common shares on the last business day of each month for holders of record on the last business day of the immediately preceding month.
The transactions contemplated by the Plan of Arrangement are expected to be immediately accretive to cash available for distribution following the effective date of
the Plan of
Arrangement. As a result, our management intends to recommend to our board of directors to increase our dividend by 5% from C$1.094 per share to C$1.15 per share on an annual basis following the
effective date of the Plan of Arrangement. Upon completion of the Plan of Arrangement, our dividend will continue to be paid monthly. Future dividends are paid at the discretion of our board of
directors subject to, among other things, our earnings and cash flow and are not guaranteed. The primary risk that impacts our ability to continue paying cash dividends at the current rate is the
operating performance of our projects and their ability to distribute cash to us after satisfying project-level obligations.
Dividends
declared per common share (or distributions per IPS) for each of the monthly periods shown below were as follows (C$):
|
|
|
|
|
|
|
|
|
|
|
Month
|
|
2011
|
|
2010
|
|
2009
|
|
|
|
Amount
|
|
January
|
|
$
|
0.0912
|
|
$
|
0.0912
|
|
$
|
0.0912
|
|
February
|
|
|
0.0912
|
|
|
0.0912
|
|
|
0.0912
|
|
March
|
|
|
0.0912
|
|
|
0.0912
|
|
|
0.0912
|
|
April
|
|
|
0.0912
|
|
|
0.0912
|
|
|
0.0912
|
|
May
|
|
|
0.0912
|
|
|
0.0912
|
|
|
0.0912
|
|
June
|
|
|
0.0912
|
|
|
0.0912
|
|
|
0.0912
|
|
July
|
|
|
0.0912
|
|
|
0.0912
|
|
|
0.0912
|
|
August
|
|
|
0.0912
|
|
|
0.0912
|
|
|
0.0912
|
|
September
|
|
|
|
|
|
0.0912
|
|
|
0.0912
|
|
October
|
|
|
|
|
|
0.0912
|
|
|
0.0912
|
|
November
|
|
|
|
|
|
0.0912
|
|
|
0.0912
|
|
December
|
|
|
|
|
|
0.0912
|
|
|
0.0912
|
|
42
Table of Contents
MARKET PRICE OF THE COMMON SHARES
The IPSs were listed and posted for trading on the TSX under the symbol "ATP.UN" from the time of our initial public offering in
November 2004 through November 30, 2009. Following the closing of the exchange of IPSs for common shares, our new common shares commenced trading on the TSX on December 2, 2009 under the
symbol "ATP." The following table sets forth the price ranges of the outstanding IPSs and common shares, as applicable, as reported by the TSX for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
High (C$)
|
|
Low (C$)
|
|
2009
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
9.28
|
|
$
|
6.34
|
|
|
Second Quarter
|
|
|
9.45
|
|
|
7.71
|
|
|
Third Quarter
|
|
|
9.49
|
|
|
8.55
|
|
|
Fourth Quarter
|
|
|
11.90
|
|
|
9.08
|
|
2010
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
13.85
|
|
|
11.50
|
|
|
Second Quarter
|
|
|
12.90
|
|
|
11.20
|
|
|
Third Quarter
|
|
|
14.47
|
|
|
12.11
|
|
|
Fourth Quarter
|
|
|
15.18
|
|
|
13.31
|
|
2011
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
15.50
|
|
|
14.41
|
|
|
Second Quarter
|
|
|
15.72
|
|
|
13.82
|
|
|
Third Quarter (until September 14, 2011)
|
|
|
15.46
|
|
|
12.92
|
|
Our shares began trading on the NYSE under the symbol "AT" on July 23, 2010. The following table sets forth the price ranges of our
outstanding common shares, as reported by the NYSE from the date on which our common shares were listed through December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
High ($)
|
|
Low ($)
|
|
2010
|
|
|
|
|
|
|
|
|
Third Quarter (beginning July 23, 2010)
|
|
$
|
14.00
|
|
$
|
12.10
|
|
|
Fourth Quarter
|
|
|
14.98
|
|
|
13.26
|
|
2011
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
15.75
|
|
|
14.72
|
|
|
Second Quarter
|
|
|
16.18
|
|
|
14.33
|
|
|
Third Quarter (until September 14, 2011)
|
|
|
16.34
|
|
|
13.12
|
|
On September 14, 2011, there were 68,984,192 of our common shares issued and outstanding, and the number of holders of our common shares
was approximately 53,998.
43
Table of Contents
CAPITALIZATION
The following table shows our capitalization as of June 30, 2011:
-
-
on an actual basis;
-
-
on an as adjusted basis to give effect to the sale of our common shares in this offering, at an assumed offering price of
$14.71 per share, the last reported sale price of our common shares on the New York Stock Exchange September 14, 2011, after deducting underwriting discounts and estimated transaction expenses
payable by us; and
-
-
on an as further adjusted basis to give effect to:
-
-
the issue of approximately 31.5 million common shares we expect to issue in exchange for CPILP units in connection
with the Plan of Arrangement;
-
-
the incurrence of additional debt (in the form of one or more private issuances of senior notes, borrowings under our
available credit facilities or a combination thereof) in the amount of $425 million; and
-
-
application of the net proceeds from this offering, any senior notes offerings and/or any borrowings under our credit
facilities to pay the cash portion of the amounts payable by us pursuant to the Plan of Arrangement, including related fees, costs and expenses, and completion of the Plan of Arrangement as described
elsewhere in this prospectus.
This
offering is not conditioned on the completion of the Plan of Arrangement and there can be no assurance that the Plan of Arrangement will be completed. The shares offered hereby
will remain outstanding whether or not the Plan of Arrangement is completed.
You should read this table in conjunction with the sections entitled "Use of proceeds" and "Unaudited pro forma condensed combined consolidated financial statements"
included elsewhere
in
44
Table of Contents
this prospectus, in addition to our consolidated financial statements and related notes incorporated by reference herein.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2011
|
|
|
|
Actual
|
|
As
adjusted
|
|
As further adjusted
|
|
|
|
(unaudited)
(in thousands)
|
|
Cash and cash equivalents:
|
|
$
|
46,551
|
|
$
|
236,831
|
|
$
|
650,019
|
|
|
|
|
|
|
|
|
|
Debt:
|
|
|
|
|
|
|
|
|
|
|
Convertible debentures due 2014
|
|
$
|
48,628
|
|
$
|
48,628
|
|
$
|
48,628
|
|
Convertible debentures due 2017
|
|
|
77,612
|
|
|
77,612
|
|
|
77,612
|
|
Convertible debentures due 2017
|
|
|
83,463
|
|
|
83,463
|
|
|
83,463
|
|
Senior unsecured notes
(1)
|
|
|
|
|
|
|
|
|
425,000
|
|
Current portion of project-level debt
|
|
|
21,962
|
|
|
21,962
|
|
|
21,962
|
|
Project-level debt
|
|
|
263,111
|
|
|
263,111
|
|
|
263,111
|
|
|
|
|
|
|
|
|
|
|
Total debt:
|
|
|
494,776
|
|
|
494,776
|
|
|
919,776
|
|
|
|
|
|
|
|
|
|
Shareholders' equity:
|
|
|
|
|
|
|
|
|
|
|
Common shares, no par value per share, unlimited authorized shares, 68,639,654 shares issued and outstanding,
actual; shares issued and outstanding, as adjusted
(2)
|
|
|
644,011
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss
|
|
|
24
|
|
|
24
|
|
|
24
|
|
Retained deficit
|
|
|
(215,782
|
)
|
|
(215,782
|
)
|
|
(215,782
|
)
|
|
|
|
|
|
|
|
|
|
Total shareholder's equity
|
|
|
428,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
969,570
|
|
$
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Assumes
completion of an offering of $425 million of senior unsecured notes. If we do not complete an offering of senior unsecured notes and the
Plan of Arrangement is completed, we intend to fund the remainder of the cash consideration payable by us from borrowing under a $625 million senior secured credit facility. See "Use of
proceeds."
-
(2)
-
Excludes
(i) 13,643,645 shares issuable upon conversion, redemption, purchase for cancellation or maturity of our outstanding convertible
debentures, and (ii) 409,295 unvested notional units granted under the terms of our Long Term Incentive Plan.
45
Table of Contents
SELECTED HISTORICAL CONSOLIDATED FINANCIAL INFORMATION FOR ATLANTIC POWER
The following table presents summary consolidated financial information for Atlantic Power. The annual historical information as of
December 31, 2010 and 2009 and for the years ended, December 31, 2010, 2009 and 2008 has been derived from the audited consolidated financial statements appearing in Atlantic Power's
Annual Report on Form 10-K for the year ended December 31, 2010, incorporated by reference into this prospectus. The annual historical information as of December 31,
2008, 2007 and 2006 and for the years ended December 31, 2007 and 2006 has been derived from historical financial statements not incorporated by reference into this prospectus. The historical
information as of, and for the six-month periods ended June 30, 2011 and 2010 has been derived from the unaudited consolidated financial statements appearing in Atlantic Power's Quarterly
Report on Form 10-Q for the quarter ended June 30, 2011, incorporated by reference into this prospectus. Data for all periods have been prepared under U.S. GAAP. You
should read the following selected consolidated financial data together with Atlantic Power's consolidated financial statements and the notes thereto and the discussion under "Management's Discussion
and Analysis of Financial Condition and Results of Operations" included as part of Atlantic Power's Annual Report on Form 10-K for the year ended December 31, 2010 and
Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, each of which is incorporated by reference into this prospectus. See "Where you can find more information"
beginning on page 85 of this prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Six Months
Ended
June 30,
|
|
(in thousands of US dollars,
except per share/subordinated note data and as otherwise stated)
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
|
2006
(a)
|
|
2011
(a)
|
|
2010
(a)
|
|
Project revenue
|
|
$
|
195,256
|
|
$
|
179,517
|
|
$
|
173,812
|
|
$
|
113,257
|
|
$
|
69,374
|
|
$
|
106,923
|
|
$
|
95,125
|
|
Project income
|
|
|
41,879
|
|
|
48,415
|
|
|
41,006
|
|
|
70,118
|
|
|
57,247
|
|
|
27,900
|
|
|
19,405
|
|
Net (loss) income attributable to Atlantic Power Corporation
|
|
|
(3,752
|
)
|
|
(38,486
|
)
|
|
48,101
|
|
|
(30,596
|
)
|
|
(2,408
|
)
|
|
19,322
|
|
|
(4,618
|
)
|
Basic earnings (loss) per share
|
|
$
|
(0.06
|
)
|
$
|
(0.63
|
)
|
$
|
0.78
|
|
$
|
(0.50
|
)
|
$
|
(0.05
|
)
|
$
|
0.28
|
|
$
|
(0.08
|
)
|
Basic earnings (loss) per share, C$
(b)
|
|
$
|
(0.06
|
)
|
$
|
(0.72
|
)
|
$
|
0.84
|
|
$
|
(0.53
|
)
|
$
|
(0.06
|
)
|
$
|
0.28
|
|
$
|
(0.08
|
)
|
Diluted earnings (loss) per share
(c)
|
|
$
|
(0.06
|
)
|
$
|
(0.63
|
)
|
$
|
0.73
|
|
$
|
(0.50
|
)
|
$
|
(0.05
|
)
|
$
|
0.28
|
|
$
|
(0.08
|
)
|
Diluted earnings (loss) per share, C$
(b)(c)
|
|
$
|
(0.06
|
)
|
$
|
(0.72
|
)
|
$
|
0.78
|
|
$
|
(0.53
|
)
|
$
|
(0.06
|
)
|
$
|
0.28
|
|
$
|
(0.08
|
)
|
Distribution per subordinated note
(d)
|
|
$
|
|
|
$
|
0.51
|
|
$
|
0.60
|
|
$
|
0.59
|
|
$
|
0.57
|
|
$
|
|
|
$
|
|
|
Dividend declared per common share
|
|
$
|
1.06
|
|
$
|
0.46
|
|
$
|
0.40
|
|
$
|
0.40
|
|
$
|
0.37
|
|
$
|
0.57
|
|
$
|
0.52
|
|
Total assets
|
|
$
|
1,013,012
|
|
$
|
869,576
|
|
$
|
907,995
|
|
$
|
880,751
|
|
$
|
965,121
|
|
$
|
1,008,980
|
|
$
|
862,525
|
|
Total long-term liabilities
|
|
$
|
518,273
|
|
$
|
402,212
|
|
$
|
654,499
|
|
$
|
715,923
|
|
$
|
613,423
|
|
$
|
523,351
|
|
$
|
407,413
|
|
-
(a)
-
Unaudited.
-
(b)
-
The
C$ amounts were converted using the average exchange rates for the applicable reporting periods.
-
(c)
-
Diluted
earnings (loss) per share is computed including dilutive potential shares, which include those issuable upon conversion of convertible debentures
and under our long term incentive plan. Because we reported a loss during the years ended December 31, 2010, 2009, 2007 and 2006, and for the six-month period ended June 30, 2010, the
effect of including potentially dilutive shares in the calculation during those periods is anti-dilutive. Please see the notes to our historical consolidated financial statements
incorporated by reference into this prospectus for information relating to the number of shares used in calculating basic and diluted earnings per share for the periods presented.
-
(d)
-
At
the time of our initial public offering, our publicly traded security was an income participating security, or an "IPS," each of which was comprised of
one common share and C$5.767 principal amount of 11% subordinated notes due 2016. On November 27, 2009, we converted from the IPS structure to a traditional common share structure. In
connection with the conversion, each IPS was exchanged for one new common share.
46
Table of Contents
SELECTED HISTORICAL CONSOLIDATED FINANCIAL INFORMATION OF CPILP
The following table presents selected consolidated financial information for CPILP. The selected historical financial data as of, and
for the years ended, December 31, 2010, 2009 and 2008 has been derived from CPILP's audited consolidated financial statements for those periods prepared under Canadian generally accepted
accounting principles and appearing elsewhere in this prospectus. Data as of, and for the years ended, December 31, 2010 and 2009 has be reconciled to U.S. generally accepted accounting
principles as noted below. The selected historical financial data as of, and for the years ended, December 31, 2007 and 2006 has been derived from the audited consolidated financial statements
of CPILP prepared under Canadian generally accepted accounting principles not appearing in this prospectus. The selected historical financial data as of, and for the six-month periods ended
June 30, 2011 and 2010 has been derived from CPILP's unaudited consolidated financial statements for those periods appearing elsewhere in this prospectus.
Data for all periods presented below is reported in Canadian dollars. You should read the following selected consolidated financial data together with CPILP's
consolidated financial
statements and the notes thereto included elsewhere in this prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Six Months
Ended
June 30,
|
|
(in thousands of Canadian dollars,
except per unit data)
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
|
2006
|
|
2011
(a)(b)
|
|
2010
(a)(b)
|
|
Revenue
|
|
$
|
532,377
|
|
$
|
586,491
|
|
$
|
499,267
|
|
$
|
549,872
|
|
$
|
326,900
|
|
$
|
261,524
|
|
$
|
241,453
|
|
Depreciation, amortization and accretion
|
|
$
|
98,227
|
|
$
|
93,249
|
|
$
|
88,313
|
|
$
|
85,553
|
|
$
|
65,200
|
|
$
|
45,461
|
|
$
|
47,826
|
|
Financial charges and other, net
|
|
$
|
40,179
|
|
$
|
46,462
|
|
$
|
94,836
|
|
$
|
8,574
|
|
$
|
42,200
|
|
$
|
21,457
|
|
$
|
21,384
|
|
Net income before tax and preferred share dividends
|
|
$
|
35,224
|
|
$
|
56,812
|
|
$
|
(91,918
|
)
|
$
|
108,953
|
|
$
|
67,400
|
|
$
|
18,741
|
|
$
|
4,705
|
|
Net income (loss) attributable to equity holders of CPILP
|
|
$
|
30,500
|
|
$
|
57,553
|
|
$
|
(67,893
|
)
|
$
|
30,816
|
|
$
|
62,121
|
|
$
|
10,529
|
|
$
|
8,410
|
|
Basic and diluted net income (loss) per unit, C$
|
|
$
|
0.55
|
|
$
|
1.07
|
|
$
|
(1.26
|
)
|
$
|
0.59
|
|
$
|
1.28
|
|
$
|
0.19
|
|
$
|
0.15
|
|
Distributions declared per unit, C$
|
|
$
|
1.76
|
|
$
|
1.95
|
|
$
|
2.52
|
|
$
|
2.52
|
|
$
|
2.52
|
|
$
|
0.88
|
|
$
|
0.88
|
|
Total assets
|
|
$
|
1,583,910
|
|
$
|
1,668,057
|
|
$
|
1,809,225
|
|
$
|
1,852,573
|
|
$
|
1,883,400
|
|
$
|
1,471,772
|
|
$
|
1,667,775
|
|
Total long-term liabilities
|
|
$
|
874,190
|
|
$
|
853,314
|
|
$
|
935,248
|
|
$
|
730,940
|
|
$
|
757,800
|
|
$
|
821,382
|
|
$
|
900,995
|
|
Operating margin
(c)
|
|
$
|
187,567
|
|
$
|
211,680
|
|
$
|
111,446
|
|
$
|
216,188
|
|
$
|
185,900
|
|
$
|
99,675
|
|
$
|
77,753
|
|
-
(a)
-
Unaudited.
-
(b)
-
Results
have been prepared using International Financial Reporting Standards.
-
(c)
-
Operating
margin is a non-GAAP financial measure. CPILP uses operating margin as a performance measure. Operating margin is not a defined financial
measures according to Canadian generally accepted accounting principles or International Financial Reporting Standards and does not have a standardized meaning prescribed by Canadian generally
accepted accounting principles or International Financial Reporting Standards. Therefore, operating margin may not be comparable to similar measures presented by other enterprises.
Under U.S. GAAP, the following differences are noted for the years indicated below:
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
(in thousands of Canadian dollars,
except per unit data)
|
|
2010
|
|
2009
|
|
Revenue
|
|
$
|
532,377
|
|
$
|
586,491
|
|
Depreciation, amortization and accretion
|
|
$
|
98,277
|
|
$
|
93,249
|
|
Financial charges and other, net
|
|
$
|
40,179
|
|
$
|
46,462
|
|
Net income before tax and preferred share dividends
|
|
$
|
39,179
|
|
$
|
54,753
|
|
Net income (loss) attributable to equity holders of CPILP
|
|
$
|
34,455
|
|
$
|
55,529
|
|
Basic and diluted net income (loss) per unit, C$
|
|
$
|
0.63
|
|
$
|
1.03
|
|
Distributions declared per unit, C$
|
|
$
|
1.76
|
|
$
|
1.95
|
|
Total assets
|
|
$
|
1,588,352
|
|
$
|
1,673,059
|
|
Total long-term liabilities
|
|
$
|
878,632
|
|
$
|
858,317
|
|
Operating margin
|
|
$
|
191,530
|
|
$
|
209,621
|
|
47
Table of Contents
UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS
The unaudited pro forma condensed combined consolidated statements of operations and balance sheet (which we refer to as the pro forma
financial statements) combine the historical consolidated financial statements of Atlantic Power and CPILP to illustrate the effect of the Plan of Arrangement. The pro forma financial statements were
based on and should be read in conjunction with the:
-
-
accompanying notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements;
-
-
consolidated financial statements of Atlantic Power for the year ended December 31, 2010 and for the six months
ended June 30, 2011 and the notes relating thereto, incorporated herein by reference; and
-
-
consolidated financial statements of CPILP for the year ended December 31, 2010 and for the six months ended
June 30, 2011 and the notes relating thereto, elsewhere in this prospectus.
The historical consolidated financial statements have been adjusted in the pro forma financial statements to give effect to pro forma events that are (1)
directly attributable to
the Plan of Arrangement, (2) factually supportable and (3) with respect to the unaudited pro forma condensed combined consolidated statements of operations (which we refer to as the pro
forma statements of operations), expected to have a continuing impact on the combined results. The pro forma statements of operations for the year ended December 31, 2010 and for the six months
ended June 30, 2011, give effect to the Plan of Arrangement as if it occurred on January 1, 2010. The Unaudited Pro Forma Condensed Combined Consolidated Balance Sheet (which we refer to
as the pro forma balance sheet) as of June 30, 2011, gives effect to the Plan of Arrangement as if it occurred on June 30, 2011.
As
described in the accompanying notes, the pro forma financial statements have been prepared using the acquisition method of accounting under existing United States generally accepted
accounting principles, or GAAP, and the regulations of the SEC. Atlantic Power has been treated as the acquirer in the transaction for accounting purposes. The acquisition accounting is dependent upon
certain valuations and other studies that have yet to commence or progress to a stage where there is sufficient information for a definitive measurement. Accordingly, the pro forma financial
statements are preliminary and have been made solely for the purpose of providing unaudited pro forma condensed combined consolidated financial information. Differences between these preliminary
estimates and the final acquisition accounting will occur and these differences could have a material impact on the accompanying pro forma financial statements and the combined company's future
results of operations and financial position.
The
pro forma financial statements have been presented for informational purposes only and are not necessarily indicative of what the combined company's results of operations and
financial position would have been had the transaction been completed on the dates indicated. In addition, the pro forma financial statements do not purport to project the future results of operations
or financial position of the combined company.
48
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2011
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic
Power
Historical
(unaudited)
(a)
|
|
CPILP
Historical
(unaudited)
(a)(1)
|
|
Pro Forma
Adjustments
(b)
|
|
Pro Forma
Combined
|
|
Project revenue:
|
|
$
|
106,923
|
|
$
|
257,148
|
|
$
|
(18,056
|
)
(d)
|
$
|
346,015
|
|
Project expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
31,384
|
|
|
145,152
|
|
|
(10,308
|
)
(d)
|
|
166,228
|
|
|
Operations and maintenance
|
|
|
18,873
|
|
|
16,997
|
|
|
(10,416
|
)
(d)
|
|
25,454
|
|
|
Depreciation and amortization
|
|
|
21,803
|
|
|
45,461
|
|
|
19,485
|
(c),(d),(e)
|
|
86,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72,060
|
|
|
207,610
|
|
|
(1,239
|
)
|
|
278,431
|
|
Project other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative instruments
|
|
|
(1,013
|
)
|
|
299
|
|
|
17
|
|
|
(697
|
)
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
3,273
|
|
|
|
|
|
|
|
|
3,273
|
|
|
Interest expense, net
|
|
|
(9,190
|
)
|
|
|
|
|
|
|
|
(9,190
|
)
|
|
Other expense, net
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,963
|
)
|
|
299
|
|
|
17
|
|
|
(6,647
|
)
|
|
|
|
|
|
|
|
|
|
|
Project income
|
|
|
27,900
|
|
|
49,837
|
|
|
(16,800
|
)
|
|
60,937
|
|
Administrative and other expenses (income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administration
|
|
|
8,725
|
|
|
14,016
|
|
|
(350
|
)
(d)
|
|
22,391
|
|
|
Interest expense, net
|
|
|
7,478
|
|
|
21,430
|
|
|
13,397
|
(c),(f)
|
|
42,305
|
|
|
Foreign exchange gain
|
|
|
(1,193
|
)
|
|
(4,351
|
)
|
|
(91
|
)
|
|
(5,635
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,010
|
|
|
31,095
|
|
|
12,956
|
|
|
59,061
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations before income taxes
|
|
|
12,890
|
|
|
18,742
|
|
|
(29,756
|
)
|
|
1,876
|
|
Income tax expense (benefit)
|
|
|
(6,161
|
)
|
|
1,159
|
|
|
(12,939
|
)
(e),(i)
|
|
(17,941
|
)
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
19,051
|
|
|
17,583
|
|
|
16,817
|
|
|
19,817
|
|
Net (loss) income attributable to noncontrolling interest
|
|
|
(271
|
)
|
|
7,054
|
|
|
169
|
|
|
6,952
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Atlantic Power Corporation/CPILP
|
|
$
|
19,322
|
|
$
|
10,529
|
|
$
|
(16,986
|
)
|
$
|
12,865
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share attributable to Atlantic Power Corporation shareholders / CPILP unitholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.28
|
|
$
|
0.19
|
|
$
|
(0.36
|
)
|
$
|
0.11
|
|
|
Diluted
|
|
$
|
0.28
|
|
$
|
0.19
|
|
$
|
(0.36
|
)
|
$
|
0.11
|
|
-
(1)
-
The
CPILP historical results are in recorded in Canadian dollars and are in accordance with IFRS. See Note 5(b) and (c) for an explanation of the
conversion to U.S. dollars and U.S. GAAP.
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.
49
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED STATEMENT OF OPERATIONS
For the Year
Ended December 31, 2010
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic
Power
Historical
(unaudited)
(a)
|
|
CPILP
Historical
(unaudited)
(a)(1)
|
|
Pro Forma
Adjustments
(b)
|
|
Pro Forma
Combined
|
|
Project revenue:
|
|
$
|
195,256
|
|
$
|
524,569
|
|
$
|
(49,840)
|
(d)
|
$
|
669,985
|
|
Project expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
65,553
|
|
|
219,218
|
|
|
(27,387)
|
(c),(d)
|
|
257,384
|
|
|
Operations and maintenance
|
|
|
31,237
|
|
|
114,164
|
|
|
(18,908)
|
(d)
|
|
126,493
|
|
|
Depreciation and amortization
|
|
|
40,387
|
|
|
98,277
|
|
|
28,604
|
(d),(e)
|
|
167,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137,177
|
|
|
431,659
|
|
|
(17,691
|
)
|
|
551,145
|
|
Project other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative instruments
|
|
|
(14,047
|
)
|
|
(11,421
|
)
|
|
468
|
|
|
(25,000
|
)
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
15,288
|
|
|
|
|
|
|
|
|
15,288
|
|
|
Interest expense, net
|
|
|
(17,660
|
)
|
|
|
|
|
|
|
|
(17,660
|
)
|
|
Other expense, net
|
|
|
219
|
|
|
|
|
|
|
|
|
219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,200
|
)
|
|
(11,421
|
)
|
|
468
|
|
|
(27,153
|
)
|
|
|
|
|
|
|
|
|
|
|
Project income
|
|
|
41,879
|
|
|
81,489
|
|
|
(31,681
|
)
|
|
91,687
|
|
Administrative and other expenses (income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administration
|
|
|
16,149
|
|
|
13,945
|
|
|
(2,292)
|
(d)
|
|
27,802
|
|
|
Interest expense, net
|
|
|
11,701
|
|
|
40,129
|
|
|
26,771
|
(d),(f)
|
|
78,601
|
|
|
Foreign exchange gain
|
|
|
(1,014
|
)
|
|
(7,808
|
)
|
|
234
|
(c)
|
|
(8,588
|
)
|
|
Other (income)
|
|
|
(26
|
)
|
|
|
|
|
(1,121)
|
(d)
|
|
(1,147
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,810
|
|
|
46,266
|
|
|
23,592
|
|
|
96,668
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations before income taxes
|
|
|
15,069
|
|
|
35,223
|
|
|
(55,273
|
)
|
|
(4,981
|
)
|
Income tax expense (benefit)
|
|
|
18,924
|
|
|
(9,384
|
)
|
|
(25,656)
|
(e),(i)
|
|
(16,116
|
)
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(3,855
|
)
|
|
44,607
|
|
|
(29,617
|
)
|
|
11,135
|
|
Net (loss) income attributable to noncontrolling interest
|
|
|
(103
|
)
|
|
14,107
|
|
|
(407
|
)
|
|
13,597
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Atlantic Power Corporation/CPILP
|
|
$
|
(3,752
|
)
|
$
|
30,500
|
|
$
|
(29,210
|
)
|
$
|
(2,462
|
)
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share attributable to Atlantic Power Corporation shareholders/CPILP unitholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.06
|
)
|
$
|
0.55
|
|
$
|
(0.51
|
)
|
$
|
(0.02
|
)
|
|
Diluted
|
|
$
|
(0.06
|
)
|
$
|
0.55
|
|
$
|
(0.51
|
)
|
$
|
(0.02
|
)
|
-
(1)
-
The
CPILP historical results are recorded in Canadian dollars and are in accordance with Canadian GAAP. See Note 5(b) and (c) for an explanation of
the conversion to U.S. dollars and U.S. GAAP.
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.
50
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED BALANCE SHEET
As of June 30, 2011
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic
Power
Historical
(unaudited)
(a)
|
|
CPILP
Historical
(unaudited)
(a)(1)
|
|
Pro Forma
Adjustments
(b)
|
|
Pro Forma
Combined
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
46,551
|
|
$
|
12,826
|
|
$
|
86,032
|
(d),(f)
|
$
|
145,409
|
|
|
Restricted cash
|
|
|
21,034
|
|
|
|
|
|
|
|
|
21,034
|
|
|
Accounts receivable
|
|
|
20,028
|
|
|
48,749
|
|
|
1,805
|
|
|
70,582
|
|
|
Note receivablerelated party
|
|
|
7,326
|
|
|
|
|
|
|
|
|
7,326
|
|
|
Current portion of derivative instruments asset
|
|
|
9,297
|
|
|
13,021
|
|
|
482
|
|
|
22,800
|
|
|
Prepayments, supplies, and other
|
|
|
8,451
|
|
|
18,143
|
|
|
672
|
|
|
27,266
|
|
|
Asset held for sale
|
|
|
|
|
|
130,613
|
|
|
(130,613
|
)
(d)
|
|
|
|
|
Refundable income taxes
|
|
|
1,611
|
|
|
|
|
|
|
|
|
1,611
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
114,298
|
|
|
223,352
|
|
|
(41,622
|
)
|
|
296,028
|
|
Property, plant, and equipment, net
|
|
|
308,051
|
|
|
835,881
|
|
|
204,252
|
(c),(e)
|
|
1,348,184
|
|
Transmission system rights
|
|
|
184,208
|
|
|
|
|
|
|
|
|
184,208
|
|
Equity investments in unconsolidated affiliates
|
|
|
276,962
|
|
|
31,344
|
|
|
1,160
|
|
|
309,466
|
|
Other intangible assets, net
|
|
|
77,425
|
|
|
270,441
|
|
|
363,179
|
(c),(e)
|
|
711,045
|
|
Goodwill
|
|
|
12,453
|
|
|
19,689
|
|
|
421,639
|
(c),(h)
|
|
453,781
|
|
Derivative instruments asset
|
|
|
18,865
|
|
|
32,710
|
|
|
1,211
|
|
|
52,786
|
|
Deferred income taxes
|
|
|
|
|
|
20,337
|
|
|
19,459
|
(c),(i)
|
|
39,796
|
|
Other assets
|
|
|
16,718
|
|
|
38,018
|
|
|
6,448
|
(c),(f)
|
|
61,184
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,008,980
|
|
$
|
1,471,772
|
|
$
|
975,726
|
|
$
|
3,456,478
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
16,333
|
|
$
|
59,423
|
|
$
|
27,557
|
(c),(g)
|
$
|
103,313
|
|
|
Liabilities held for sale
|
|
|
|
|
|
15,367
|
|
|
(15,367
|
)
(d)
|
|
|
|
|
Current portion of long-term debt
|
|
|
21,962
|
|
|
|
|
|
|
|
|
21,962
|
|
|
Current portion of derivative instruments liability
|
|
|
7,410
|
|
|
23,138
|
|
|
857
|
|
|
31,405
|
|
|
Interest payable on convertible debentures
|
|
|
1,948
|
|
|
|
|
|
|
|
|
1,948
|
|
|
Dividends payable
|
|
|
6,490
|
|
|
|
|
|
|
|
|
6,490
|
|
|
Other current liabilities
|
|
|
7
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
54,150
|
|
|
97,928
|
|
|
13,047
|
|
|
165,125
|
|
Long-term debt
|
|
|
263,111
|
|
|
675,465
|
|
|
454,420
|
(c),(f)
|
|
1,392,996
|
|
Convertible debentures
|
|
|
209,703
|
|
|
|
|
|
|
|
|
209,703
|
|
Derivative instruments liability
|
|
|
24,822
|
|
|
79,686
|
|
|
2,950
|
|
|
107,458
|
|
Deferred income taxes
|
|
|
23,594
|
|
|
17,200
|
|
|
150,812
|
(c),(i)
|
|
191,606
|
|
Other non-current liabilities
|
|
|
2,121
|
|
|
49,031
|
|
|
(21,082)
|
(c)
|
|
30,070
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares
|
|
|
644,001
|
|
|
332,301
|
|
|
345,079
|
(f),(j)
|
|
1,321,381
|
|
|
Accumulated other comprehensive loss
|
|
|
24
|
|
|
|
|
|
|
|
|
24
|
|
|
Retained deficit
|
|
|
(215,782
|
)
|
|
|
|
|
23,048
|
(g),(i)
|
|
(192,734
|
)
|
|
|
|
|
|
|
|
|
|
|
Total shareholders' equity
|
|
|
428,243
|
|
|
332,301
|
|
|
368,127
|
|
|
1,128,671
|
|
|
|
|
|
|
|
|
|
|
|
Noncontrolling interest
|
|
|
3,236
|
|
|
220,161
|
|
|
7,452
|
(c)
|
|
230,849
|
|
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
431,479
|
|
|
552,462
|
|
|
375,579
|
|
|
1,359,520
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
1,008,980
|
|
$
|
1,471,772
|
|
$
|
975,726
|
|
$
|
3,456,478
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
The
CPILP historical results are in recorded in Canadian dollars and are in accordance with IFRS. See Note 5(b) and (c) for an explanation of the
conversion to U.S. dollars and U.S. GAAP.
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.
51
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
NOTES TO THE UNAUDITED PRO FORMA CONDENSED
COMBINED CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Description of the Transaction
On June 20, 2011, Atlantic Power, CPILP, CPILP's general partner and CPI Investments Inc. entered into the Arrangement Agreement, which provides that Atlantic
Power will acquire,
directly or indirectly, all of the issued and outstanding CPILP units pursuant to a court-approved statutory Plan of Arrangement under the CBCA. Under the terms of the Plan of Arrangement, CPILP
unitholders will be permitted to exchange each of their CPILP units for, at their election, C$19.40 in cash or 1.3 Atlantic Power common shares. All cash elections will be subject to proration if
total cash elections exceed approximately C$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power
common shares.
Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power Corporation, for
approximately
C$121.4 million. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power Corporation and CPILP and certain subsidiaries
of CPILP will be terminated (or assigned to Atlantic Power) in consideration of a payment of C$10 million. Atlantic Power will assume the management of CPILP and enter into a transitional
services agreement with
Capital Power Corporation for a term of up to 12 months following closing, which will facilitate the integration of CPILP into Atlantic Power.
Note 2. Basis of Pro Forma Presentation
The pro forma financial statements were derived from historical consolidated financial statements of Atlantic Power and CPILP. Certain reclassifications have been
made to the historical
financial statements of CPILP to conform with Atlantic Power's presentation. This resulted in income statement adjustments to operating revenues, operating expenses, other income and deductions and
balance sheet adjustments to current assets, long term assets, current liabilities and other long term liabilities.
The
historical consolidated financial statements have been adjusted in the pro forma financial statements to give effect to pro forma events that are (1) directly attributable to
the transaction, (2) factually supportable, and (3) with respect to the pro forma statement of operations, expected to have a continuing impact on the combined results. The following
matters have not been reflected in the pro forma financial statements as they do not meet the aforementioned criteria.
-
-
Cost savings (or associated costs to achieve such savings) from operating efficiencies, synergies or other restructuring
that could result from the transaction with CPILP. The timing and effect of actions associated with integration are currently uncertain.
-
-
A fair value adjustment for CPILP's pension and other postretirement benefit obligations. Atlantic Power management
believes the actuarial assumptions and methods used to measure CPILP's obligations and costs for financial accounting purposes for 2010 and 2011 are appropriate in the circumstances. The final fair
value determination of the pension and postretirement benefit obligations may differ materially, largely due to potential changes in discount rates, return on plan assets up to the date of completion
of the transaction and the conforming of certain Atlantic Power and CPILP assumptions surrounding the determination of these obligations.
52
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
NOTES TO THE UNAUDITED PRO FORMA CONDENSED
COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 2. Basis of Pro Forma Presentation (Continued)
The
pro forma financial statements were prepared using the acquisition method of accounting under GAAP and the regulations of the SEC. Atlantic Power has been treated as the acquirer in
the transaction for accounting purposes. Acquisition accounting requires, among other things, that most assets acquired and liabilities assumed be recognized at fair value as of the acquisition date.
In addition, acquisition accounting establishes that the consideration transferred be measured at the closing date of the transaction at the then-current market price. Since acquisition
accounting is dependent upon certain valuations and other studies that have yet to commence or progress to a stage where there is sufficient information for a definitive measurement, the pro forma
financial statements are preliminary and have been prepared solely for the purpose of providing unaudited pro forma condensed combined consolidated financial information. Differences between these
preliminary estimates and the final acquisition accounting will occur and these differences could have a material impact on the accompanying pro forma financial statements and the combined company's
future results of operations and financial position.
Note 3. Significant Accounting Policies
Based upon Atlantic Power's initial review of CPILP's summary of significant accounting policies, as disclosed in the CPILP consolidated historical financial
statements elsewhere in
this prospectus, as well as on preliminary discussions with CPILP's management, the pro forma condensed combined
consolidated financial statements assume there will be significant adjustments necessary to conform CPILP's accounting policies under International Financial Reporting Standards ("IFRS") to Atlantic
Power's accounting policies under U.S. GAAP. Upon completion of the transaction and a more comprehensive comparison and assessment, differences may be identified that would necessitate changes
to CPILP's future accounting policies and such changes could result in material differences in future reported results of operations and financial position for CPILP as compared to historically
reported amounts.
53
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
NOTES TO THE UNAUDITED PRO FORMA CONDENSED
COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 4. Estimated Purchase Price and Preliminary Purchase Price Allocation
Atlantic Power is proposing to acquire all of the outstanding units of CPILP for a combination of either C$19.40 in cash or 1.3 Atlantic Power shares per CPILP unit.
The purchase price
for the business combination is estimated as follows (in thousands):
|
|
|
|
|
|
Fair value of consideration transferred:
|
|
|
|
|
|
Cash
|
|
$
|
525,689
|
|
|
Equity
|
|
|
487,480
|
|
|
|
|
|
Total estimated purchase price
|
|
|
1,013,169
|
|
Preliminary purchase price allocation
|
|
|
|
|
|
Working capital
|
|
$
|
10,932
|
|
|
Property, plant and equipment
|
|
|
1,040,133
|
|
|
Intangibles
|
|
|
633,620
|
|
|
Other long-term assets
|
|
|
129,883
|
|
|
Long-term debt
|
|
|
(704,885
|
)
|
|
Other long-term liabilities
|
|
|
(110,585
|
)
|
|
Deferred tax liability
|
|
|
(199,644
|
)
|
|
|
|
|
|
Total identifiable net assets
|
|
|
799,454
|
|
|
Noncontrolling interest
|
|
|
(227,613
|
)
|
|
Goodwill
|
|
|
441,328
|
|
|
|
|
|
Total estimated purchase price
|
|
|
1,013,169
|
|
The preliminary purchase price was computed using CPILP's outstanding units as of June 30, 2011, adjusted for the exchange ratio. The
preliminary purchase price reflects the market value of Atlantic Power's common shares to be issued in connection with the transaction based on the closing price of Atlantic Power's common shares on
the NYSE on June 30, 2011.
The
allocation of the preliminary purchase price to the fair values of assets acquired and liabilities assumed includes pro forma adjustments to reflect the fair values of CPILP's
assets and liabilities at the time of the completion of the transaction. The final allocation of the purchase price could differ materially from the preliminary allocation used for the Unaudited Pro
Forma Condensed Combined Consolidated Balance Sheet primarily because power market prices, interest rates and other valuation variables will fluctuate over time and be different at the time of
completion of the transaction compared to the amounts assumed in the pro forma adjustments.
Note 5. Pro Forma Adjustments to Financial Statements
The pro forma adjustments included in the pro forma financial statements are as follows:
-
(a)
-
Atlantic Power and CPILP historical presentation
Based on the amounts reported in the
consolidated statements of operations and balance sheets of Atlantic Power and CPILP for the year ended December 31, 2010 and for the six months ended and as of June 30, 2011. Certain
financial statement line items included in CPILP's historical presentation have been reclassified to corresponding line items included in Atlantic Power's historical presentation. These
reclassifications had no impact on the historical operating income, net income from continuing operations or partners' equity reported
54
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
NOTES TO THE UNAUDITED PRO FORMA CONDENSED
COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 5. Pro Forma Adjustments to Financial Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
Six months ended
June 30, 2011
|
|
Year ended
December 31, 2010
|
|
Project revenue
|
|
$
|
24,210
|
|
$
|
34,726
|
|
Project expenses
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
13,787
|
|
|
24,816
|
|
|
Project operations and maintenance
|
|
|
10,843
|
|
|
15,916
|
|
|
Depreciation and amortization
|
|
|
4,539
|
|
|
8,936
|
|
|
|
|
|
|
|
|
|
|
29,169
|
|
|
49,668
|
|
|
|
|
|
|
|
Project loss
|
|
|
(4,959
|
)
|
|
(14,942
|
)
|
Administration
|
|
|
1,032
|
|
|
3,438
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(5,991
|
)
|
$
|
(18,380
|
)
|
|
|
|
|
|
|
55
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
NOTES TO THE UNAUDITED PRO FORMA CONDENSED
COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 5. Pro Forma Adjustments to Financial Statements (Continued)
|
|
|
|
|
|
|
As of
June 30, 2011
|
|
Assets held for sale
|
|
$
|
130,613
|
|
Liabilities held for sale
|
|
|
(15,367
|
)
|
|
|
|
|
Retained earnings
|
|
$
|
115,246
|
|
|
|
|
|
-
(e)
-
Power Purchase Agreements and Plants
The pro forma balance sheet includes pro forma adjustments
to reflect the fair value of CPILP's power contracts (including those designated as "normal purchases normal sales") recorded to intangible assets and additional fair value of plants in the amounts of
$353.3 million and $136.5 million, respectively. The pro forma statements of operations include pro forma adjustments to reflect the increase in expense resulting from the amortization
of the valuation adjustment related to CPILP's intangibles and the depreciation of the plants of $21.9 million and $40.4 million for the six months ended June 30, 2011 and the
year ended December 31, 2010, respectively. The pro forma estimated annual amortization for the power contracts is $39.3 million based on the timing and fair value of the underlying
contracts. This estimate is preliminary, subject to change and could vary materially from the actual adjustments at the time the transaction is completed, driven by various factors including changes
in energy commodity prices and fuel prices.
-
(f)
-
Debt and Equity issuance
The pro forma balance sheet includes a pro forma adjustment of
$425.0 million to reflect Atlantic Power's proceeds from third-party debt and proceeds of $200.0 million from the issuance of 13.1 million common shares. The assumptions for the
$425.0 million debt facility include a term of 5 years at 6.00% per annum. The proceeds from the debt and equity offering will be used to pay the CPILP unitholders the cash portion of
the purchase price. The debt and equity amounts are offset by $11.7 million and $10.1 million of transaction costs classified as deferred financing costs and a reduction of common stock,
respectively. The pro forma statements of operations include pro forma adjustments to reflect the net incremental interest expense resulting from the new debt and amortization of deferred financing
costs of $14.0 million and $27.8 million for the six months ended June 30, 2011 and the year ended December 31, 2010, respectively.
-
(g)
-
Transaction Costs
The pro forma balance sheet includes a pro forma adjustment to accounts
payable and accrued liabilities to reflect estimated transaction costs of $25.7 million. The transaction costs have been excluded from the pro forma statements of operations as they reflect
non-recurring charges not expected to have a continuing impact on the combined results.
-
(h)
-
Goodwill
The pro forma balance sheet includes a preliminary estimate of the allocation of the
excess of the purchase price paid over the fair value of CPILP's identifiable assets acquired and liabilities assumed. The estimated purchase price of the transaction, based on the closing price of
Atlantic Power's common shares on the NYSE on June 30, 2011, is $1,013.2 million, and the excess purchase price over the fair value of the identifiable net assets acquired is
$441.3 million.
56
Table of Contents
ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
NOTES TO THE UNAUDITED PRO FORMA CONDENSED
COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 5. Pro Forma Adjustments to Financial Statements (Continued)
-
(i)
-
Deferred Tax Assets and Liabilities:
The pro forma balance sheet includes a preliminary estimated deferred
tax impact of $40.6 million to deferred tax liabilities. This adjustment reflect the estimated deferred tax impacts of the acquisition on the balance sheet, primarily related to the reversal of
the Atlantic Power's valuation allowance associated with its Canadian accumulated net operating losses as of June 30, 2011. For purposes of the unaudited pro forma condensed combined
consolidated financial statements, deferred taxes are provided at the Canadian enacted statutory rate of 25%. This rate does not reflect Atlantic Power's effective tax rate, which includes other tax
items, such as non-deductible items, as well as other tax charges or benefits, and does not take into account any historical or possible future tax events that may impact the combined
company. When the transaction is completed and additional information becomes available, it is likely the applicable income tax rate will change.
-
-
The
$159,874 deferred tax liability adjustment reflects the estimated deferred tax liability impact of the acquisition on the balance sheet,
primarily related to estimated fair value adjustments for acquired tangible and intangible assets. For purposes of the unaudited pro forma condensed combined consolidated financial information,
deferred taxes are provided at Atlantic Power's deferred tax rate of 33%, which includes the U.S. federal statutory income tax rate plus the Canadian statutory income tax rate. This rate does not
reflect Atlantic Power's effective tax rate, which includes other tax items, such as state taxes, as well as other tax charges or benefits and does not take into account any historical or possible
future tax events that may impact the combined company. When the transaction is completed and additional information becomes available, it is likely the applicable income tax rate will change.
-
(j)
-
Common Shares outstanding
Reflects the elimination of the CPILP units offset by issuance of
31.5 million Atlantic Power common shares as part of purchase price and the issuance of 13.1 million Atlantic Power common shares in new equity. The pro forma weighted average number of
basic shares outstanding is calculated by adding these additional share issuances to Atlantic Power's weighted average number of basic common shares outstanding for the six months ended
June 30, 2011 or the year ended December 31, 2010. The following table illustrates these computations (in thousands):
|
|
|
|
|
|
|
|
|
(in thousands of shares)
|
|
Six months ended
June 30, 2011
|
|
Year ended
December 31, 2010
|
|
Atlantic Power's basic shares outstanding
|
|
|
68,116
|
|
|
61,706
|
|
Additional shares issued to CPILP unit holders
|
|
|
31,500
|
|
|
31,500
|
|
Additional shares on new equity issuance
|
|
|
13,141
|
|
|
13,141
|
|
|
|
|
|
|
|
Basic shares outstanding
|
|
|
112,757
|
|
|
106,347
|
|
Dilutive potential shares
|
|
|
|
|
|
|
|
|
Convertible debentures
|
|
|
14,430
|
|
|
12,339
|
|
|
LTIP notional units
|
|
|
427
|
|
|
542
|
|
|
|
|
|
|
|
Potentially dilutive shares
|
|
|
127,614
|
|
|
119,228
|
|
Potentially dilutive shares from convertible debentures have been excluded from fully dilutive shares for the six months ended June 30,
2011 and for the year ended December 31, 2010 because their impact would be anti-dilutive.
57
Table of Contents
ACQUISITION OF CPILP
The Arrangement Agreement and Plan of Arrangement
On June 20, 2011, we entered into an Arrangement Agreement, as amended effective July 25, 2011, with CPILP, a publicly
traded Canadian limited partnership, CPILP's general partner and CPI Investments Inc., a holding company that owns 100% of the shares of the general partner and, together with the CPILP units
held by the general partner, 29.18% of the outstanding CPILP units. An affiliate of Capital Power Corporation, a Canadian public company, holds a 49% voting interest and a 100% economic interest in
CPI Investments Inc. and EPCOR Utilities Inc. holds the other 51% voting interest. The Arrangement Agreement provides that we will acquire, directly or indirectly, all of the issued and
outstanding CPILP units pursuant to a plan of arrangement under the Canada Business Corporations Act. Under the terms of the Plan of Arrangement, CPILP unitholders will be permitted to exchange each
of their CPILP units for, at their election, C$19.40 in
cash or 1.3 Atlantic Power common shares. All cash elections will be subject to proration if total cash elections exceed approximately C$506.5 million and all share elections will be subject to
proration if total share elections exceed approximately 31.5 million Atlantic Power common shares.
Under
the Plan of Arrangement, we will indirectly acquire the 16,513,504 CPILP units held by CPI Investments Inc. and CPILP's general partner through the acquisition of all of
the outstanding shares of CPI Investments Inc. on effectively the same basis as the acquisition of CPILP units under the Plan of Arrangement.
Atlantic Power shareholders will continue to hold our existing common shares after the Plan of Arrangement. Based on the number of Atlantic Power common shares
expected to be
outstanding immediately prior to the effective date of the Plan of Arrangement, and excluding the common shares to be sold in this offering, we estimate that upon completion of the Plan of Arrangement
current Atlantic Power shareholders will own approximately 70% of the combined company and former CPILP unitholders will own approximately 30% of the combined company, in each case on a fully-diluted
basis.
Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power Corporation, a
publicly traded
Canadian company, for approximately C$121.4 million. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power
Corporation and CPILP and certain of its subsidiaries will be terminated (or assigned to Atlantic Power) in consideration of a payment of C$10.0 million. Atlantic Power or its subsidiaries will
assume the management of CPILP and intends to enter into a transitional services agreement with Capital Power Corporation for a term of up to 12 months following the completion of the Plan of
Arrangement, which will facilitate the integration of CPILP into Atlantic Power.
The
Arrangement Agreement contains customary representations, warranties and covenants. Among these covenants, CPILP and its affiliates have each agreed not to solicit alternative
transactions, except that CPILP may respond to an alternative transaction proposal that constitutes, or would reasonably be expected to lead to, a superior proposal. In addition, we or CPILP may be
required to pay a C$35.0 million fee if the Arrangement Agreement is terminated in certain circumstances.
Completion of the Plan of Arrangement is conditioned upon the receipt of certain governmental authorizations, consents, orders or other approvals, including but not
limited to approval
under the
Investment Canada Act
, the
Competition Act
(Canada), the
Hart-Scott-Rodino Antitrust Improvements Act of
1976
, as amended (United States) and the
United States Federal Power
Act
. The Plan of Arrangement must also be approved by the Court of Queen's Bench of Alberta and both our shareholders and CPILP's unitholders. We currently expect to complete
the Plan of Arrangement in the fourth quarter of 2011, subject to receipt of required shareholder/unitholder, court and regulatory approvals and the satisfaction or waiver of the financing and other
conditions contained in the
58
Table of Contents
Arrangement Agreement. However, we cannot be certain that our acquisition of CPILP will be completed. See "Risk factorsRisks related to the Plan of Arrangement."
A
copy of the Arrangement Agreement, including the Plan of Arrangement, is included as an exhibit to our Current Report on Form 8-K filed with the Securities and
Exchange Commission on June 24, 2011, which is incorporated by reference into this prospectus. The foregoing description of the proposed transaction and the Arrangement Agreement does not
purport to be complete and is qualified in its entirety by reference to such exhibit.
The
terms of the Arrangement Agreement are the result of arm's length negotiation between the parties and their respective advisors. Effective July 25, 2011, the Arrangement
Agreement was amended to account for our receiving the written commitment of a Canadian chartered bank and another financial institution to structure, arrange, underwrite and syndicate a senior
secured credit facility in the amount of $625 million, the termination of a commitment regarding certain bridge loans that we had entered into at the time of entering into the Arrangement
Agreement and the correction of certain other references.
Reasons for the Arrangement Agreement and Plan of Arrangement
At a meeting held on June 19, 2011, our board of directors unanimously determined that the Arrangement Agreement and the
transactions contemplated thereby, including the issuance of Atlantic Power common shares to CPILP unitholders necessary to complete the Plan of Arrangement, are in the best interests of Atlantic
Power and are fair to its stakeholders. In reaching these determinations, our board of directors consulted with our management and legal, financial and other advisors, and also considered numerous
factors, including the strategic and financial benefits of the Plan of Arrangement and other factors, which our board of directors viewed as supporting its decision.
The strategic benefits that our board of directors believes should result from the combination of Atlantic Power and CPILP include, among other things, the
following:
-
-
Atlantic Power will become a leading publicly traded power generation and infrastructure company, with a larger and more
diversified portfolio of contracted power generation assets in the United States and Canada;
-
-
the transaction will combine Atlantic Power's proven management team with CPILP's highly qualified operations,
maintenance, commercial management, accounting, human resources, legal and other personnel;
-
-
Atlantic Power's market capitalization and enterprise value are expected to increase significantly, which is expected to
add liquidity and enhance access to capital to fuel the long term growth of Atlantic Power's asset base throughout North America;
-
-
the combination will expand and diversify Atlantic Power's asset portfolio to include projects in Canada and regions of
the United States where we do not currently have a presence;
-
-
our enhanced geographic diversification is anticipated to lead to additional growth opportunities in those regions in
which we did not previously operate; and
-
-
the transaction will further diversify the fuel types used by Atlantic Power's projects to include additional hydro,
biomass and natural gas.
Our board of directors also believes that the combination of Atlantic Power and CPILP will result in significant financial benefits to Atlantic Power's shareholders.
These financial
benefits include:
-
-
upon completion of the Plan of Arrangement, our board of directors anticipates being able to increase dividends by 5%,
from C$1.094 to C$1.15 per share on an annual basis;
-
-
the transaction is expected to strengthen Atlantic Power's dividend sustainability for the foreseeable future with
immediate accretion to cash available for distribution;
59
Table of Contents
-
-
the transaction is expected to result in a significant improvement in Atlantic Power's dividend payout ratio starting in
2012;
-
-
the transaction extends Atlantic Power's average PPA term from 8.8 to 9.1 years and enhances the credit quality of
Atlantic Power's power off-takers; and
-
-
following completion of the Plan of Arrangement, we expect to benefit from cost savings attributable to synergies from
combining the two entities and eliminating the public company reporting costs for CPILP.
Financing Transactions
We intend to use the net proceeds from this offering to pay a portion of the cash consideration required under the Plan of Arrangement
and related fees and expenses. We plan to fund the remainder of the cash consideration payable by us under the Plan of Arrangement, including related fees and expenses, with the net proceeds from a
senior unsecured notes offering and/or drawings under a $625 million senior secured credit facility, each as described below.
Under a separate offering memorandum or otherwise, we may offer senior unsecured notes to fund a portion of the cash consideration payable by us under the Plan of
Arrangement, pursuant
to Rule 144A and Regulation S under the Securities Act. The completion of this offering of common shares is not subject to the completion of an offering of senior unsecured notes and the
completion of an offering of senior unsecured notes will not be subject to the completion of this offering. No assurance can be given that a notes offering will be commenced or completed or, if
completed, as to the final terms of the notes offering.
We do not intend to register any notes under the Securities Act or the securities laws of any other jurisdiction, and notes may not be offered or sold in the United
States absent
registration or an applicable exemption from registration requirements. Any such notes will be offered only to qualified institutional buyers in the United States pursuant to Rule 144A under
the Securities Act and outside the United States pursuant to Regulation S under the Securities Act. This description and other information regarding a possible notes offering is included in
this prospectus solely for information purposes. Nothing in this prospectus should be construed as an offer to sell, or the solicitation of an offer to buy, any notes.
We
have received the written commitment of a Canadian chartered bank and another financial institution to structure, arrange, underwrite and syndicate a senior secured credit facility
in the amount of $625 million in order to finance the cash consideration payable by us under the Plan of Arrangement. Funding under this facility is subject to certain conditions, including,
without limitation, that there shall not have occurred a material adverse effect with respect to Atlantic Power, CPILP, CPI Income Services Ltd. and CPI Investments Inc. taken as a whole.
About Atlantic Power
We own and operate a diverse fleet of power generation and infrastructure assets in the United States. Our generation projects sell
electricity to utilities and other large commercial customers under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Our power
generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 MW, in which our ownership interest is approximately 871 MW. Our current portfolio consists
of interests in 12 operational power generation projects across nine states, one biomass project under construction in Georgia, and a 500 kilovolt 84-mile electric transmission line
located in California. We also own a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development. Six of our projects are wholly-owned subsidiaries:
Lake Cogen, Ltd., Pasco Cogen, Ltd., Auburndale Power Partners, L.P., Cadillac Renewable
60
Table of Contents
Energy, LLC, Piedmont Green Power, LLC (98%)and Atlantic Path 15, LLC. Our common shares trade on the NYSE under the symbol "AT" and on the TSX under the symbol "ATP."
About CPILP
CPILP's primary business is the ownership and operation of power plants in Canada and the United States, which generate electricity
and steam, from which it derives its earnings and cash flows. CPILP's generation projects sell electricity to utilities and other large commercial customers under long-term PPAs, which
seek to minimize exposure to changes in commodity prices. At present, CPILP's portfolio consists of 19 wholly-owned power generation assets located in both Canada (in the provinces of British Columbia
and Ontario) and the United States (in the states of California, Colorado, Illinois, New Jersey, New York and North Carolina), a 50.15% interest in a power generation asset in Washington State, and a
14.3% common equity interest in Primary Energy Recycling Holdings LLC. CPILP's assets have a total net generating capacity of 1,400 MW and more than four million pounds per hour of thermal
energy. The CPILP units trade on the TSX under the symbol "CPA.UN."
CPILP's
power projects generate electricity and steam from a combination of natural gas, waste heat, wood waste, water flow, coal and tire-derived fuel. CPILP's Canadian
operations consist of:
-
-
four natural gas-fired plants with a combined generating capacity of 163 MW;
-
-
two biomass, wood waste plants with a combined generating capacity of 101 MW; and
-
-
two hydroelectric facilities with a combined generating capacity of 56 MW.
CPILP's
United States operations consist of:
-
-
one simple-cycle natural gas-fired power plant with a generating capacity of 300 MW;
-
-
one combined-cycle natural gas-fired power plant with a generating capacity of 125 MW;
-
-
seven natural gas-fired combined heat and power ("CHP") plants, three of which can also use distillate fuel,
with a combined generating capacity of 440 MW and steam generating capacity of 2,537 mlbs/hr; and
-
-
a hydroelectric plant with a total generating capacity of 60 MW.
Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power Corporation, a
publicly traded
Canadian company, for approximately C$121.4 million.
61
Table of Contents
The following table summarizes each of CPILP's power plants in each of Canada and the United States, and their respective operating characteristics (other than the
Roxboro and Southport
facilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project Name
|
|
Location
|
|
Type
|
|
Net
MW
|
|
Economic
Interest
|
|
Primary
Electric
Purchaser
|
|
Power
Contract
Expiry
|
|
Customer
S&P
Credit
Rating
|
Calstock
|
|
Ontario
|
|
Biomass
|
|
|
35
|
|
|
100
|
%
|
Ontario Electricity Financial Corporation
|
|
|
2020
|
|
AA-
|
Kapuskasing
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100
|
%
|
Ontario Electricity Financial Corporation
|
|
|
2017
|
|
AA-
|
Nipigon
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100
|
%
|
Ontario Electricity Financial Corporation
|
|
|
2012
|
(1)
|
AA-
|
North Bay
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100
|
%
|
Ontario Electricity Financial Corporation
|
|
|
2017
|
|
AA-
|
Tunis
|
|
Ontario
|
|
Natural Gas
|
|
|
43
|
|
|
100
|
%
|
Ontario Electricity Financial Corporation
|
|
|
2014
|
|
AA-
|
Mamquam
|
|
British Columbia
|
|
Hydro
|
|
|
50
|
|
|
100
|
%
|
British Columbia Hydro and Power Authority
|
|
|
2027
|
(2)
|
AAA
|
Moresby Lake
|
|
British Columbia
|
|
Hydro
|
|
|
6
|
|
|
100
|
%
|
British Columbia Hydro and Power Authority
|
|
|
2022
|
|
AAA
|
Williams Lake
|
|
British Columbia
|
|
Biomass
|
|
|
66
|
|
|
100
|
%
|
British Columbia Hydro and Power Authority
|
|
|
2018
|
(3)
|
AAA
|
Frederickson
|
|
Washington
|
|
Natural Gas
|
|
|
125
|
(4)
|
|
50.15
|
%
(5)
|
3 Public Utility Districts
(6)
|
|
|
2022
|
|
A to A+
|
Greeley
|
|
Colorado
|
|
Natural Gas
|
|
|
72
|
|
|
100
|
%
|
Public Service Company of Colorado
|
|
|
2013
|
|
A-
|
Manchief
|
|
Colorado
|
|
Natural Gas
|
|
|
300
|
|
|
100
|
%
|
Public Service Company of Colorado
|
|
|
2022
|
(7)
|
A-
|
Naval Station
|
|
California
|
|
Natural Gas
|
|
|
47
|
|
|
100
|
%
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
Naval Training Centre
|
|
California
|
|
Natural Gas
|
|
|
25
|
|
|
100
|
%
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
North Island
|
|
California
|
|
Natural Gas
|
|
|
40
|
|
|
100
|
%
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
Oxnard
|
|
California
|
|
Natural Gas
|
|
|
49
|
|
|
100
|
%
|
Southern California Edison
|
|
|
2020
|
|
BBB+
|
Curtis Palmer
|
|
New York
|
|
Hydro
|
|
|
60
|
|
|
100
|
%
|
Niagara Mohawk
Power Corp.
|
|
|
2027
|
|
A-
|
Kenilworth
|
|
New Jersey
|
|
Natural Gas
|
|
|
30
|
|
|
100
|
%
|
Schering-Plough Corporation
|
|
|
2012
(8)
|
|
AA
|
Morris
|
|
Illinois
|
|
Natural Gas
|
|
|
177
|
|
|
100
|
%
|
Equistar
Chemicals, LP
(9)
|
|
|
2023
|
(10)
|
BB-
|
-
(1)
-
CPILP
has the option to extend the PPA for ten years at existing terms.
-
(2)
-
BC
Hydro has an option exercisable in 2021 and every five years thereafter to buy the Mamquam facility or extend the contract.
-
(3)
-
BC
Hydro has an option to extend the agreement by up to 10 years, on the basis of two five-year term extensions.
-
(4)
-
In
addition, there is 10 MW dust firing.
-
(5)
-
Represents
CPILP's 50.15% ownership interest in Frederickson. Puget Sound Energy, Inc. owns the remaining 49.85% ownership interest.
-
(6)
-
PUDs
are: Benton (A+), Franklin (A) and Grays Harbor (A).
-
(7)
-
Public
Service Company of Colorado has an option during the latter part of the extension term to purchase the Manchief facility.
-
(8)
-
Pursuant
to the ESA, Schering-Plough Corporation has the option to purchase the Kenilworth facility. The ESA can be extended automatically for
successive five year periods.
62
Table of Contents
-
(9)
-
100 MW
is sold forward through April 2014 into the Pennsylvania, New Jersey, and Maryland market.
-
(10)
-
Equistar
Chemicals, LP has a right to purchase the Morris facility at fair market value at the end of 2013, 2018 and 2023.
Power Purchase Agreements
Canada
Ontario
The
Ontario Electricity Financial Corporation ("OEFC") is the sole purchaser of power from CPILP's five Ontario power plants. The power is purchased under
long-term power purchase agreements. The earliest expiry date of these agreements is at the Nipigon plant where the initial term of the PPA expires in 2012 and the longest expiry date is
at the Calstock plant where the PPA expires in 2020. CPILP reached an agreement with the OEFC to amend the Tunis PPA effective January 16, 2010 that allows CPILP to flow-through
natural gas and transportation costs in excess of benchmark amounts to OEFC and extends OEFC the right to curtail the plant during summer off-peak periods through the remaining term of the
PPA in 2014.
Williams
Lake
The
Williams Lake power plant sells power to the British Columbia Hydro and Power Authority ("BC Hydro") under a 25-year PPA with the initial term
expiring in 2018. BC Hydro has an option to extend the agreement by up to 10 years, on the basis of two five-year term extensions.
The Williams Lake Electricity Purchase Agreement ("EPA") contains two pricing tranches: a firm energy tranche, representing approximately 82% of total energy
produced; and a surplus
energy tranche, representing approximately 18% of total energy produced. The firm energy tranche price consists of a fixed energy component, an operations and maintenance component (adjusted annually
for average weekly earnings in British Columbia), and a reimbursable cost component. The surplus energy tranche price is adjusted annually for changes in the Dow Jones California Oregon Border index.
The year end surplus energy tranche price would have been set at C$32/MWh for 2010, compared to
C$58/MWh for 2009. However CPILP sold the surplus energy to a third party at a higher price. The surplus energy price for 2011 was set through negotiations with BC Hydro and is attractive.
Mamquam
The Mamquam hydroelectric facility sells all of its electricity generated to BC Hydro under a long-term contract (the "Mamquam EPA") which will
expire in October 2027. BC Hydro has an option, exercisable in 2021 and every five years thereafter, to either purchase the Mamquam facility or extend the Mamquam EPA.
Energy
rates payable under the Mamquam EPA consist of a fixed energy component, an operations and maintenance component (adjusted annually for inflation), and a reimbursable cost
component which covers costs such as property taxes, water and land use fees as well as comprehensive liability insurance costs.
Moresby
Lake
The Moresby Lake hydroelectric facility sells substantially all its electricity to BC Hydro under a long-term contract (the "Moresby Lake PPA")
which will expire in 2022.
The
energy rate payable by BC Hydro under the Moresby Lake PPA consists of a fixed energy component adjusted annually for inflation.
63
Table of Contents
United States
Frederickson
CPILP's
portion (50.15% or approximately 125 MW) of the Frederickson facility's base 249 MW generating capacity has been sold under PPAs to three Washington
State Public Utility Districts ("PUDs") for a term of 20 years ending in 2022. Under the PPAs, CPILP provides generating capacity and associated energy to each PUD, and the PUDs pay CPILP a
capacity charge, a fixed operations and maintenance charge, a variable operations and maintenance charge and a fuel charge. The PUDs must supply their proportionate share of natural gas to CPILP at
Huntingdon, British Columbia. CPILP is responsible for contracting firm transportation for natural gas from Huntingdon to the Frederickson facility. CPILP is responsible for any fixed and variable
cost increases above those recoverable under the PPAs, other than costs that result from the effects of material changes to environmental and tax laws.
Manchief
The Manchief power plant operates under a PPA with the Public Service Company of Colorado ("PSCo") that expires in 2022. PSCo is an electricity and natural
gas distribution company that primarily serves northern Colorado. Under the PPA, PSCo purchases: (i) the electricity capacity consisting of 301.8 MW of net generating capacity per hour, or the
actual net generating capacity that is available in any given hour, whichever is less; and (ii) the electrical energy which is actually dispatched by PSCo and associated with such capacity, and
Manchief is paid capacity and energy payments. Capacity payments are typically stable and are made on a monthly basis, regardless of whether the plant is actually dispatched by PSCo. Energy payments
are also made on a monthly basis and are comprised of tolling fees, start-up fees, heat rate adjustment payments (payable either to or by Manchief) and natural gas transportation charges.
Starting in May 2012, the capacity payments will be reduced by approximately 15% under the tolling arrangement.
Manchief
obtains operations and maintenance services for its generating facility from Colorado Energy Management, LLC pursuant to the terms of a plant operating and maintenance
agreement.
CPILP and PSCo have also signed an Option Agreement under which PSCo has the right, during the latter part of the PPA term, to acquire the Manchief power plant. If
PSCo exercises the
purchase option, CPILP would receive a fixed purchase price, as specified in the Option Agreement, which management believes will maintain the economic value of the term and compensate CPILP for the
power plant's expected residual value.
Greeley
The
Greeley facility provides all of its electrical output to PSCo under an on-system PPA which expires in August 2013. PSCo pays the Greeley
facility a monthly capacity payment and energy payment pursuant to the PPA. CPILP entered into a three-year forward natural gas swap contract expiring in October 2011 that covers most of
the anticipated supply requirements for the Greeley facility during this period. Extension of the forward swap to cover the expiry of the PPA is being evaluated by management.
Under
a development agreement between Ventures and KN/Thermo LLC, KN/Thermo LLC is currently entitled to up to 33.5% of the Pre-Tax Cash Flow from the Greeley
facility. Pre-Tax Cash Flow is defined in the development agreement to include the net proceeds realized by CPILP from the sale of the Greeley facility under certain circumstances, and
cash proceeds received from operation of the Greeley facility (including from sales of electric power and hot water), as reduced by the reasonable operating costs of the facility.
64
Table of Contents
California
Facilities
CPILP's
California facilities are comprised of three facilities located on U.S. naval bases (the "Naval Facilities") and the Oxnard facility.
The Naval Facilities are comprised of Naval Station, North Island and Naval Training Center. Except for the 4 MW steam turbine at the North Island facility, each of
the Naval Facilities
provides all of its electrical output to San Diego Gas and Electric Company ("SDG&E") under the terms of the Long Run Standard Offer No. 4 for Power Purchase and Interconnection agreements from
Qualifying Facilities, each of which expire in 2019. SDG&E is an electricity and natural gas distribution company primarily serving the San Diego area. Each of the Naval Facilities is required to
operate throughout the term of the applicable PPA as a Qualifying Facility ("QF") in accordance with the cogeneration facility requirements established by the Federal Energy Regulatory Commission
("FERC").
In 2009, CPILP completed an upgrade to its gas turbine at the North Island facility in southern California from a GE LM5000 to a GE LM6000 unit for an approximate
cost of
US$17.0 million. The repowering project was completed in time for the summer peak demand season in southern California. The project improved the operating efficiency of the facility reducing
the gas turbine gross heat rate by approximately 1,127 Btu/kWh. The replaced LM5000 unit is available as a spare gas turbine for
CPILP's other LM5000 turbines. The energy produced by the 4 MW steam turbine at the North Island facility is sold to the U.S. Navy at a discount to SDG&E's retail rates. The energy produced by the 2.5
MW steam turbine at the Naval Training Center is sold to SDG&E under a Standard Offer No. 1 for Power Purchase and Interconnection from Qualifying Facilities ("SO1"). The energy rates under the
SO1 are the SDG&E short run avoided cost ("SRAC") rates. Capacity payments are paid on an as-available basis under rates that are reviewed by the California Public Utility Commission
("CPUC") periodically.
The Navy has the right to terminate the Naval Facility Negotiated Utility Service Contracts ("NUSCs") for convenience on one year's notice. Termination costs incurred
under the PPA
would be reimbursed under the NUSC in the event of termination for convenience. See "Thermal Supply Agreements."
The
Oxnard facility provides all of its natural gas turbine electrical output to Southern California Edison Company ("SCE") under a contract that expires in 2020. SCE is an electricity
and natural gas distribution company primarily serving areas of southern California outside Los Angeles and San Diego. The Oxnard facility is required to operate throughout the term of the Oxnard PPA
meeting QF efficiency standards in accordance with the cogeneration facility requirements established by the FERC. The Oxnard facility is qualified as both a QF and an Exempt Wholesale Generator
("EWG").
In May 2010, CPILP completed the replacement of the existing GE LM5000 natural gas turbine with a more efficient and reliable GE LM6000 at Oxnard at a cost of
US$19.3 million.
The final capital cost could potentially be lower if the sale of the used General Electric LM5000 turbine is successful. The repowering project was completed in time for the summer peak demand season
in southern California. While the project improved the Oxnard facility heat rate by 2.4%, the primary economic driver of the project is an expected reduction in forced outage costs relative to the GE
LM5000.
The
price paid under the Naval Facilities' PPAs includes a capacity payment and an energy payment based on SDG&E's SRAC. The price paid under the Oxnard PPA includes a capacity payment
and an energy payment based on SCE's SRAC. Capacity payments are based on achieving availability performance targets. These performance requirements require that forced outage rates for the facility
are to be less than 20% during specified on-peak hours during the summer peak demand months. An additional performance bonus is applied when on-peak forced outage rates are
less than 15%. Each of
65
Table of Contents
the
Naval Facilities and the Oxnard facility has historically achieved its firm capacity revenue and near maximization of capacity bonus revenues.
On
September 20, 2007, the CPUC accepted an alternative decision regarding revisions to the SRAC formulae that became effective August 1, 2009. The essence of the decision
was to provide a 50/50 split between market and administratively determined heat rates for the calculation of the overall heat rate
used in the energy price calculation; provide an escalating operating and maintenance fee adder; and use a 12-month forward-looking market heat rate rather than the historical pricing. The
SRAC change impacts the steam payment component of the Naval Facilities PPAs and CPILP is currently in discussions with the Navy regarding implications of future steam pricing.
SRAC
energy prices are published monthly in accordance with the above mentioned decision. As such, this pricing provision recovers the month-to-month natural gas
costs related to electricity production and substantially passes through the fuel cost to SDG&E and SCE in the variable energy charge. Time of use factors are applied to the SRAC energy rate to value
the electricity delivered during on-peak hours relative to electricity delivered during off-peak hours. The Oxnard facility typically operates during on-peak hours
in order to take advantage of higher electricity prices provided from on-peak time of use rates. Changes in natural gas prices have a nominal impact on the Oxnard facility's operating
margin.
Curtis
Palmer
The Curtis Palmer hydroelectric facility sells all power generated to Niagara Mohawk Power Corporation ("Niagara") under a long-term contract. The
Curtis Palmer PPA ends after the earlier of 2027 and the delivery to Niagara of a cumulative 10,000 GWh of electricity.
The
Curtis Palmer PPA sets out 11 different prices for electricity sold to Niagara, with the applicable price to be paid at any given time being dependent upon the cumulative GWh of
electricity which have been delivered to Niagara. In December 2008, the pricing increased by 18% as the plant moved into the sixth pricing block. Over the remaining term of the PPA, the price
increases by US$10/MWh with each additional 1,000 GWh of electricity delivered. The plant requires approximately three years to move through each 1,000 GWh block, depending upon river flow.
Under
certain circumstances, Niagara has the ability to relocate, rearrange, retire or abandon its transmission system which would potentially give rise to material future capital cost
outlays by Curtis Palmer to maintain its interconnection.
Morris
The Morris facility sells electrical energy to Equistar Chemicals, LP ("Equistar"), a wholly-owned subsidiary of LyondellBasell AF S.C.A.
(LyondellBasell), under an Energy Supply Agreement ("ESA") that expires in 2023. Pursuant to the Morris ESA, Equistar pays a tiered
energy rate based on the amount of energy consumed to a maximum of 77 MW. Equistar also pays capacity fees, comprised of both a non-escalating fixed fee that expires in 2013 and a variable
fee that escalates with materials and labour indices and expires in 2023. The non-escalating capacity payment is fixed at US$8.3 million per year. In addition, the Morris facility
earns energy payments based on electricity and steam delivered that is adjusted monthly for natural gas prices. Based on the energy payment formula, there is a small portion of energy costs that are
not recovered through the energy payments, and this non-recoverable amount fluctuates with the price of natural gas. Most of this natural gas price exposure has been hedged through 2011.
Equistar has a right to purchase the Morris facility at fair market value at the end of 2013, 2018 and 2023. The Morris facility is certified as a QF.
Excess capacity and energy above the needs of Equistar can be sold into the Pennsylvania, New Jersey, and Maryland ("PJM") market. 100 MW of electrical capacity has
been sold through
the PJM market from May 2011 to April 2014 at auction prices.
66
Table of Contents
On January 6, 2009, Equistar, along with LyondellBasell's other North American operating entities, filed a voluntary petition for reorganization
under
Chapter 11 of the U.S. Bankruptcy Code. Since that date, Equistar made all post-petition payments required under the ESA. On April 23, 2010 the plan of reorganization for
LyondellBasell's U.S. subsidiaries, including Equistar, under Chapter 11 of the U.S. Bankruptcy Code was approved. Pursuant to the plan of reorganization, Equistar assumed the Morris ESA, and
as a result, CPILP received a US$12.4 million payment for pre-petition services under the ESA along with interest.
Kenilworth
The
Kenilworth facility sells electrical energy to Schering-Plough Corporation ("Schering"), a subsidiary of Merck & Co., Inc., under an
amended and extended ESA that expires in July 2012. Pursuant to the Kenilworth ESA, Schering pays an energy rate that escalates annually. The Kenilworth ESA imposes a minimum take or pay obligation on
Schering of 125,000 MWh per year. Load growth at Schering's facility over the years has caused certain seasonal loads to match more closely with the capacity of the Kenilworth facility. Excess
generation above the Schering loads are sold to Public Service Enterprise Group Incorporated under a contract entered into in 2009.
Thermal Supply Agreements
The Greeley facility sells hot water to the University of Northern Colorado ("UNC") pursuant to a Thermal Supply Agreement ("TSA")
which expires in August 2013. Under the Greeley TSA, the Greeley facility is obligated to deliver for sale to UNC only such heat energy as is generated during the production of electrical capacity and
energy for sale to PSCo. The charge per million Btu of thermal energy is calculated in a manner that gives UNC a discount when compared to UNC avoided natural gas-fired boiler costs.
The Naval Facilities sell steam to the Navy pursuant to NUSCs, each of which expires in February 2018. The Naval Facility NUSCs give the Navy a right to purchase
electrical energy from
the Naval Facilities at prices comparable to those under the Naval Facility PPAs. Under the Naval Facility NUSCs, the Navy has an obligation to consume enough thermal energy for the Naval Facilities
to maintain their QF status. The Navy has the right to terminate the NUSCs for convenience on one year's notice. The Navy is obligated to pay a termination payment if it breaches an agreement or
causes any loss of a Naval Facility's QF status.
The
contracted steam for the Naval Facilities is based on a take or pay formula using a specified volume at each facility. Additional steam can be taken above these specified volumes
and such steam is priced at avoided package boiler costs. The monthly price payable by the Navy for steam under the Naval Facility NUSCs includes: (i) a steam commodity charge;
(ii) fixed service charge for plant capital and operations and maintenance avoidance; and (iii) water cost pass-through provisions, a feed water charge and a credit for
condensate return.
Steam
pricing is linked to the cost of natural gas and SDG&E's SRAC by an energy sharing formula. This formula provides the Naval Facilities with reduced price volatility as the SRAC
price of electricity primarily increases or decreases as a result of changes to the price of natural gas. Changes in natural gas prices have a nominal impact on the Naval Facilities' cash provided by
operating activities. On September 20, 2007, the CPUC accepted an alternative decision regarding revisions to the SRAC formulae that became effective on August 1, 2009.
The
Oxnard facility supplies steam to its anhydrous ammonia absorption refrigeration plant, which then provides refrigeration services to Boskovich Farms at no charge; thereby
maintaining the Oxnard facility's QF status.
67
Table of Contents
The
Morris facility sells steam to Equistar to a maximum of 720 million lbs/hr under the Morris ESA through 2023. Ten year average usage is approximately 320 million
lbs/hr. The Morris ESA charge for steam is calculated on the basis of a tiered pricing schedule ranging from US$2.60/mlbs of steam to US$3.18/mlbs of steam depending on quantity of average monthly
steam demand. The agreement provides for the option to renegotiate pricing if steam demand falls outside a set range for a stipulated period of time.
The Kenilworth facility sells steam to Schering under an amended and extended Kenilworth ESA that expires in July 2012. The Kenilworth ESA provides for a contract
minimum of
160,000 million Btu per year. The average annual heat content of steam sales directly from the Kenilworth facility under the terms of the Kenilworth ESA has been higher (740,000 million
Btu per year average) than the contract minimum. The Kenilworth ESA charge per million Btu of steam is calculated as a function of the delivered cost of fuel to Schering's auxiliary boilers. Schering
is able to request long term purchase strategies to minimize the monthly volatility of natural gas prices.
Fuel Purchase Agreements
The largest of CPILP's expenses is the cost of fuel used in the generation of electricity. Fuel costs include the natural gas
commodity price, natural gas transportation charges, waste heat optimization costs and wood waste costs at the Calstock and Williams Lake plants. Wood waste costs include the cost of wood waste, the
transportation of wood waste, fuel and management costs and the disposal of wood ash. Although wood waste and the related transportation services have been purchased under contract for the majority of
the fuel requirements at the Calstock and Williams Lake facilities, the suppliers have no obligation to provide in the event they scale back or shut down operations.
CPILP
purchases fuel gas and/or waste heat for each of the Ontario power plants except Tunis, under long-term natural gas and waste heat supply agreements. CPILP reached an
agreement with the OEFC to amend the Tunis PPA effective January 16, 2010 that allows CPILP to flow-through natural gas and transportation costs in excess of benchmark amounts to
OEFC and extends OEFC the right to curtail the plant during summer off-peak periods through the remaining term of the PPA in 2014. Firm capacity for the transportation of fuel gas to the
Ontario power plants has been contracted for on the TransCanada natural gas transmission system under long-term transportation agreements, the earliest of which expires in 2011.
In late 2008, CPILP completed a new supply agreement with a nearby wood waste landfill site for Calstock. The landfill site is estimated by management to have
equivalent to one million
green metric tons of supply, which is equal to three years of supply for the plant. Pursuant to a Certificate of Approval ("CoA") from the Ministry of Environment, Calstock successfully completed a
rail ties test burn in November 2009. CPILP has applied for a permanent CoA amendment from the Ministry of
Environment. If approved, the rail ties could provide up to 20% of the Calstock facility's fuel requirement.
Wood waste supply to the Williams Lake facility was sufficient in 2010. Traditional suppliers returned to near normal production levels with the exception of one
supplier who continues
to idle one of their sawmills. CPILP has identified other sources of supply to replace volume lost from the curtailed sawmill. These sources are more expensive; however, approximately 82% of the fuel
cost is borne by BC Hydro under the EPA. The facility is well positioned to withstand potential fuel shortages largely due to an agreement with Pioneer Biomass Inc. to supply processed forest
based residuals, on an as needed basis, to the Williams Lake facility. Fuel inventory levels were reduced significantly in 2010 to bring back to normal operating levels. The expanded wood waste
storage capacity continues to provide flexibility in managing available lower cost wood waste supplies. At December 31, 2010, the
68
Table of Contents
plant had sufficient wood waste inventory for the plant to produce its maximum output of 66 MW for 35 days at full output.
Natural gas supply purchased for the Greeley facility is financially fixed under an agreement with Shell Energy North America and CP Energy Marketing (US) Inc.
which expires in
October 2011. Natural gas for the Naval Facilities and Oxnard is purchased through natural gas contracts with RBS Sempra Energy Trading Corporation (Sempra) at monthly index prices similar to those
used in the utility SRAC calculations. Kenilworth natural gas is also purchased from Sempra with that price used directly in the steam pricing under the ESA. The Morris facility obtains the majority
of its required natural gas through a Purchase and Sale Agreement with DCP Midstream Marketing LP and Tenaska Power Services Co. (Tenaska) which expires in 2014 at a price indexed to the
Chicago City Gate market. Under the agreement, Tenaska also provides power market trading services through a year-to-year agreement that may be cancelled on 60 days
notice. Additionally, the Morris facility contracts gas storage facility as a seasonal hedge and to maximize operational flexibility.
Waste Heat Agreements
Pursuant to long-term waste heat agreements, TransCanada provides the Ontario power plants with all waste heat generated
by the natural gas turbine compressors located at the compressor stations adjacent to the Ontario power plants on an as available basis. Each agreement continues in effect for as long as CPILP
delivers electrical energy from the particular plant. The waste heat agreements provide that TransCanada will be obligated to supply waste heat to the Ontario power plants only when such waste heat is
available from the compressor stations. In the event waste heat output is reduced at a compressor station as a result of reduced natural gas turbine output arising from any cause, TransCanada's
obligation to deliver waste heat is reduced accordingly.
In
2003, CPILP entered into an agreement with TransCanada to optimize the waste heat availability at certain of CPILP's Ontario plants. Under the agreement, CPILP pays for incremental
natural gas used in the compressor station turbines to optimize the quantities of waste heat which can be available to CPILP's adjacent power plant. Any incremental maintenance or repair costs as a
result of the increased use of TransCanada's turbines are also charged to CPILP.
69
Table of Contents
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information regarding the beneficial ownership of our common shares as of September 14, 2011
with respect to:
-
-
each person (including any "group" of persons as that term is used in Section 13(d)(3) of the Exchange Act) who is
known to us to be the beneficial owner of more than 5% of our outstanding common shares (none as of September 14, 2011);
-
-
each of our directors;
-
-
each of our named executive officers; and
-
-
all of our directors and named executive officers as a group.
The
address of each beneficial owner listed in the following table is c/o Atlantic Power Corporation, 200 Clarendon Street, Floor 25, Boston, MA 02116.
Except as otherwise indicated in the footnotes to the following table, we believe, based on the information provided to us, that the persons named in the following
table have sole
voting and investment power with respect to the shares they beneficially own, subject to applicable community property laws.
|
|
|
|
|
|
Owner
|
|
Number of common
shares beneficially
owned
|
|
Percentage of
common shares
beneficially owned
(1)
|
Directors and named executive officers
|
|
|
|
|
*
|
Irving R. Gerstein
|
|
|
10,400
|
|
*
|
Kenneth M. Hartwick
|
|
|
57,485
|
(2)
|
*
|
John A. McNeil
|
|
|
12,500
|
|
*
|
R. Foster Duncan
(3)
|
|
|
1,500
|
|
*
|
Holli Nichols
(3)
|
|
|
2,550
|
(2)
|
*
|
Barry E. Welch
|
|
|
223,105
|
|
*
|
Paul H. Rapisarda
|
|
|
40,009
|
|
*
|
William B. Daniels
|
|
|
7,173
|
|
*
|
John J. Hulburt
|
|
|
4,643
|
|
*
|
All directors and named executive officers as a group (9 persons)
|
|
|
359,365
|
|
0.01
|
-
*
-
Less
than l%.
-
(1)
-
The
applicable percentage ownership is based on 68,639,654 common shares issued and outstanding as of June 30, 2011.
-
(2)
-
Common
shares beneficially owned include units held in our Deferred Share Unit Plan of 55,485 for Ken Hartwick and 2,550 for Holli Nichols.
-
(3)
-
Joined
our board of directors in June 2010.
70
Table of Contents
DESCRIPTION OF COMMON SHARES
The following summary description sets forth some of the general terms and provisions of our common shares. Because this is a summary
description, it does not contain all of the information that may be important to you. For a more detailed description of our common shares, you should refer to the provisions of our Articles of
Continuance, which we refer to as our "Articles."
The last reported sale price of our common shares on the TSX on September 14, 2011 was C$14.65 per common share, and the last reported sale price of our common
shares on the NYSE
on September 14, 2011 was $14.79 per common share.
Common Shares
Our Articles authorize an unlimited number of common shares. At the close of business on September 14, 2011, 68,984,192 of our
common shares were issued and outstanding.
Our
common shares are listed on the TSX under the symbol "ATP" and began trading on the NYSE under the symbol "AT" on July 23, 2010. Holders of our common shares are entitled to
receive dividends as and when declared by our board of directors and are entitled to one vote per common share on a vote by poll, or one vote per person present who is a shareholder or a proxy holder
for a vote by show of hands, in each case with respect to all matters to be voted on at meetings of shareholders. We are limited in our ability to pay dividends on our common shares by restrictions
under the Business Corporations Act (British Columbia), which we refer to as the "BC Act," relating to our solvency before and after the payment of a dividend. Holders of our common shares have no
preemptive, conversion or redemption rights and are not subject to further assessment by us.
Upon
our voluntary or involuntary liquidation, dissolution or winding up, the holders of common shares are entitled to share ratably in the remaining assets available for distribution,
after payment of liabilities.
Holders
of our common shares will have one vote for each common share held at meetings of our common shareholders on a vote by poll, and one vote per person present who is a shareholder
or a proxy holder for a vote by show of hands.
Pursuant
to our Articles and the provisions of the BC Act, certain actions that may be proposed by us require the approval of our shareholders. We may, by special resolution and subject
to our Articles, increase our authorized capital by such means as creating shares with or without par value or increasing the number of shares with or without par value. We may, by special resolution
and subject to the BC Act, alter our Articles to subdivide, consolidate, change from shares with par value to shares without par value or from shares without par value to shares with par value or
change the designation of all or any of our shares. We may also, by special resolution and subject to the BC Act, alter our Articles to create, define, attach, vary, or abrogate special rights or
restrictions to any shares. Under the BC Act and our Articles, a special resolution is a resolution passed at a duly-convened meeting of shareholders by not less than
two-thirds of the votes cast in person or by proxy at the meeting, or a written resolution consented to by all shareholders who would have been entitled to vote at the meeting of
shareholders.
Certain provisions of our Articles and the BC Act
We are governed by the BC Act. Our Articles contain provisions that could have the effect of delaying, deferring or discouraging
another party from acquiring control of our company by means of a tender offer, a proxy contest or otherwise.
71
Table of Contents
Advance notice procedures
Our Articles establish an advance notice procedure for "special business" and shareholder proposals to be brought before a meeting of
shareholders. For special business, advance notice describing the special business to be discussed at the meeting must be provided and that notice must include any documents to be approved or ratified
as an addendum or state that such document will be available for inspection at our records office or other reasonably accessible location. Shareholders at an annual meeting may not consider proposals
or nominations that are not specified in the notice of meeting or brought before the meeting by or at the direction of the board of directors or by a shareholder of record on the record date for the
meeting or a proxyholder who is entitled to vote at the meeting.
Advance notice procedures
Under the BC Act, shareholders may make proposals for matters to be considered at the annual general meeting of shareholders. Such
proposals must be sent to us in advance of any proposed meeting by delivering a timely written notice in proper form to our registered office. The notice must include information on the business the
shareholder intends to bring before the meeting. These provisions could have the effect of delaying until the next shareholder meeting shareholder actions that are favored by the holders of a majority
of our outstanding voting securities.
Shareholder requisitioned meeting
Under the BC Act, shareholders holding
1
/
20
of our outstanding common shares may request the directors to call a
general meeting of shareholders to deal with matters that may be dealt with at a general meeting, including election of directors. If the directors do not call the meeting within the timeframes
specified in the BC Act, the shareholder can call the meeting and we must reimburse the costs.
Removal of directors and increasing board size
Under our Articles, directors may be removed by shareholders by passing an ordinary resolution of a simple majority of shareholders
with the right to vote on such resolution. Further, under our Articles and subject to the BC Act, the directors may appoint additional directors up to one-third of the directors elected by
the shareholders.
Canadian Securities Laws
We are a reporting issuer in Canada and therefore subject to the securities laws in each province and territory in which we are
reporting. Canadian securities laws require reporting of share purchases and sales by shareholders holding more than 10% of our common shares, including certain prescribed public disclosure of their
intentions for their holdings. Canadian securities laws also govern how any offer to acquire more than 20% of our equity or voting shares must be conducted.
Transfer Agent and Registrar
Computershare Investor Services Inc. and Computershare Trust Company, N.A. serve as our transfer agents and registrars for our
common shares.
72
Table of Contents
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following general summary describes certain U.S. federal income tax considerations for U.S. Holders (as defined below) of our
common shares. This summary does not address all of the tax considerations that may be relevant to certain types of U.S. Holders subject to special treatment under U.S. federal income tax laws, such
as:
-
-
persons who do not hold common shares as capital assets;
-
-
dealers in securities or currencies;
-
-
financial institutions;
-
-
regulated investment companies;
-
-
real estate investment trusts;
-
-
tax-exempt entities (including private foundations);
-
-
qualified retirement plans, individual retirement accounts, and other tax-deferred accounts;
-
-
insurance companies;
-
-
persons holding common shares as a part of a hedging, integrated, conversion or constructive sale transaction or a
straddle;
-
-
persons that own, directly, indirectly or as a result of certain constructive ownership rules, common shares representing
10% or more of the voting power in Atlantic Power;
-
-
traders in securities that elect to use a mark-to-market method of accounting;
-
-
persons liable for alternative minimum tax;
-
-
U.S. Holders whose "functional currency" is not the U.S. dollar; or
-
-
U.S. tax expatriates and certain former citizens and long-term residents of the United States.
This
summary is based upon the provisions of the United States Internal Revenue Code of 1986 (as amended, the "Code"), the United States Treasury Regulations promulgated thereunder, and
administrative and judicial interpretations of the Code and the United States Treasury Regulations, all as currently in effect, and all subject to differing interpretations or change, possibly on a
retroactive basis. This summary does not address any estate, gift, state, local, non-U.S. or other tax consequences, except as specifically provided herein.
For
purposes of this summary, a "U.S. Holder" means a person that holds common shares that is, for U.S. federal income tax purposes:
-
-
an individual who is a citizen or resident of the U.S. (as determined under U.S. federal income tax rules);
-
-
a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) created or organized in or
under the laws of the United States or of any political subdivision thereof;
-
-
an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or
-
-
a trust if it (i) is subject to the primary supervision of a court within the United States and one or more U.S.
persons have the authority to control all substantial decisions of the trust or (ii) has in effect a valid election under applicable United States Treasury Regulations to be treated as a U.S.
person.
73
Table of Contents
If
a partnership or an entity treated as a partnership for U.S. federal income tax purposes holds common shares, the U.S. federal income tax treatment of a partner in the partnership
will generally depend on the status of the partner and the activities of the partnership. Partnerships or a partner in a partnership holding common shares should consult their own tax advisor
regarding the consequences of the ownership and disposition of common shares by the partnership.
The following summary is of a general nature only and is not a substitute for careful tax planning and advice. U.S. Holders of common shares are urged to consult
their own tax advisors concerning the U.S. federal income tax consequences of the issues discussed herein, in light of their particular circumstances, as well as any considerations arising under the
laws of any foreign, state, local or other taxing jurisdiction.
Taxation of distributions on common shares
The gross amount (i.e., before Canadian withholding tax) of distributions to a U.S. Holder on our common shares (other than
distributions in liquidation or in redemption of stock that are treated as exchanges) will be treated as a dividend, to the extent paid out of our current or accumulated earnings and profits (as
determined under U.S. federal income tax principles). Such dividend will be includible in a U.S. Holder's gross income on the day actually or constructively received. Distributions to a U.S. Holder in
excess of earnings and profits will be treated first as a return of capital that reduces a U.S. Holder's tax basis in such common shares (thereby increasing the amount of gain or decreasing the amount
of loss that a U.S. Holder would recognize on a subsequent disposition of our common shares), and then as gain from the sale or exchange of such common shares.
Non-corporate
U.S. Holders will generally be eligible for the preferential U.S. federal rate on qualified dividend income for tax years beginning on or before
December 31, 2012, provided that we are a "qualified foreign corporation," the stock on which the dividend is paid is held for a minimum holding period, and other requirements are satisfied.
A
qualified foreign corporation includes a foreign corporation that is not a PFIC (as defined below) in the year of the distribution or in the prior tax year and that is eligible for
the benefits of an income tax treaty with the United States, if such treaty contains an exchange of information provision and the United States Treasury Department has determined that the treaty is
satisfactory for purposes of the legislation. Based on current law and applicable administrative guidance, our dividends paid before December 31, 2012 should be eligible for treatment as
qualified dividend income, provided the holding period and other requirements are satisfied. In the absence of intervening legislation, dividends received by a U.S. Holder after tax years beginning on
or after December 31, 2012 will be taxed to such Holder at ordinary income rates.
Distributions
to U.S. Holders generally will not be eligible for the dividends received deduction generally allowed to U.S. corporations in respect of dividends received from other U.S.
corporations.
A
U.S. Holder will be taxed on the U.S. dollar value of any Canadian dollars received as dividends, generally determined at the spot rate as of the date the payment is actually or
constructively received. No currency exchange gain or loss will be recognized by a U.S. Holder on such dividend payments if the Canadian dollars are converted into U.S. dollars on the date received at
that spot rate. Any gain or loss on a subsequent conversion or other disposition of Canadian dollars generally will be treated as U.S.-source ordinary income or loss.
Taxation of sale, exchange or other taxable disposition of common shares
Upon the sale, exchange or other taxable disposition of a common share, a U.S. Holder generally will recognize gain or loss equal to
the difference between the amount realized upon the sale, exchange or other disposition and such U.S. Holder's tax basis in the common share. The amount
74
Table of Contents
realized
on the sale, exchange or other taxable disposition of the common shares will be the U.S. dollar value of any Canadian dollars received in the transaction, which is determined for cash basis
taxpayers on the settlement date for the transaction and for accrual basis taxpayers on the trade date (although accrual basis taxpayers can also elect the settlement date). Any such gain or loss will
generally be capital gain or loss and will generally be long-term capital gain or loss if the U.S. Holder's holding period for the common shares transferred exceeds one year on the date of
the sale or disposition. Long-term capital gains of non-corporate U.S. Holders derived with respect to the disposition of common shares are currently subject to tax at reduced
rates. The deductibility of capital losses is subject to several limitations. Any gain or loss realized on a subsequent conversion or other disposition of Canadian dollars will be ordinary gain or
loss.
Disclosure of reportable transactions
If a U.S. Holder sells or disposes of the common shares at a loss or otherwise incurs certain losses that meet certain thresholds,
such U.S. Holder may be required to file a disclosure statement with the IRS. For U.S. Holders that are individuals or trusts, there is a special reporting requirement threshold for foreign
currency losses, which is US$50,000. Failure to comply with these and other reporting requirements could result in the imposition of significant penalties.
Foreign tax credit limitations
U.S. Holders may be subject to Canadian withholding tax on payments made with respect to the common shares. Subject to certain
conditions and limitations, such withholding taxes may be treated as foreign taxes eligible for credit against a U.S. Holder's U.S. federal income tax liability. Such credit may not be available to
U.S. holders owning the common shares in a non-taxable account. Additionally, foreign taxes may not be eligible to the extent they could have been reduced pursuant to an income tax treaty.
It
is possible that we are, or at some future time will be, at least 50% owned by U.S. persons. Dividends paid by a foreign corporation that is at least 50% owned by U.S. persons may be
treated as U.S.-source income (rather than foreign-source income) for foreign tax credit purposes to the extent the foreign corporation has more than an insignificant amount of U.S.-source income. The
effect of this rule may be to treat a portion of any dividends we pay as U.S.-source income. Treatment of the dividends as U.S.-source income in whole or in part may limit a U.S. Holder's ability to
claim a foreign tax credit for the Canadian withholding taxes payable in respect of the dividends. Subject to certain limitations, the Code permits a U.S. Holder entitled to benefits under the
U.S.-Canadian income tax treaty to elect to treat any Company dividends as foreign-source income for foreign tax credit purposes. U.S. Holders should consult their own tax advisors about the
desirability of making, and the method of making, such an election.
The
rules governing foreign tax credits are complex. U.S. Holders are urged to consult their own tax advisors regarding the availability of foreign tax credits in their particular
circumstances.
Passive foreign investment company
A foreign corporation is a passive foreign investment company ("PFIC") within the meaning of Section 1297 of the Code if,
during any taxable year, (i) 75% or more of its gross income consists of certain types of passive income, or (ii) the average value (or basis in certain cases) of its passive assets
(generally assets that generate passive income) is 50% or more of the average value (or basis in certain cases) of all of its assets. If we were a PFIC while a taxable U.S. Holder held common shares,
the PFIC rules could have the effect of subjecting such U.S. Holder to an interest charge on any deferred taxation and taxing gain upon the sale of our common shares as ordinary income. In addition,
under recently enacted legislation each U.S. Holder of a PFIC is required to file an annual report containing
75
Table of Contents
such
information as the U.S. Department of the Treasury may require. The reporting requirements imposed by this new legislation have been suspended until the IRS issues the revised form necessary to
report the requisite information, but following the release of such revised form, affected U.S. Holders will have to attach the form for the suspended tax year to their next return to be filed with
the IRS. If we were classified as a PFIC in any year with respect to which a U.S. Holder owns common shares, we would continue to be treated as a PFIC with respect to the U.S. Holder in all succeeding
years during which the U.S. Holder owns common shares, regardless of whether we continue to meet the tests described above. However, if we ceased to be a PFIC, a U.S. Holder of our common shares could
avoid some of the adverse effects of the PFIC regime by making a deemed sale election with respect to our common shares.
We
do not believe we are a PFIC, and we do not expect to become a PFIC. If our income or asset composition were to become more passive (including through the acquisition of assets that
generate passive income, or minority investments in stock of corporations), we could potentially become a PFIC. Our PFIC status for any taxable year may also depend upon the extent to which our
revenue is subject to special PFIC rules with respect to "commodities," an analysis that raises uncertainties in application and interpretation. Additionally, if we were a PFIC and were to form or
acquire non-U.S. subsidiaries that are treated as corporations for U.S. tax purposes, such subsidiaries could potentially be PFICs. If we owned a subsidiary that is a PFIC, then taxable
U.S. Holders could be adversely affected as a result of their indirect ownership of stock in any subsidiary of ours that is a PFIC.
Information reporting and backup withholding
In general, information reporting requirements will apply to payments with respect to common shares paid to a U.S. Holder other than
certain exempt recipients (such as
corporations). Backup withholding will apply to such payments if such U.S. Holder fails to provide a taxpayer identification number or certification of other exempt status or fails to comply with the
applicable requirements of the backup withholding rules. Any amounts withheld under the backup withholding rules will be allowed as a refund or a credit against such U.S. Holder's U.S. federal income
tax liability provided the required information is furnished by such U.S. Holder to the IRS. A U.S. Holder who does not provide a correct taxpayer identification number may be subject to penalties
imposed by the IRS.
In
addition, for taxable years beginning after March 18, 2010, certain U.S. Holders who are individuals who hold certain foreign financial assets (which may include common
shares) are required to report information relating to such assets, subject to certain exceptions. The reporting requirement has been suspended until the IRS issues the form necessary to report the
requisite information, but following the release of such form, affected U.S. Holders will have to attach the form for the suspended tax year to their next return to be filed with the IRS. U.S. Holders
should consult their own tax advisors regarding the effect, if any, of this legislation on their ownership and disposition of common shares.
Additional Tax on Passive Income
Certain U.S. Holders that are individuals, estates or trusts will be required to pay up to an additional 3.8% tax on, among other
things, dividends and capital gains for taxable years beginning after December 31, 2012. Such tax will apply to dividends to and capital gains from the sale or other disposition of our common
shares.
76
Table of Contents
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
The following is a summary of the principal Canadian federal income tax considerations generally applicable under the Income Tax Act
(Canada) and the regulations thereunder (collectively, the "Tax Act") to a holder that acquires our common shares pursuant to the offering and that, for the purposes of the Tax Act and the
Canada-United States Income Tax Convention (the "Canadian Treaty"), at all relevant times (a) is a resident of the United States and is not resident, or deemed to be resident, in Canada,
(b) holds the common shares as capital property, (c) deals at arm's length with the Company, (d) is not affiliated with the Company, and (e) does not use or hold and is not
deemed to use or hold the common shares in connection with a trade or business that the prospective purchaser carries on, or is deemed to carry on, in Canada at any time (a "U.S. Holder"). For the
purpose of the Tax Act, related persons (as defined therein) are deemed not to deal at arm's length, and it is a question of fact whether persons not related to each other deal at arm's length.
Special rules which are not discussed in this summary may apply to "financial institutions" (as defined in the Tax Act), to a U.S. Holder that is an insurer carrying on an insurance business in Canada
and elsewhere and to an "authorized foreign bank" (as defined in the Tax Act) and, accordingly, such persons should consult their own tax advisors.
Limited
liability companies ("LLCs") that are not taxed as corporations pursuant to the provisions of the Code do not qualify as resident in the U.S. for purposes of the Canadian
Treaty. Under the Canadian Treaty, a resident of the U.S. that is a member of such an LLC and is otherwise eligible for benefits under the Canadian Treaty may generally be entitled to claim
benefits under the Canadian Treaty in respect of income, profits or gains derived through the LLC.
The
Canadian Treaty includes limitation on benefits rules that restrict the ability of certain persons that are resident in the U.S. for purposes of the Canadian Treaty to claim any or
all benefits under the Canadian Treaty. U.S. Holders should consult their own tax advisors with respect to their eligibility for benefits under the Canadian Treaty, having regard to these rules.
This summary is of a general nature only and is based upon the facts set out herein, the provisions of the Tax Act, the Canadian Treaty and the current published
administrative policies
and assessing practices of the Canada Revenue Agency (the "CRA"), all in effect as of the date hereof. This summary is based on the assumption that the common shares issuable will at all relevant
times be listed on the Toronto Stock Exchange. This summary takes into account all specific proposals to amend the Tax Act publicly announced by or on behalf of the Minister of Finance (Canada) prior
to the date hereof. There can be no assurance that any such proposals will be implemented in their current form or at all. This summary does not otherwise take into account or anticipate any changes
in law or in the administrative policies and assessing practices of the CRA, whether by legislative, governmental or judicial decision or action, and does not take into account provincial, territorial
or foreign tax legislation or considerations, which may differ significantly from those discussed herein.
This summary is not exhaustive of all possible Canadian federal tax considerations applicable to an investment in common shares. Moreover, the Canadian tax
consequences of acquiring,
holding or disposing of common shares will vary depending on the U.S. Holder's particular circumstances. Accordingly, this summary is of a general nature only and is not intended to be, and should not
be interpreted as, legal or tax advice to any prospective purchaser and no representation with respect to the tax consequence to any particular U.S. Holder is made. Prospective investors should
consult their own tax advisors with respect to the Canadian tax consequences of an investment in common shares based on their particular circumstances.
Prospective investors may also be subject to certain Canadian provincial or territorial tax consequences as a result of acquiring, holding or disposing of common
shares. Accordingly,
prospective investors are urged to consult with their tax advisors for advice with respect to Canadian provincial or territorial tax consequences of an investment in common shares based on their
particular circumstances.
77
Table of Contents
For purposes of the Tax Act, all amounts relating to the acquisition, holding or disposition of common shares, including income, gain or profit, adjusted cost base
and proceeds of
disposition, must be converted into Canadian dollars based on the prevailing United States dollar exchange rate at the time such amounts arise in accordance with the detailed rules in the Tax Act.
Dividends on Common Shares
Dividends paid or credited on the common shares, or deemed under the Tax Act to be paid or credited on the common shares, to a U.S.
Holder will generally be subject to Canadian withholding tax at the rate of 25%, unless the rate is reduced under the provisions of an applicable tax treaty. Under the Canadian Treaty, the withholding
tax rate in respect of a dividend paid to a U.S. Holder that is the beneficial owner of the dividend and entitled to full benefits under the Canadian Treaty, is generally reduced to 15%.
Disposition of Common Shares
A U.S. Holder will not be subject to tax under the Tax Act in respect of any capital gain realized by such U.S. Holder on a
disposition of common shares unless the common shares constitute "taxable Canadian property" (as defined in the Tax Act) of the U.S. Holder at the time of disposition and the U.S. Holder is not
entitled to relief under an applicable tax treaty. Where the common shares are listed on a designated stock exchange for purposes of the Tax Act (which currently includes both the TSX and the NYSE) at
a particular time, the common shares will not constitute taxable Canadian property to a U.S. Holder at such time provided that at any time during the sixty-month period that ends at that time, either:
(a) the U.S. Holder, persons with which the U.S. Holder does not deal at arm's length, or the U.S. Holder together with all such persons, have not owned 25% or more of any class or series of
shares of the capital stock of the Company; or (b) such common shares did not derive, directly or indirectly, more than 50% of their fair market value from one or any combination of
(i) real or immovable property situated in Canada, (ii) "Canadian resource properties" (as defined in the Tax Act), (iii) "timber resource properties" (as defined in the Tax Act),
and (iv) options or interests in respect of property described in (i), (ii) and (iii).
In the event that the common shares constitute or are deemed to constitute taxable Canadian property to any U.S. Holder, the Canadian Treaty (or other applicable tax
treaty or
convention) may exempt the U.S. Holder from tax under the Tax Act in respect of the disposition thereof. U.S. Holders whose common shares may be taxable Canadian property should consult with their own
tax advisors for advice having regard to their particular circumstances.
78
Table of Contents
UNDERWRITING
We are offering the common shares described in this prospectus through the underwriters named below. TD Securities Inc.
and Morgan Stanley & Co. LLC are the joint book-running managers of this offering and the representatives of the underwriters (the "Representative"). We have entered
into an underwriting agreement (the "Underwriting Agreement") with the representatives. Subject to the terms and conditions of the Underwriting Agreement, each of the underwriters has severally agreed
to purchase, and we have agreed to sell to the underwriters, the number of common shares listed next to its name in the following table.
|
|
|
|
Underwriters
|
|
Number of
shares
|
TD Securities Inc.
|
|
|
Morgan Stanley & Co. LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
The Underwriting Agreement provides that the underwriters must buy all of the shares if they buy any of them. However, the underwriters are not
required to take or pay for the shares covered by the underwriters' over-allotment option described below.
Our
common shares are offered subject to a number of conditions, including:
-
-
receipt and acceptance of our common shares by the underwriters, and
-
-
the underwriters' right to reject orders in whole or in part.
In
connection with this offering, certain of the underwriters or securities dealers may distribute prospectuses electronically.
We
expect that delivery of the shares will be made against payment therefor on or about the closing date of this offering specified on the cover page of this Prospectus, which is five
business days following the date of pricing of the shares (this settlement cycle being referred to as "T+5"). Under Rule 15c6-1 of the Exchange Act, trades in the secondary market
generally are required to settle in three business days, unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade their shares on the date of pricing
or the next succeeding business day will be required, by virtue of the fact that the shares initially will settle in T+5, to specify an alternate settlement cycle at the time of any such trade to
prevent a failed settlement. Purchasers of the shares who wish to trade their shares on the date of pricing or the next succeeding business day should consult their own advisor.
Over-Allotment Option
We have granted the underwriters an option to buy up to an aggregate
of additional common shares. The underwriters may
exercise this option solely for the purpose of covering over-allotments, if any, made in connection with this offering. The underwriters have 30 days from the date of this
prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional shares approximately in proportion to the amounts specified in the table above.
Commissions and Discounts
Shares sold by the underwriters to the public will initially be offered at the public offering price set forth on the cover of this
prospectus. Any shares sold by the underwriters to securities dealers may
79
Table of Contents
be sold at a discount of up to $ per share from the public offering price. Sales of shares may be made in other jurisdictions by affiliates of the underwriters. If all the shares
are
not sold at the public offering price, the representatives may change the offering price and the other selling terms. Upon execution of the Underwriting Agreement, the underwriters will be obligated
to purchase the shares at the prices and upon the terms stated therein.
The
following table shows the per share and total underwriting discounts and commissions we will pay to the underwriters assuming both no exercise and full exercise of the underwriters'
option to purchase additional common shares.
|
|
|
|
|
|
|
|
|
|
|
No
exercise
|
|
Full
exercise
|
|
Per share
|
|
$
|
|
|
$
|
|
|
|
Total
|
|
$
|
|
|
$
|
|
|
We estimate that the total expenses of this offering payable by us, not including the underwriting discounts and commissions, will be
approximately $ million.
No Sales of Similar Securities
We and our executive officers and directors have entered into lock-up agreements with the underwriters. Under these
agreements, subject to certain exceptions, we and each of these persons may not, without the prior written approval of the Representatives, offer, sell, contract to sell or otherwise dispose of,
directly or indirectly, or hedge our common shares or securities convertible into or exchangeable or exercisable for our common shares. These restrictions will be in effect for a period of
90 days after the date of this prospectus. At any time and without public notice, the Representatives may, in their sole discretion, release some or all of the securities from these
lock-up agreements.
Indemnification
We have agreed to indemnify the underwriters against certain liabilities, including certain liabilities under the Securities Act. If
we are unable to provide this indemnification, we have agreed to contribute to payments the underwriters may be required to make in respect of those liabilities.
NYSE and TSX Stock Market Listings
Our common shares are listed on the NYSE under the symbol "AT" and on the TSX under the symbol "ATP."
Price Stabilizations, Short Positions
In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of
our common shares, including:
-
-
stabilizing transactions;
-
-
short sales;
-
-
purchases to cover positions created by short sales;
-
-
imposition of penalty bids; and
-
-
syndicate covering transactions.
Stabilizing
transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common shares while this offering is in
progress. These transactions may also include making short sales of our common shares, which involve the sale by the
80
Table of Contents
underwriters
of a greater number of common shares than they are required to purchase in this offering, and purchasing common shares on the open market to cover positions created by short sales. Short
sales may be "covered short sales," which are short positions in an amount not greater than the underwriters' over-allotment option referred to above, or may be "naked short sales," which
are short positions in excess of that amount.
The
underwriters may close out any covered short position by either exercising their over-allotment option, in whole or in part, or by purchasing shares in the open market.
In making this determination, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase
shares through the over-allotment option.
Naked
short sales are short sales made in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing shares in the open
market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common shares in the open market that could
adversely affect investors who purchased in this offering.
The
underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the
representatives have repurchased shares sold by or for the account of that underwriter in stabilizing or short covering transactions.
As
a result of these activities, the price of our common shares may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may
be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the NYSE, the TSX, in the over-the-counter market or otherwise.
Affiliations
Certain of the underwriters and their affiliates have in the past provided, are currently providing and may in the future from time to
time provide, investment banking and other financing, trading, banking, research, transfer agent and trustee services to us or our subsidiaries, for which they have in the past received, and may
currently or in the future receive, customary fees and expenses.
The Representatives have provided and are providing services with respect to the Plan of Arrangement pursuant to which they were and are to be paid customary fees
upon the public
announcement of the Plan of Arrangement and upon consummation thereof, if completed. We agreed to pay TD Securities Inc. and Morgan Stanley & Co. LLC $1.9 million and
$1.0 million, respectively, upon public announcement of the Plan of Arrangement and an additional fee of $5.6 million and $4.0 million, respectively, if the Plan of Arrangement is
completed.
In addition, the Representatives have jointly committed to provide to us a $625 million credit facility to fund the cash consideration required under the Plan of
Arrangement, for
which the Representatives will receive customary compensation.
81
Table of Contents
NOTICE TO INVESTORS
Notice to Prospective Investors in the European Economic Area
In relation to each Member State of the European Economic Area, or EEA, which has implemented the Prospectus Directive (each, a
"Relevant Member State"), with effect from, and including, the date on which the Prospectus Directive is implemented in that Relevant Member State (the "Relevant Implementation Date"), an offer to the
public of our securities which are the subject of the offering contemplated by this prospectus may not be made in that Relevant Member State, except that, with effect from, and including, the Relevant
Implementation Date, an offer to the public in that Relevant Member State of our securities may be made at any time under the following exemptions under the Prospectus Directive, if they have been
implemented in that Relevant Member State:
-
a)
-
to
legal entities which are authorized or regulated to operate in the financial markets, or, if not so authorized or regulated, whose corporate purpose is
solely to invest in our securities;
-
b)
-
to
any legal entity which has two or more of: (1) an average of at least 250 employees during the last (or, in Sweden, the last two) financial
year(s); (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last (or, in Sweden,
the last two) annual or consolidated accounts; or
-
c)
-
to
fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of
the representatives for any such offer; or
-
d)
-
in
any other circumstances falling within Article 3(2) of the Prospectus Directive provided that no such offer of our securities shall result in a
requirement for the publication by us or any underwriter or agent of a prospectus pursuant to Article 3 of the Prospectus Directive.
As
used above, the expression "offered to the public" in relation to any of our securities in any Relevant Member State means the communication in any form and by any means of
sufficient information on the terms of the offer and our securities to be offered so as to enable an investor to decide to purchase or subscribe for our securities, as the same may be varied in that
Member State by any measure implementing the Prospectus Directive in that Member State and the expression "Prospectus Directive" means Directive 2003/71/EC and includes any relevant implementing
measure in each Relevant Member State.
The
EEA selling restriction is in addition to any other selling restrictions set out in this prospectus.
Notice to Prospective Investors in the United Kingdom
This prospectus is only being distributed to and is only directed at: (1) persons who are outside the United Kingdom;
(2) investment professionals falling within Article 19(5)
of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the "Order"); or (3) high net worth companies, and other persons to whom it may lawfully be communicated,
falling within Article 49(2)(a) to (d) of the Order (all such persons falling within (1)-(3) together being referred to as "relevant persons"). The shares are only available to, and any
invitation, offer or agreement to subscribe, purchase or otherwise acquire such shares will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on
this prospectus or any of its contents.
82
Table of Contents
Notice to Prospective Investors in Switzerland
The Prospectus does not constitute an issue prospectus pursuant to Article 652a or Article 1156 of the Swiss Code of
Obligations ("CO") and the shares will not be listed on the SIX Swiss Exchange. Therefore, the Prospectus may not comply with the disclosure standards of the CO and/or the listing rules (including any
prospectus schemes) of the SIX Swiss Exchange. Accordingly, the shares may not be offered to the public in or from Switzerland, but only to a selected and limited circle of investors, which do not
subscribe to the shares with a view to distribution.
Notice to Prospective Investors in Australia
This prospectus is not a formal disclosure document and has not been, nor will be, lodged with the Australian Securities and
Investments Commission. It does not purport to contain all information that an investor or their professional advisers would expect to find in a prospectus or other disclosure document (as defined in
the Corporations Act 2001 (Australia)) for the purposes of Part 6D.2 of the Corporations Act 2001 (Australia) or in a product disclosure statement for the purposes of Part 7.9 of the
Corporations Act 2001 (Australia), in either case, in relation to the securities.
The
securities are not being offered in Australia to "retail clients" as defined in sections 761G and 761GA of the Corporations Act 2001 (Australia). This offering is being made
in Australia solely to "wholesale clients" for the purposes of section 761G of the Corporations Act 2001 (Australia) and, as such, no prospectus, product disclosure statement or other
disclosure document in relation to the securities has been, or will be, prepared.
This
prospectus does not constitute an offer in Australia other than to wholesale clients. By submitting an application for our securities, you represent and warrant to us that you are
a wholesale client for the purposes of section 761G of the Corporations Act 2001 (Australia). If any recipient of this prospectus is not a wholesale client, no offer of, or invitation to apply
for, our securities shall be deemed to be made to such recipient and no applications for our securities will be accepted from such recipient. Any offer to a recipient in Australia, and any agreement
arising from acceptance of such offer, is personal and may only be accepted by the recipient. In addition, by applying for our securities you undertake to us that, for a period of 12 months
from the date of issue of the securities, you will not transfer any interest in the securities to any person in Australia other than to a wholesale client.
Notice to Prospective Investors in Hong Kong
Our securities may not be offered or sold in Hong Kong, by means of this prospectus or any document other than (i) to
"professional investors" within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder, or (ii) in circumstances which do not constitute
an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or (iii) in other circumstances which do not result in the document being a "prospectus" within
the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong). No advertisement, invitation or document relating to our securities may be issued or may be in the possession of any person for the
purpose of issue (in each case whether in Hong Kong or elsewhere) which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to
do so under the securities laws of Hong Kong) other than with respect to the securities which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional
investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.
Notice to Prospective Investors in Japan
Our securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the Financial
Instruments and Exchange Law) and our securities will not be
83
Table of Contents
offered
or sold, directly or indirectly, in Japan, or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other
entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan, or to a resident of Japan, except pursuant to an exemption from the
registration
requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.
Notice to Prospective Investors in Singapore
This document has not been registered as a prospectus with the Monetary Authority of Singapore and in Singapore, the offer and sale of
our securities is made pursuant to exemptions provided in sections 274 and 275 of the Securities and Futures Act, Chapter 289 of Singapore ("SFA"). Accordingly, this prospectus and any
other document or material in connection with the offer or sale, or invitation for subscription or purchase, of our securities may not be circulated or distributed, nor may our securities be offered
or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor as defined in
Section 4A of the SFA pursuant to Section 274 of the SFA, (ii) to a relevant person as defined in section 275(2) of the SFA pursuant to Section 275(1) of the SFA, or
any person pursuant to Section 275(1A) of the SFA, and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with
the conditions of, any other applicable provision of the SFA, in each case subject to compliance with the conditions (if any) set forth in the SFA. Moreover, this document is not a prospectus as
defined in the SFA. Accordingly, statutory liability under the SFA in relation to the content of prospectuses would not apply. Prospective investors in Singapore should consider carefully whether an
investment in our securities is suitable for them.
Where
our securities are subscribed or purchased under Section 275 of the SFA by a relevant person which is:
-
(a)
-
by
a corporation (which is not an accredited investor as defined in Section 4A of the SFA) the sole business of which is to hold investments and the
entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or
-
(b)
-
for
a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual
who is an accredited investor, shares of that corporation or the beneficiaries' rights and interest (howsoever described) in that trust shall not be transferable for six months after that corporation
or that trust has acquired the shares under Section 275 of the SFA, except:
-
(i)
-
to
an institutional investor (for corporations under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or
any person pursuant to an offer that is made on terms that such shares of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its
equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the
conditions, specified in Section 275 of the SFA;
-
(ii)
-
where
no consideration is given for the transfer; or
-
(iii)
-
where
the transfer is by operation of law.
In
addition, investors in Singapore should note that the securities acquired by them are subject to resale and transfer restrictions specified under Section 276 of the SFA, and
they, therefore, should seek their own legal advice before effecting any resale or transfer of their securities.
84
Table of Contents
LEGAL MATTERS
Certain legal matters relating to the issue and sale of the common shares offered hereby will be passed upon by Goodmans on behalf of
Atlantic Power and by Blake, Cassels & Graydon LLP on behalf of the underwriters. Goodwin Procter LLP is acting as U.S. counsel to Atlantic Power in this offering and Paul, Weiss,
Rifkind, Wharton & Garrison LLP is acting as U.S. counsel for the underwriters.
EXPERTS
The consolidated financial statements and financial statement schedule of Atlantic Power as of December 31, 2010 and 2009 and
for each of the years in the three-year period ended December 31, 2010 appearing in Atlantic Power's Annual Report on Form 10-K (including the schedule appearing
therein) have been incorporated by reference herein in reliance upon the reports of the United States and Canadian firms of KPMG LLP, independent registered public accounting firms,
incorporated by reference herein, and upon the authority of said firms as experts in accounting and auditing.
The
financial statements of Chambers Cogeneration Limited Partnership as of December 31, 2010, and for the year then ended incorporated in this registration statement by
reference to Atlantic Power's Annual Report on Form 10-K for the year ended December 31, 2010, have been so incorporated in reliance on the report of
PricewaterhouseCoopers LLP, independent auditors, given on the authority of said firm as experts in auditing and accounting.
The
consolidated financial statements of CPILP as of December 31, 2010 and 2009 and for each of the years in the three year period ended December 31, 2010 have been
included in this registration statement in reliance on the report of the Canadian firm of KPMG LLP, an independent registered public accounting firm, and upon the authority of said firm as
experts in auditing and accounting.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement under the Securities Act that registers the offer and sale of the securities
offered by this prospectus. This prospectus is part of the registration statement, but the registration statement, including the accompanying exhibits included or incorporated by reference therein,
contains additional relevant information about us.
We
are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document we file, including the
registration statement containing this prospectus and the registration statement with respect to the registration of the common shares, at the SEC's Public Reference Room at 100 F Street, N.E.,
Washington, D.C. 20549. You may call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Our SEC filings are also
available to the public from the SEC's website at
http://www.sec.gov
and on our website at
http://www.atlanticpower.com
. We have included the SEC's web
address and our web address as inactive textual references only. Our website is
not incorporated into, and does not constitute a part of, this prospectus or any other report or documents we file with or furnish to the SEC.
85
Table of Contents
INCORPORATION BY REFERENCE OF CERTAIN DOCUMENTS
We are "incorporating by reference" into this prospectus certain information we file with the SEC, which means that we are disclosing
important information to you by referring you to those documents. The documents that we incorporate disclose important information that each prospective purchaser should consider when deciding whether
to invest in the common shares. We incorporate the documents listed below:
-
-
our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on March 18,
2011;
-
-
our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011,
respectively, filed with the SEC on May 11, 2011 and August 12, 2011, respectively;
-
-
our annual Proxy Statement on Schedule 14A relating to our annual meeting of shareholders, filed with the SEC on
May 2, 2011 (with respect to those portions incorporated by reference into our 2010 Annual Report on Form 10-K); and
-
-
our Current Reports on Form 8-K filed with the SEC on May 4, 2011, June 16, 2011, June 20,
2011, June 24, 2011, July 15, 2011 and August 2, 2011 (as amended by our Current Report on Form 8-K/A filed on August 5, 2011), except, in any such cases, the
portions furnished and not filed pursuant to Item 7.01 or otherwise.
You
may request a copy of these filings, and any exhibits we have specifically incorporated by reference as an exhibit in this prospectus, at no cost by writing or telephoning us at the
following: Atlantic Power Corporation, 200 Clarendon Street, Floor 25, Boston, Massachusetts 02116. Our telephone number is (617) 977-2400.
86
Table of Contents
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS OF CPILP
F-1
Table of Contents
|
|
|
|
|
|
|
|
|
KPMG LLP
Chartered Accountants
10125 - 102 Street
Edmonton AB T5J 3V8
Canada
|
|
Telephone
Fax
Internet
|
|
(780) 429-7300
(780) 429-7379
www.kpmg.ca
|
INDEPENDENT AUDITORS' REPORT
To
the Partners of Capital Power Income L.P.
We
have audited the accompanying consolidated balance sheets of Capital Power Income L.P. and subsidiaries ("the Partnership") as of December 31, 2010, 2009, and 2008 and
the related consolidated statements of income and loss, partners' equity, comprehensive loss and cash flows for each year in the three-year period ended December 31, 2010. These
consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We
conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing
audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no
such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In
our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31,
2010, 2009, and 2008 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010 in conformity with Canadian
generally accepted accounting principles.
Accounting
principles generally accepted in Canada vary in certain significant respects from U.S. generally accepted accounting principles. Information relating to the nature and effect
of such differences is presented in note 27 to the consolidated financial statements.
"signed KPMG"
KPMG LLP
Edmonton, Canada
March 2,
2011, except as to notes 27 and 28, which are as of July 25, 2011
F-2
Table of Contents
Capital Power Income L.P.
CONSOLIDATED STATEMENTS OF INCOME AND LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
|
(In millions of dollars except
units and per unit amounts)
|
|
Revenues
|
|
$
|
532.4
|
|
$
|
586.5
|
|
$
|
499.3
|
|
Cost of fuel
|
|
|
230.7
|
|
|
271.4
|
|
|
288.8
|
|
Operating and maintenance expense
|
|
|
114.2
|
|
|
103.4
|
|
|
99.1
|
|
|
|
|
|
|
|
|
|
|
|
|
187.5
|
|
|
211.7
|
|
|
111.4
|
|
Other costs
|
|
|
|
|
|
|
|
|
|
|
Depreciation, amortization and accretion (Note 5)
|
|
|
98.3
|
|
|
93.3
|
|
|
88.3
|
|
Financial charges and other, net (Note 9)
|
|
|
40.1
|
|
|
46.4
|
|
|
70.7
|
|
Management and administration
|
|
|
13.9
|
|
|
15.2
|
|
|
20.2
|
|
Asset impairment charge (Note 8)
|
|
|
|
|
|
|
|
|
24.1
|
|
|
|
|
|
|
|
|
|
|
|
|
152.3
|
|
|
154.9
|
|
|
203.3
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations before income tax and preferred share dividends
|
|
|
35.2
|
|
|
56.8
|
|
|
(91.9
|
)
|
Income tax recovery (Note 14)
|
|
|
9.4
|
|
|
8.9
|
|
|
31.4
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations before preferred share dividends
|
|
|
44.6
|
|
|
65.7
|
|
|
(60.5
|
)
|
Preferred share dividends of a subsidiary company (Note 11)
|
|
|
14.1
|
|
|
7.9
|
|
|
6.6
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
|
30.5
|
|
|
57.8
|
|
|
(67.1
|
)
|
Loss from discontinued operations (Note 25)
|
|
|
|
|
|
(0.2
|
)
|
|
(0.7
|
)
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
30.5
|
|
$
|
57.6
|
|
$
|
(67.8
|
)
|
|
|
|
|
|
|
|
|
Net income (loss) per unit from continuing operations
|
|
$
|
0.55
|
|
$
|
1.07
|
|
$
|
(1.24
|
)
|
Net loss per unit from discontinued operations
|
|
|
|
|
|
|
|
|
(0.01
|
)
|
Net income (loss) per unit
|
|
$
|
0.55
|
|
$
|
1.07
|
|
$
|
(1.26
|
)
|
|
|
|
|
|
|
|
|
Weighted average units outstanding
(millions)
|
|
|
55.0
|
|
|
53.9
|
|
|
53.9
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
F-3
Table of Contents
Capital Power Income L.P.
CONSOLIDATED STATEMENTS OF CASH FLOW
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
|
(In millions of dollars)
|
|
Operating activities
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
$
|
30.5
|
|
$
|
57.8
|
|
$
|
(67.1
|
)
|
Items not affecting cash:
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, amortization and accretion
|
|
|
98.3
|
|
|
93.3
|
|
|
88.3
|
|
|
Asset impairment charge
|
|
|
|
|
|
|
|
|
24.1
|
|
|
Future income tax recovery
|
|
|
(13.9
|
)
|
|
(12.4
|
)
|
|
(34.4
|
)
|
|
Fair value changes on derivative instruments
|
|
|
3.6
|
|
|
(6.2
|
)
|
|
98.4
|
|
|
Unrealized foreign exchange losses
|
|
|
|
|
|
0.3
|
|
|
26.2
|
|
|
Other
|
|
|
6.6
|
|
|
10.0
|
|
|
8.7
|
|
|
|
|
|
|
|
|
|
|
|
|
125.1
|
|
|
142.8
|
|
|
144.2
|
|
Change in non-cash working capital (Note 16)
|
|
|
(7.3
|
)
|
|
(8.3
|
)
|
|
13.3
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities of continuing operations
|
|
|
117.8
|
|
|
134.5
|
|
|
157.5
|
|
|
Cash (used in) provided by operating activities of discontinued operations
|
|
|
|
|
|
(2.8
|
)
|
|
2.7
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
117.8
|
|
|
131.7
|
|
|
160.2
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant and equipment and other assets
|
|
|
(28.3
|
)
|
|
(100.7
|
)
|
|
(40.0
|
)
|
Change in non-cash working capital
|
|
|
(7.2
|
)
|
|
4.2
|
|
|
2.7
|
|
Dividends from equity investment
|
|
|
|
|
|
1.3
|
|
|
3.2
|
|
Acquisition of Morris Cogeneration LLC (Note 24)
|
|
|
|
|
|
|
|
|
(90.7
|
)
|
Acquisition of equity investment
|
|
|
|
|
|
(8.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities of continuing operations
|
|
|
(35.5
|
)
|
|
(104.0
|
)
|
|
(124.8
|
)
|
|
Cash provided by (used in) investing activities of discontinued operations
|
|
|
|
|
|
11.6
|
|
|
(3.5
|
)
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(35.5
|
)
|
|
(92.4
|
)
|
|
(128.3
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
|
|
|
|
|
|
|
|
Distributions paid
|
|
|
(69.5
|
)
|
|
(127.7
|
)
|
|
(135.8
|
)
|
Net borrowings under credit facilities
|
|
|
8.1
|
|
|
1.8
|
|
|
85.7
|
|
Proceeds from preferred share offering (Note 11)
|
|
|
|
|
|
100.0
|
|
|
|
|
Long-term debt repaid
|
|
|
(1.4
|
)
|
|
(1.3
|
)
|
|
(1.1
|
)
|
Issue costs
|
|
|
(0.5
|
)
|
|
(4.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in financing activities
|
|
|
(63.3
|
)
|
|
(31.3
|
)
|
|
(51.2
|
)
|
|
|
|
|
|
|
|
|
Foreign exchange gains (losses) on cash held in a foreign currency
|
|
|
(1.0
|
)
|
|
(1.5
|
)
|
|
2.2
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
18.0
|
|
|
6.5
|
|
|
(17.1
|
)
|
Cash and cash equivalents, beginning of year
|
|
|
9.5
|
|
|
3.0
|
|
|
20.1
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year
|
|
$
|
27.5
|
|
$
|
9.5
|
|
$
|
3.0
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow information
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid
|
|
$
|
5.6
|
|
$
|
2.4
|
|
$
|
6.7
|
|
Interest paid
|
|
$
|
38.0
|
|
$
|
43.6
|
|
$
|
37.1
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
F-4
Table of Contents
Capital Power Income L.P.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
|
(In millions of dollars)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
27.5
|
|
$
|
9.5
|
|
$
|
3.0
|
|
|
Accounts receivable
|
|
|
52.5
|
|
|
51.8
|
|
|
60.6
|
|
|
Inventories (Note 4)
|
|
|
19.5
|
|
|
24.6
|
|
|
23.2
|
|
|
Prepaids and other
|
|
|
4.0
|
|
|
4.5
|
|
|
5.0
|
|
|
Derivative assets (Note 15)
|
|
|
10.4
|
|
|
7.8
|
|
|
22.8
|
|
|
Future income taxes (Note 14)
|
|
|
7.1
|
|
|
1.9
|
|
|
2.3
|
|
|
Current assets of discontinued operations
|
|
|
|
|
|
|
|
|
2.3
|
|
|
|
|
|
|
|
|
|
|
|
|
121.0
|
|
|
100.1
|
|
|
119.2
|
|
Property, plant and equipment
(Note 5)
|
|
|
994.1
|
|
|
1,064.7
|
|
|
1,106.0
|
|
Power purchase arrangements
(Note 6)
|
|
|
290.0
|
|
|
330.4
|
|
|
408.6
|
|
Goodwill
(Note 7)
|
|
|
45.0
|
|
|
47.6
|
|
|
55.1
|
|
Derivative assets
(Note 15)
|
|
|
29.7
|
|
|
31.8
|
|
|
27.1
|
|
Future income taxes
(Note 14)
|
|
|
41.2
|
|
|
35.0
|
|
|
16.8
|
|
Other assets
(Note 8)
|
|
|
62.8
|
|
|
58.5
|
|
|
64.4
|
|
Long-term assets of discontinued operations
(Note 25)
|
|
|
|
|
|
|
|
|
12.0
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,583.8
|
|
$
|
1,668.1
|
|
$
|
1,809.2
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
52.9
|
|
$
|
59.6
|
|
$
|
70.3
|
|
|
Distributions payable
|
|
|
8.2
|
|
|
7.9
|
|
|
33.9
|
|
|
Long-term debt due within one year (Note 9)
|
|
|
|
|
|
1.4
|
|
|
1.3
|
|
|
Derivative liabilities (Note 15)
|
|
|
21.1
|
|
|
2.9
|
|
|
13.0
|
|
|
Current liabilities of discontinued operations
|
|
|
|
|
|
|
|
|
1.2
|
|
|
Future income taxes (Note 14)
|
|
|
|
|
|
3.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82.2
|
|
|
75.6
|
|
|
119.7
|
|
Long-term debt
(Note 9)
|
|
|
704.5
|
|
|
719.4
|
|
|
798.5
|
|
Derivative liabilities
(Note 15)
|
|
|
81.9
|
|
|
36.4
|
|
|
38.5
|
|
Other liabilities
(Note 10)
|
|
|
37.1
|
|
|
34.8
|
|
|
33.3
|
|
Long-term liabilities of discontinued operations
(Note 25)
|
|
|
|
|
|
|
|
|
4.2
|
|
Future income taxes
(Note 14)
|
|
|
50.7
|
|
|
62.7
|
|
|
60.7
|
|
Preferred shares issued by a subsidiary company
(Note 11)
|
|
|
219.7
|
|
|
219.7
|
|
|
122.0
|
|
|
|
|
|
|
|
|
|
Partners' equity
|
|
|
407.7
|
|
|
519.5
|
|
|
632.3
|
|
Commitments
(Note 23)
|
|
|
|
|
|
|
|
|
|
|
Subsequent event
(Note 28)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,583.8
|
|
$
|
1,668.1
|
|
$
|
1,809.2
|
|
|
|
|
|
|
|
|
|
Approved by CPI Income Services Ltd., as General Partner of Capital Power Income L.P.
|
|
|
"signed Brian Vaasjo"
|
|
"signed Brian Felesky"
|
Brian T. Vaasjo
|
|
Brian A. Felesky
|
Director and Chairman of the Board
|
|
Director and Chairman of the Audit Committee
|
See accompanying notes to the consolidated financial statements.
F-5
Table of Contents
Capital Power Income L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
|
(In millions of dollars)
|
|
Partnership capital
(Note 12)
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
$
|
1,200.6
|
|
$
|
1,197.1
|
|
$
|
1,197.1
|
|
Partnership units issued pursuant to distribution reinvestment plan
|
|
|
27.0
|
|
|
3.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
1,227.6
|
|
$
|
1,200.6
|
|
$
|
1,197.1
|
|
|
|
|
|
|
|
|
|
Deficit
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year:
|
|
|
(543.7
|
)
|
|
(496.1
|
)
|
|
(296.5
|
)
|
Net income (loss)
|
|
|
30.5
|
|
|
57.6
|
|
|
(67.8
|
)
|
Distributions
|
|
|
(96.9
|
)
|
|
(105.2
|
)
|
|
(135.8
|
)
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
(610.1
|
)
|
$
|
(543.7
|
)
|
$
|
(500.1
|
)
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss
(Note 13)
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
$
|
(137.4
|
)
|
$
|
(64.7
|
)
|
$
|
5.1
|
|
Other comprehensive loss
|
|
|
(72.4
|
)
|
|
(72.7
|
)
|
|
(69.8
|
)
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
(209.8
|
)
|
$
|
(137.4
|
)
|
$
|
(64.7
|
)
|
|
|
|
|
|
|
|
|
Total of deficit and accumulated other comprehensive loss
|
|
$
|
(819.9
|
)
|
$
|
(681.1
|
)
|
$
|
(564.8
|
)
|
|
|
|
|
|
|
|
|
Partners' equity
|
|
$
|
407.7
|
|
$
|
519.5
|
|
$
|
632.3
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
F-6
Table of Contents
Capital Power Income L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
|
(In millions of dollars)
|
|
Net income (loss)
|
|
$
|
30.5
|
|
$
|
57.6
|
|
$
|
(67.8
|
)
|
Other comprehensive income (loss), net of income taxes
|
|
|
|
|
|
|
|
|
|
|
Losses on translating net assets of self-sustaining foreign operations
(1)
|
|
|
(27.4
|
)
|
|
(65.9
|
)
|
|
(66.0
|
)
|
Amortization of deferred gains on derivative instruments de-designated as cash flow hedges to income
(2)
|
|
|
(0.5
|
)
|
|
(0.4
|
)
|
|
(3.8
|
)
|
Unrealized losses on derivative instruments designated as cash flow hedges
(3)
|
|
|
(46.7
|
)
|
|
(6.7
|
)
|
|
|
|
Ineffective portion of cash flow hedges reclassified to net income
(2)
|
|
|
2.2
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(72.4
|
)
|
|
(72.7
|
)
|
|
(69.8
|
)
|
|
|
|
|
|
|
|
|
Comprehensive loss
|
|
$
|
(41.9
|
)
|
$
|
(15.1
|
)
|
$
|
(137.6
|
)
|
|
|
|
|
|
|
|
|
-
(1)
-
Includes
income tax expense of $0.6 million (2009 and 2008$nil).
-
(2)
-
Net
of income tax of $nil.
-
(3)
-
Net
of income tax of $14.6 million (2009$2.5 million; 2008$nil).
See accompanying notes to the consolidated financial statements.
F-7
Table of Contents
Capital Power Income L.P.
Notes to the Consolidated Financial Statements
Note 1. Description of the Partnership
Capital Power Income L.P. (the Partnership) is a limited partnership created under the laws of the Province of Ontario pursuant to a Partnership Agreement dated
March 27,
1997, as amended and restated November 4, 2009. The Partnership commenced operations on June 18, 1997 and currently has independent power generating facilities in British Columbia,
Ontario, California, Colorado, Illinois, New Jersey, New York, North Carolina and Washington State.
CPI
Income Services Ltd., the general partner of the Partnership (the General Partner), has the responsibility for overseeing the management of the Partnership and distributions
to unitholders. The General Partner is a wholly owned subsidiary of CPI Investments Inc. (Investments). Capital Power Corporation (collectively with its subsidiaries, CPC, unless otherwise
indicated) indirectly owns all of the 49 voting, participating shares of Investments and EPCOR Utilities Inc. (EPCOR) indirectly owns all of the 51 voting, non-participating shares
of Investments. The General Partner has engaged certain other subsidiaries of CPC (collectively herein, the Manager) to perform management and administrative services on behalf of the Partnership and
to operate and maintain the power plants pursuant to management and operations agreements.
Note 2. Significant accounting policies
Basis of presentation
The consolidated financial statements of the Partnership have been prepared by the management of the General Partner in accordance
with Canadian generally accepted accounting principles (GAAP) and include the accounts of the Partnership and of its subsidiaries. All significant intercompany transactions and balances have been
eliminated.
Measurement uncertainty
The preparation of the Partnership's financial statements in accordance with GAAP requires management to make estimates that affect
the reported amounts of revenues, expenses, assets and liabilities as well as the disclosure of contingent assets and liabilities at the financial statement date. The Partnership uses the most current
information available and exercises careful judgment in making these estimates and assumptions.
For
determining asset impairments, recording financial assets and liabilities and for certain disclosures, the Partnership is required to estimate the fair value of certain assets or
obligations. Estimates of fair value may be based on readily determinable market values, depreciated replacement cost or discounted cash flow techniques employing estimated future cash flows based on
a number of assumptions and using an appropriate discount rate.
Adjustments
to previous estimates, which may be material, will be recorded in the period they become known.
Revenue recognition
Power purchase arrangements, steam purchase arrangements and energy services agreements (collectively referred to as power purchase
arrangements or PPAs) are long-term contracts to sell power and steam from the Partnership on a predetermined basis. As explained in "Power purchase arrangements containing a lease," PPAs
may be classified as a lease (either operating or capital) and the income is recognized in revenue according to lease revenue recognition standards. For those PPAs
F-8
Table of Contents
Capital Power Income L.P.
Notes to the Consolidated Financial Statements (Continued)
Note 2. Significant accounting policies (Continued)
that
are not considered to contain a lease, income earned on the PPA is recognized in revenue as follows: Revenue from the sales of electricity, steam and natural gas are recognized on delivery or
availability for delivery under take or pay contracts. Revenue from certain long-term contracts with fixed payments is recognized at the lower of (1) the megawatt hours (MWhs) made
available during the period multiplied by the billable contract price per MWh and (2) an amount determined by the MWhs made available during the period multiplied by the average price per MWh
over the term of the contract from the date of acquisition. Any excess of the current period contract price over the average price is recorded as deferred revenue.
Gains
and losses on non-financial derivative instruments settlements are recorded in revenues or cost of fuel, as appropriate.
Financial instruments
Financial assets are identified and classified as either available for sale, held for trading, held to maturity or loans and
receivables. Financial liabilities are classified as either held for trading or other liabilities. Initially, all financial assets and financial liabilities are recorded on the balance sheet at fair
value with subsequent measurement determined by the classification of each financial asset and liability.
Financial
assets and financial liabilities held for trading are measured at fair value with the changes in fair value reported in net income. Financial assets held to maturity, loans
and receivables and financial liabilities other than those held for trading are measured at amortized cost. Available for sale financial assets are measured at fair value with changes in fair value
reported in other comprehensive income until the financial asset is disposed of or becomes impaired. Investments in equity instruments classified as available for sale that do not have quoted market
prices in an active market are measured at cost.
Upon
initial recognition, the Partnership may designate financial instruments as held for trading when such financial instruments have a reliably determinable fair value and where doing
so eliminates or significantly reduces a measurement or recognition inconsistency that would otherwise arise from measuring assets and liabilities or recognising gains and losses on them on a
different basis. The Partnership has designated its cash and cash equivalents as held for trading. All other non-derivative financial assets not meeting the Partnership's criteria for
designation as held for trading are classified as available for sale, loans and receivables or held to maturity.
Financial
assets purchased or sold, where the contract requires the asset to be delivered within an established timeframe, are recognized on a settlement date basis.
Transaction
costs on financial assets and liabilities classified as other than held for trading are capitalized and amortized over the expected life of the instrument, based on
contractual cash flows, using the effective interest method (EIM). The EIM calculates the amortized cost of a financial asset or liability and allocates the interest income or expense over the term of
the financial asset or liability using an effective interest rate.
Derivative instruments and hedging activities
To reduce its exposure to movements in energy commodity prices, interest rate changes and foreign currency exchange rates, the
Partnership uses various risk management techniques including the
F-9
Table of Contents
Capital Power Income L.P.
Notes to the Consolidated Financial Statements (Continued)
Note 2. Significant accounting policies (Continued)
use
of derivative instruments. Derivative instruments may include forward contracts, fixed-for-floating swaps and option contracts. Such instruments are used to establish a
fixed price for an energy commodity, a cash flow denominated in a foreign currency or an interest-bearing obligation. All derivative instruments, including embedded derivatives, are recorded at fair
value on the balance sheet as derivative instruments assets or derivative instruments liabilities except for embedded derivatives instruments that are clearly and closely linked to their host contract
and the combined instrument is not measured at fair value. Any contract to buy or sell a commodity that was entered into and continues to be held for the purpose of the receipt or delivery of that
commodity in accordance with the Partnership's expected purchase, sale or usage requirements is not treated as a derivative. All changes in the fair value of derivatives are recorded in net income
unless cash flow hedge accounting is used, in which case changes in fair value of the effective portion of the derivatives are recorded in other comprehensive income.
The
Partnership uses non-financial forward delivery contracts and financial contracts-for-differences to manage the Partnership's exposure to
fluctuations in natural gas prices related to obligations arising from its natural gas fired generation facilities. Under the non-financial forward delivery contracts, the Partnership
agrees to purchase natural gas at a fixed price for delivery of a pre-determined quantity under a specified timeframe. Under the financial contracts-for-differences
derivatives, the Partnership agrees to exchange, with creditworthy or adequately secured counterparties, the difference between the variable or indexed price and the fixed price on a notional quantity
of the underlying commodity for a specified timeframe.
Foreign
exchange forward contracts are used by the Partnership to manage foreign exchange exposures, consisting mainly of U.S. dollar exposures, resulting from anticipated transactions
denominated in foreign currencies.
The
Partnership may use forward interest rate or swap agreements and option agreements to manage the impact of fluctuating interest rates on existing debt.
The
Partnership may use hedge accounting when there is a high degree of correlation between the risk in the item designated as being hedged (the hedged item) and the derivative
instrument designated as a hedge (the hedging instrument). The Partnership documents all relationships between hedging instruments and hedged items at the hedge's inception, including its risk
management objectives and its assessment of the effectiveness of the hedging relationship on a retrospective and prospective basis. The Partnership uses cash flow hedges for certain of its anticipated
transactions to reduce exposure to fluctuations in changes in natural gas prices. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative
is recognized in other comprehensive income, while the ineffective portion is recognized in net income. The amounts recognized in accumulated other comprehensive income are reclassified into net
income in the same period or periods in which the hedged item occurs and is recorded in net income or when the hedged item becomes probable of not occurring. The hedging relationship for the natural
gas contracts, which are derivative instruments, was established after the inception of the contracts. The fair value of these contracts at the date of hedge designation is recognized in net income as
the natural gas is delivered under the contracts based on the anticipated fair value of the deliveries at the inception of the hedging relationship.
A
hedging relationship is discontinued if the hedging relationship ceases to be effective, if the hedged item is an anticipated transaction and it is probable that the transaction will
not occur by the
F-10
Table of Contents
Capital Power Income L.P.
Notes to the Consolidated Financial Statements (Continued)
Note 2. Significant accounting policies (Continued)
end
of the originally specified time period, if the Partnership terminates its designation of the hedging relationship or if either the hedged or hedging instrument ceases to exist as a result of its
maturity, expiry, sale, termination or cancellation and is not replaced as part of the Partnership's hedging strategy.
If
a cash flow hedging relationship is discontinued or ceases to be effective, any cumulative gains or losses arising prior to such time are deferred in accumulated other comprehensive
income and recognized in net income in the same period as the hedged item, and subsequent changes in the fair value of the derivative instrument are reflected in net income. If the hedged or hedging
item matures, expires, or is sold, extinguished or terminated and the hedging item is not replaced, any gains or losses associated with the hedging item that were previously recognized in other
comprehensive income are recognized in net income in the same period as the corresponding gains or losses on the hedged item. When it is no longer probable that an anticipated transaction will occur
within the originally determined period and the associated cash flow hedge has been discontinued, any gains or losses associated with the hedging item that were previously recognized in other
comprehensive income are recognized in net income in the period.
When
the conditions for hedge accounting cannot be applied, the changes in fair value of the derivative instruments are recognized as described above. The fair value of derivative
financial instruments reflects changes in the commodity market prices and foreign exchange rates. Fair value is determined based on exchange or over-the-counter price
quotations by reference to bid or asking price as appropriate, in active markets. In illiquid or inactive markets, the Partnership uses appropriate valuation and price modeling techniques commonly
used by market participants to estimate fair value. Fair values determined using valuation models require the use of assumptions concerning the amounts and timing of future cash flows. Fair value
amounts reflect management's best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates, discount rates for time value and
volatility where available. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.
Income taxes
Future income tax assets and liabilities are determined based on temporary differences between the tax basis of assets and liabilities
and their carrying amounts for accounting purposes. Future income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse.
The
Partnership was not subject to Canadian income taxes and accordingly those taxes which are the responsibility of individual partners have not been reflected in these consolidated
financial statements. Certain subsidiaries are taxable and applicable income, withholding and other taxes have been reflected in these consolidated financial statements. However, the Partnership is
subject to Canadian income taxes after 2010. As a result, the Partnership recognized future income taxes based on the estimated net taxable timing differences which are expected to reverse after 2010.
Cash and cash equivalents
Cash and cash equivalents include cash or highly liquid, investment-grade, short-term investments and are recorded at fair
value.
F-11
Table of Contents
Capital Power Income L.P.
Notes to the Consolidated Financial Statements (Continued)
Note 2. Significant accounting policies (Continued)
Inventories
Inventories represent small parts and other consumables and fuel, the majority of which is consumed by the Partnership in provision of
its goods and services, and are valued at the lower of cost and net realizable value. Cost includes the purchase price, transportation costs and other costs to bring the inventories to their present
location and condition. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific
identification of their individual costs. Previous write downs of inventories from cost to net realizable value can be fully or partially reversed if supported by economic circumstances.
Property, plant and equipment
Property, plant and equipment is recorded at cost. Power generation plant and equipment, less estimated residual value, is depreciated
on a straight-line basis over estimated service lives of one to fifty years. Other equipment, which includes the costs of office
furniture, tools and vehicles, is capitalized and depreciated over estimated service lives of three to fifteen years.
Property,
plant and equipment, including asset retirement costs, is periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount
may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to
the asset's fair value is recognized during the period, with a charge to income.
Power purchase arrangements
On acquisition of power plants with existing PPAs in place, the acquired PPAs are capitalized as an intangible asset and included
within the balance sheet as PPAs. The Partnership records acquired PPAs at their fair value and amortizes them over the remaining terms of the contracts.
Power purchase arrangements containing a lease
The Partnership has entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain leases which
convey to the counterparty the right to the use of the Partnership's property, plant and equipment in return for future payments. Such arrangements are classified as either capital or operating
leases. PPAs that transfer substantially all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases.
Finance
income related to leases or arrangements accounted for as direct financing leases is recognized in a manner that produces a constant rate of return on the net investment in the
lease. The net investment is comprised of net minimum lease payments and unearned finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying
value of the leased property. Unearned finance income is deferred and recognized in net income over the lease term.
Payments
received under PPAs classified as direct financing leases are segmented into those for the lease and those for other elements on the basis of their relative fair value.
F-12
Table of Contents
Capital Power Income L.P.
Notes to the Consolidated Financial Statements (Continued)
Note 2. Significant accounting policies (Continued)
Long-term investments
Investments that are not controlled by the Partnership, but over which it has significant influence are accounted for using the equity
method and recorded at original cost and adjusted periodically to recognize the Partnership's proportionate share of the investee's net income or losses after the date of investment, additional
contributions made and dividends received. Other investments are stated at cost. When there has been a decline in value that is other than temporary, the carrying amount of an investment is reduced to
its fair value.
Investment in joint venture
The investment in a joint venture is accounted for using the proportionate consolidation method. Under this method, the Partnership
records its proportionate share of assets, liabilities, revenue and expenses of the joint venture.
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 net assets acquired based on their fair values. Goodwill is not amortized, but rather is tested for impairment at least annually or more frequently if events and circumstances indicate that a
possible impairment may exist. To test for impairment, the fair value of the reporting unit to which the goodwill relates is compared to the carrying amount, including goodwill, of the reporting unit.
If the carrying amount of the reporting unit exceeds its fair value, the fair value of the reporting unit's goodwill is compared with its carrying amount to measure the impairment loss, if any. The
Partnership determines the fair value of a reporting unit using discounted cash flow techniques and estimated future cash flows.
Other intangible assets
Other intangible assets consist primarily of emissions allowances and are amortized over their remaining lives.
Asset retirement obligations
The Partnership recognizes asset retirement obligations for its power plants. The fair value of the liability is added to the carrying
amount of the associated plant asset and depreciated accordingly. The liability is accreted at the end of each period through charges to depreciation, amortization and accretion. The Partnership has
recorded these asset retirement obligations, as it is legally required to remove the facilities at the end of their useful lives and restore the plant sites to their original condition.
Foreign currency translation
The Partnership's functional and presentation currency is the Canadian dollar. The Partnership indirectly owns U.S. subsidiaries which
are self-sustaining foreign operations translated to Canadian dollars using the current rate method. Assets and liabilities are translated at the exchange rate in effect at the balance
sheet date. Revenues and expenses are translated at average exchange rates prevailing during the period. The resulting translation gains and losses are deferred and included in accumulated
F-13
Table of Contents
Capital Power Income L.P.
Notes to the Consolidated Financial Statements (Continued)
Note 2. Significant accounting policies (Continued)
other
comprehensive income until there is a reduction in the Partnership's net investment in the foreign operations. Prior to October 1, 2008, the U.S. subsidiaries were considered integrated
foreign operations.
Net income per unit
Net income per unit is calculated by dividing net income by the weighted average number of units outstanding, including those held by
CPC.
Note 3. Changes in accounting policies
Future accounting changes
International financial reporting standards
The CICA has announced that Canadian reporting issuers will need to begin reporting under IFRS, including comparative figures, by the
first quarter of 2011. In the fourth quarter of 2010, the Audit Committee reviewed accounting policy decisions for all standards that were in effect at the end of the year ended December 31,
2010.
Note 4. Inventories
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
Parts and other consumables
|
|
$
|
9.0
|
|
$
|
14.2
|
|
$
|
7.7
|
|
Fuel
|
|
|
10.5
|
|
|
10.4
|
|
|
15.5
|
|
|
|
|
|
|
|
|
|
|
|
$
|
19.5
|
|
$
|
24.6
|
|
$
|
23.2
|
|
|
|
|
|
|
|
|
|
Inventories expensed in cost of fuel and other plant operating expenses were $47.1 million for the year ended December 31, 2010
(December 31, 2009$21.2 million; December 31, 2008$40.5 million).
No
write-down of inventory or reversal of a previous write-down was recognized in the years ended December 31, 2010, 2009 or 2008. As at
December 31, 2010, 2009 and 2008, no inventories were pledged as security for liabilities.
Note 5. Property, plant and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
|
|
Cost
|
|
Accumulated
Depreciation
|
|
Net Book
Value
|
|
Cost
|
|
Accumulated
Depreciation
|
|
Net Book
Value
|
|
Land
|
|
$
|
4.9
|
|
$
|
|
|
$
|
4.9
|
|
$
|
5.0
|
|
$
|
|
|
$
|
5.0
|
|
Plant and equipment
|
|
|
1,439.2
|
|
|
455.3
|
|
|
983.9
|
|
|
1,421.6
|
|
|
399.0
|
|
|
1,022.6
|
|
Other equipment
|
|
|
10.1
|
|
|
9.3
|
|
|
0.8
|
|
|
11.0
|
|
|
8.7
|
|
|
2.3
|
|
Construction in progress
|
|
|
4.5
|
|
|
|
|
|
4.5
|
|
|
34.8
|
|
|
|
|
|
34.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,458.7
|
|
$
|
464.6
|
|
$
|
994.1
|
|
$
|
1,472.4
|
|
$
|
407.7
|
|
$
|
1,064.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-14
Table of Contents
Capital Power Income L.P.
Notes to the Consolidated Financial Statements (Continued)
Note 5. Property, plant and equipment (Continued)