Mr. James Moore reports
ATLANTIC POWER CORPORATION RELEASES FOURTH QUARTER AND YEAR END 2016 RESULTS
Atlantic Power Corp. has released its financial results for the three months and year ended Dec. 31, 2016. For additional information regarding the Company's 2016 performance, 2017 guidance and certain operational updates, including the status of certain upcoming Power Purchase Agreement (PPA) renewals, please consult Management's prepared remarks and the accompanying presentation, which will be available on the Conference Calls page of the Company's website.
Fourth Quarter 2016 Financial Results (vs. 2015)
-
Cash provided by operating activities of $19.9 million vs. $19.7 million
-
Net loss of $(6.6) million vs. $(88.6) million; 2015 included a $127.8 million impairment charge
-
Project income of $13.3 million vs. project loss of $(104.3) million, including impairment charges
-
Project Adjusted EBITDA of $42.3 million vs. $50.4 million; decline was attributable to lower water flows at Curtis Palmer, lower waste heat, and a scheduled maintenance outage at Oxnard
Full Year 2016 Financial Results (vs. 2015)
-
Cash provided by operating activities of $111.8 million vs. $87.4 million
-
Net loss of $(122.4) million vs. $(62.4) million; both years included significant impairment charges
-
Project income of $10.1 million vs. project loss of $(41.4) million
-
Project Adjusted EBITDA of $202.2 million vs. $208.9 million; results were below the Company's guidance of $205 to $215 million due to lower water flows at Curtis Palmer, lower waste heat and severance costs at three Ontario projects
Other Highlights
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Achieved net reduction in debt in 2016 of $22 million, despite upsizing term loan in April; now have significantly improved debt maturity profile
- Repurchased 8.1 million common shares at an average price of $2.42 since December 2015
-
Reduced total overhead costs by 28% to $23 million in 2016 from $32 million in 2015
-
Initiated 2017 Project Adjusted EBITDA guidance (see page 4 of this release)
-
Expect to repay another $150 million or more of debt in 2017
"During 2016, we refinanced our existing term loan and revolver with a larger $700 million term loan and a $200 million revolver, both with extended maturity dates. We also paid down $288 million of debt, ending the year with a reduction in consolidated debt of approximately $22 million, net of the term loan upsizing. Since year end 2013, we have reduced consolidated debt by more than $800 million and improved our maturity profile considerably. We also made further progress in reducing our interest payments and corporate overhead costs, which are now $60 million and $31 million lower than 2013 levels, respectively," said James J. Moore, Jr., President and CEO of Atlantic Power. "In addition, we have lowered our share count by 6.6% since December 2015 by repurchasing and canceling approximately 8.1 million common shares at an average price of $2.42 per share."
"By strengthening our balance sheet, addressing our near-term maturities and reducing our fixed costs, we believe that we have positioned the Company to take a disciplined approach on renewals of PPAs and withstand an extended downturn in a very cyclical business," said Mr. Moore. "We are enthusiastic about our strengthened financial position, expected 2017 operating cash flow and the uses of capital that we have available which are consistent with our objective of increasing intrinsic value per share."
Mr. Moore continued, "After two years of dramatic change, the Company is now in a position to pay down an additional $150 million or more of debt in 2017; continue to repurchase shares when they trade at a significant discount to our estimates of intrinsic value per share, as they do today; work toward PPA renewals without financial pressure to transact quickly in a down market, and begin to implement a growth strategy, with efforts currently focused on industrial customers."
Selected Financial Results
(in millions of U.S. dollars, except as otherwise stated)
Three months ended December 31, Twelve months ended December 31,
2016 2015 2016 2015
Financial Results
Project revenue $93.4 $98.4 $399.2 $420.2
Project income (loss) 13.3 (104.3) 10.1 (41.4)
Net loss attributable
to Atlantic Power (6.6) (88.6) (122.4) (62.4)
Cash provided by
operating activities 19.9 19.7 111.8 87.4
Project Adjusted EBITDA 42.3 50.4 202.2 208.9
All amounts are in U.S. dollars and are approximate unless otherwise indicated.
Project Adjusted EBITDA is not a recognized measure under generally accepted
accounting principles in the United States ("GAAP") and does not have a
standardized meaning prescribed by GAAP; therefore, this measure may not be
comparable to similar measures presented by other companies. Please refer to
"Non-GAAP Disclosures" beginning on page 13 of this news release for an
explanation and a reconciliation of "Project Adjusted EBITDA" as used in this
news release to project income (loss), the most directly comparable measure
on a GAAP basis, and Net loss. The Wind Projects were sold in June 2015 and
are included in discontinued operations for the three months and year ended
December 31, 2015. Results of the Wind Projects are excluded from Project
revenue, Project income (loss) and Project Adjusted EBITDA as shown in Table
1 and as discussed below but are included in Net loss attributable to Atlantic
Power Corporation and Cash provided by operating activities as shown in Table 1.
Please see page 13 for a summary of results of discontinued operations. The
Wind Projects consisted of five operating wind projects in Idaho and Oklahoma
nd representing 521 MW net ownership: Goshen (12.5% economic interest), Idaho
Wind (27.6% economic interest), Meadow Creek (100% economic interest), Rockland
Wind Farm (50% economic interest, but consolidated on a 100% basis) and Canadian
Hills (99% economic interest).
Financial Results
Three Months Ended December 31, 2016
The primary operational factors that affected the Company's results for the fourth quarter of 2016 included lower water flows at Curtis Palmer, lower waste heat at the Company's Ontario plants, a scheduled maintenance outage at Oxnard, turbine maintenance expense at Kapuskasing and North Bay and severance cost at Kapuskasing, North Bay and Nipigon. These negative drivers were partially offset by higher water flows at Mamquam.
Net loss attributable to Atlantic Power Corporation for the fourth quarter of 2016 of $(6.6) million included a $1.2 million non-cash impairment of the remaining goodwill at Moresby Lake and a $12.7 million charge for the non-cash accelerated amortization of intangible assets related to the PPAs at Kapuskasing and North Bay, which were terminated early as described in the Company's January 9, 2017 press release. Net loss for the fourth quarter of 2015 of $(88.6) million included a $127.8 million non-cash impairment of long-lived assets and goodwill, primarily at Williams Lake. The $82.0 million reduction in net loss in 2016 was primarily attributable to the reduction in impairment expense and an increase in the fair value of derivative instruments, partially offset by higher amortization expense, a reduction in largely unrealized foreign exchange gain, lower income tax benefit and the operational factors described previously.
Project income for the fourth quarter of 2016 was $13.3 million versus project loss for the year-ago period of $(104.3) million. The $117.6 million improvement from project loss in 2015 to project income in 2016 was primarily attributable to lower impairment expense and an increase in the fair value of derivative instruments as described previously, partially offset by higher amortization expense and the operational factors described previously.
Project Adjusted EBITDA for the fourth quarter of 2016 was $42.3 million, a decline of $8.1 million from $50.4 million in the year-ago period. Primary contributors to the decline were a $3.3 million reduction at Curtis Palmer due to lower water flows; a $5.0 million decrease at Kapuskasing and North Bay due to lower waste heat, turbine maintenance expense, and severance expense; and a $2.2 million decrease at Oxnard due to the scheduled maintenance outage. Results for Kapuskasing, Nipigon and North Bay included $1.1 million of severance expense related to the revised operational status of and contractual arrangements for these plants announced in the Company's January 9, 2017 press release. These decreases were partially offset by a $2.2 million increase at Mamquam due to favorable water flows and lower maintenance expense.
Cash provided by operating activities of $19.9 million was in line with the $19.7 million reported for the year-ago period. Significant uses of cash provided by operating activities during the fourth quarter of 2016 included $15.0 million of term loan amortization, $3.0 million of project debt amortization and $2.1 million of preferred dividend payments.
Year Ended December 31, 2016
The primary operational factors that affected the Company's results for the year ended December 31, 2016 included an extended planned outage at Morris in the third quarter, lower water flows at Curtis Palmer, lower waste heat and fuel price escalation at some of the Company's Ontario plants, a contractual price adjustment at Calstock, and a scheduled maintenance outage at Oxnard. These negative drivers were partially offset by the absence of an outage at Manchief (compared to 2015) and higher water flows at Mamquam.
Net loss attributable to Atlantic Power Corporation of $(122.4) million for the year ended December 31, 2016 increased $60.0 million from a net loss of $(62.4) million in 2015. The increased net loss was the result of a $32.8 million non-cash write-off of deferred financing costs in the second quarter attributable to the Company's refinancing activities (included in interest expense), $12.7 million of accelerated amortization expense in the fourth quarter related to the Kapuskasing and North Bay PPAs, a $13.9 million largely unrealized foreign exchange loss as compared to a $60.3 million unrealized foreign exchange gain in 2015, and the absence of income from the discontinued Wind business ($19.5 million in 2015). The operational factors described previously had a net negative impact. These negative factors affecting the 2016 net loss were partially offset by reduced impairment expense ($85.9 million in 2016, mostly in the third quarter, as compared to $127.8 million in 2015) and a $22.5 million positive variance in the fair value of derivatives. Another positive factor was that corporate general and administrative costs declined $6.8 million in 2016 from 2015.
Project income of $10.1 million for the year compared favorably to project loss of $(41.4) million for 2015. The 2016 result benefited from lower impairment expense as previously described, a favorable change in the fair value of derivative instruments, higher project income at Manchief, which had a scheduled maintenance overhaul in the second quarter of 2015, partially offset by lower project income at Morris, which had an extended planned outage in the third quarter of 2016, lower project income at Curtis Palmer due to lower water flows, a contractual price adjustment at Calstock, a scheduled maintenance outage at Oxnard and increased amortization expense.
Project Adjusted EBITDA of $202.2 million for the year decreased $6.7 million from $208.9 million for 2015. Primary contributors to the decline were a $10.1 million reduction at Morris due to lower revenues and higher maintenance expense resulting from the extended outage in 2016, a $3.3 million decrease at Curtis Palmer due to lower water flows, and a decrease of $7.6 million at the Ontario projects due to lower waste heat, fuel escalators and a contractual price adjustment at Calstock. The stronger U.S. dollar had a negative non-cash translation impact of approximately $2.9 million, almost all of which was in the first quarter. These negative factors were partially offset by a $7.2 million increase at Manchief, which had a major gas turbine outage in 2015, and a $6.7 million increase at Mamquam due to higher water flows.
Cash provided by operating activities of $111.8 million increased $24.4 million from the 2015 level of $87.4 million. The increase was primarily attributable to a $29.3 million reduction in cash interest payments due to debt repayment in 2015 and 2016 and the absence of make-whole premiums associated with the redemption of the 9.0% Senior Unsecured Notes in 2015, a $6.8 million reduction in corporate G&A expense and a positive variance in changes in working capital. These positive drivers were partially offset by the loss of $21.9 million of operating cash flow from the Wind businesses, which were included in the 2015 result. The $6.7 million decrease in Project Adjusted EBITDA described previously also had a negative impact on operating cash flow in 2016. In 2016, the Company used its $111.8 million of cash provided by operating activities to amortize $96.5 million of term loan and project debt, make capital expenditures of $7.2 million and pay preferred dividends of $8.5 million.
2017 Guidance
The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and projections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses. These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA.
The Company has initiated guidance for 2017 Project Adjusted EBITDA in the range of $225 to $240 million. The increase from the 2016 level of $202.2 million is primarily attributable to the expiration on December 31, 2016 of an above-market gas supply contract for two of the Company's Ontario projects. Other positive factors include an expected full year cash return on completed optimization investments; an expected return to average water flows, particularly at Curtis Palmer and Mamquam; and revised operational and contractual arrangements for Kapuskasing and North Bay as described in the Company's January 9, 2017 press release, net of the cost of putting those plants into a non-operational status. Morris is also expected to have a positive comparison because of the extended outage it underwent in 2016, but this is expected to be more than offset by a planned maintenance outage at Frederickson in 2017 and expenses associated with preparing Tunis for a return to service in 2018 under the new PPA.
Liquidity and Balance Sheet
Liquidity
As shown in Table 3, the Company's liquidity at December 31, 2016 was $204.1 million, essentially unchanged from $205.1 million at September 30, 2016. An $8.2 million reduction in the unrestricted cash balance was mostly offset by a $7.2 million increase in borrowing capacity resulting from a reduction in letters of credit outstanding. The unrestricted cash of $85.6 million includes approximately $60 million at the parent, of which the Company considers approximately $50 million to be discretionary cash available for general corporate purposes.
Atlantic Power Corporation
Table 3 {A –} Liquidity (in millions of U.S. dollars)
Unaudited
December 31, 2016 September 30, 2016
Revolver capacity $200.0 $200.0
Letters of credit outstanding (81.5) (88.7)
Unused borrowing capacity 118.5 111.3
Unrestricted cash 85.6 93.8
Total Liquidity $204.1 $205.1
Note: Liquidity numbers presented do not include restricted cash of $12.6 million at September 30, 2016 and $13.3 million at December 31, 2016.
Balance Sheet
Repayment of Term Loan and Project Debt
During the fourth quarter of 2016, the Company amortized $15.0 million of the APLP Holdings term loan and $3.0 million of project-level debt. For the full year, the Company amortized $85.5 million of term loan debt, including $25.3 million in the first quarter related to the previous term loan, and $11.1 million of project-level debt.
Redemptions and Repurchases of Convertible Debentures
There were no redemptions or repurchases of convertible debentures in the fourth quarter of 2016. For the year, the Company redeemed or repurchased a total of $191.5 million principal amount of convertible debentures. This was done under the normal course issuer bid (NCIB) in the first quarter ($18.8 million), through the redemption at par of both 2017 issues in the second quarter ($110.1 million) using proceeds from the term loan refinancing, and under a substantial issuer bid in the third quarter ($62.7 million), also using proceeds from the refinancing.
Debt Balance and Leverage at December 31, 2016
Although the refinancing of the Company's previous term loan in April 2016 resulted in a net increase in debt of $252 million, the allocation of a majority of the net cash proceeds from the refinancing to debt redemptions and repurchases in the second and third quarters of this year, together with ongoing amortization of the new term loan and project debt, as described previously, offset all but $10 million of this increase. At December 31, 2016, the Company's consolidated debt was $996.5 million, excluding unamortized discounts and deferred financing costs, as compared to $1,018.7 million at year end 2015. The Company's consolidated leverage ratio (consolidated gross debt to trailing 12-month consolidated Adjusted EBITDA) was 5.6 times at December 31, 2016.
Debt Maturity Profile
As a result of refinancing and discretionary repurchases to date, the Company has no bullet maturities at the corporate level prior to June 2019, when the remaining $42.6 million of Series C convertible debentures will mature. In addition, the Company has $60.3 million (U.S. dollar equivalent) of Series D convertible debentures maturing in December 2019. The reshaping of the Company's maturity profile is further improved by the later maturity dates for the new term loan (2023 versus 2021 previously) and the new revolver (2021 versus 2018 previously). The Company also has one project debt bullet maturity during this period {A –} the term loan at its Piedmont project totaling $54 million at its maturity date of August 2018. In addition to these bullet maturities, the Company has amortizing debt at various projects through 2025 and required amortization of the APLP Holdings term loan per a targeted debt schedule through the 2023 maturity date.
2017 Debt Repayment Plans
The Company expects to amortize $100 million of its APLP Holdings term loan and $11.8 million of project debt in 2017 using cash flow. In addition, the Company plans to allocate $40 million or more of its discretionary cash to additional debt reduction (which could include convertible debentures, further paydown of term loan and project debt maturities). Thus, in total, the Company expects to repay approximately $150 million or more of debt in 2017.
Normal Course Issuer Bid (discretionary repurchases of debt and equity)
The NCIB implemented by the Company in December 2015 expired on December 28, 2016. Under this program, the Company repurchased $18.8 million principal amount of convertible debentures, all in the first quarter of 2016. The Company also repurchased a total of slightly less than 8.1 million common shares, including 8.0 million in 2016, at a total cost including commissions of approximately $19.6 million (average price of $2.42 per share). Share repurchases in the fourth quarter of 2016 totaled 2.4 million at a total cost of $5.8 million (average price of $2.44 per share).
The Company implemented a new NCIB on December 29, 2016. Under this NCIB, the Company may purchase up to 10% of the public float of the Company's outstanding common shares and convertible debentures and up to 5% of the amount issued and outstanding of Atlantic Power Preferred Equity Ltd.'s preferred shares. Details of the program can be found in the Company's December 20, 2016 press release.
Other Financial Updates
PPA Expirations and Negotiations
The Company has PPAs or other contractual arrangements scheduled to expire for nine of its projects in the next five years. Together these represent 25% of the Company's capacity and 30% of 2016 Project Adjusted EBITDA. In January 2017, the Company put the Kapuskasing, North Bay and Nipigon projects in Ontario into a non-operational state, under arrangements that provide a fixed monthly payment to the projects until December 2017 for Kapuskasing and North Bay and October 2018 for Nipigon. Another Ontario project, Tunis, has not been operating since the expiration of its previous PPA in December 2014, but has a 15-year PPA that will commence between November 2017 and June 2019, at the Company's option. The Company plans to return Tunis to service under the new PPA in 2018. In San Diego, the Company's three plants (Naval Station, North Island and Naval Training Center) have expiring PPAs in December 2019, but these PPAs are dependent on the Company's right to use the underlying sites under agreements with the Navy that expire in February 2018. The Company is currently considering negotiating, extending or entering into new agreements or arrangements for certain of the Ontario, San Diego and other projects for which the PPAs expire during this period. For information on the status of these negotiations or arrangements, please consult the Company's 2016 Annual Report on Form 10-K.
Optimization Investments
The Company made approximately $3.4 million of optimization-related investments in its projects in 2016, with the majority of those for upgrades to a boiler and two combustion turbines at Morris and a spillway upgrade project at Curtis Palmer, all of which were completed in 2016. The Company expects to complete the upgrade of the third combustion turbine at Morris during an outage in the spring of this year. Although the Company will continue to evaluate the potential for additional such investments, they are expected to be relatively modest. The Company has begun an evaluation of its operation and maintenance costs and expects that to be a major focus in 2017.
The Company realized a cash flow benefit of approximately $8 million in 2016 from optimization investments made in 2013 through 2016 totaling approximately $25 million, which was below the original expectation primarily because high levels of waste heat at Nipigon reduced the need for the duct burners and booster pump that were installed as optimization projects in 2014 and 2015, respectively. In addition, lower water flows at Curtis Palmer in 2016 reduced the contribution from the turbine upgrades completed in 2013 and 2014. The Company expects to realize a cash flow benefit of approximately $12 million in 2017 from these investments and those made in 2017, assuming average water conditions.
Maintenance and Capex
In 2016, for its consolidated projects only, the Company incurred $37.9 million of maintenance expense versus $36.2 million in 2015. In addition to maintenance expensed in the period, the Company made $7.2 million of capital expenditures versus $11.3 million in 2015. Including the Company's share of projects in which it has an equity ownership interest, maintenance expense was $46.2 million in 2016 versus $55.6 million in 2015, and capital expenditures were $7.5 million versus $11.6 million in 2015. For 2017, including its share of equity-owned projects, the Company expects to incur maintenance expenses of approximately $45 million (in line with the 2016 level) and make capital investments of between $5 million and $6 million (slightly lower than the 2016 level). The maintenance expenditures in 2017 include an estimate of the cost to prepare Tunis for a return to service in 2018 under the new PPA.
Material Weakness Remediated
As previously disclosed in the Company's 2015 Annual Report on Form 10-K, the Company had identified a material weakness in its internal controls over financial reporting because its internal controls over its long-lived asset and goodwill impairment tests where not designed effectively. During 2016, management developed and implemented new control procedures to remediate this material weakness. Upon completion of the testing of the design and operating effectiveness of these new control procedures in the annual goodwill impairment analysis it conducted in the fourth quarter of 2016, management concluded that as of December 31, 2016, it had remediated the previously identified material weakness.
Subsequent Event
As disclosed in the Company's 2016 Annual Report on Form 10-K, on February 27, 2017, the Company received notice from the Ontario Electricity Financial Corporation (OEFC) that the Company will be receiving a payment of approximately Cdn$8.4 million for its Kapuskasing and North Bay plants representing the application of the price escalator calculation under their respective PPAs for power sold to OEFC in 2016. This payment stems from the Global Adjustment litigation brought by a group of Non-Utility Generators against the OEFC, which was decided in favor of the plaintiffs by the Superior Court of Canada. The OEFC was denied leave to appeal this ruling by the Supreme Court of Canada in January 2017.
The Company was not a party to the litigation, but did enter into a standstill agreement with the OEFC in 2015, with respect to its Kapuskasing, North Bay and Tunis projects. Under the standstill the Company reserved its right to bring claims against the OEFC with respect to the calculation of the price escalator provision in the PPAs for these three plants.
The OEFC payment of Cdn$8.4 million is for Kapuskasing and North Bay only during 2016 and does not cover any prior period. The Company has notified the OEFC that it reserves its right to contest the payment amount. The amount will be included in the Company's revenue only when the matter is settled and all contingencies have been resolved. The Company's 2017 financial guidance does not include any current or retroactive payments with respect to this matter.
Supplementary Financial Information
Results for project income and Project Adjusted EBITDA exclude discontinued operations, which consist primarily of the Wind businesses that were sold in June 2015. Results of discontinued operations are summarized on page 13 of this release.
A discussion of non-GAAP disclosures and schedules reconciling Project Adjusted EBITDA, a non-GAAP measure, to the comparable GAAP measure, can be found on pages 13 to 14 of this release.
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone conference call on Friday, March 3, 2017 at 8:30 AM ET. Management's prepared remarks and an accompanying presentation will be available on the Conference Calls page of the Company's website prior to the call.
Conference Call / Webcast Information
:
Date: Friday, March 3, 2017
Start Time: 8:30 AM ET
Phone Number: U.S. (Toll Free) 1-855-239-3193; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-542-4129.
Conference Access: Please request access to the Atlantic Power conference call.
Webcast: The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.
Replay/Archive Information:
Replay: Access conference call number 10100699 at the following telephone numbers: U.S. (Toll Free) 1-877-344-7529; Canada (Toll Free) 1-855-669-9658; International (Toll) 1-412-317-0088. The replay will be available one hour after the end of the conference call through April 2, 2017 at 11:59 PM ET.
Webcast archive: The conference call will be archived on Atlantic Power's website at www.atlanticpower.com for a period of 12 months.
About Atlantic Power
Atlantic Power owns and operates a diverse fleet of twenty-three power generation assets across nine states in the United States and two provinces in Canada. The Company's power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. The aggregate gross electric generation capacity of this portfolio is approximately 2,138 megawatts (MW), and the Company's aggregate net ownership interest is approximately 1,500 MW.
Atlantic Power Corporation
Consolidated Statements of Operations
(in millions of U.S. dollars, except per share amounts)
Three months ended December 31,Twelve months ended December 31,
2016 2015 2016 2015
Project revenue:
Energy sales $45.8 $46.6 $184.2 $191.5
Energy capacity revenue 28.7 31.9 141.9 149.3
Other 18.9 19.9 73.1 79.4
93.4 98.4 399.2 420.2
Project expenses:
Fuel 38.7 39.8 149.5 165.1
Operations and maintenance 25.8 21.9 105.2 103.5
Development - - - 1.1
Depreciation and amortization 37.9 26.2 113.5 110.0
102.4 87.9 368.2 379.7
Project other income (expense):
Change in fair value of
derivative instruments 17.8 6.7 37.9 15.4
Equity in earnings of
unconsolidated affiliates 8.0 8.4 35.9 36.7
Gain on sale of equity investments - - - -
Interest, net (2.3) (2.0) (9.2) (8.2)
Impairment (1.2) (127.8) (85.9) (127.8)
Other income, net - (0.1) 0.4 2.0
22.3 (114.8) (20.9) (81.9)
Project income (loss) 13.3 (104.3) 10.1 (41.4)
Administrative and other expenses:
Administration 5.0 6.4 22.6 29.4
Interest, net 18.2 15.8 106.0 107.1
Foreign exchange loss (gain) (5.1) (11.2) 13.9 (60.3)
Other income, net - - (3.9) (3.1)
18.1 11.0 138.6 73.1
Loss from continuing
operations before income taxes (4.8) (115.3) (128.5) (114.5)
Income tax benefit (0.4) (29.9) (14.6) (30.4)
Loss from continuing operations (4.4) (85.4) (113.9) (84.1)
Net (loss) income from
discontinued operations, net of tax (1) - (1.3) - 19.5
Net loss (4.4) (86.7) (113.9) (64.6)
Net loss attributable to
noncontrolling interests - - - (11.0)
Net income attributable to preferred
share dividends of a subsidiary company 2.2 1.9 8.5 8.8
Net loss attributable to
Atlantic Power Corporation ($6.6) ($88.6) ($122.4) ($62.4)
Basic and diluted (loss)
income per share:
Loss from continuing operations
attributable to Atlantic Power ($0.06) ($0.71) ($1.02) ($0.76)
(Loss) income from discontinued
operations, net of tax - (0.01) - 0.25
Net loss attributable to
Atlantic Power Corporation ($0.06) ($0.72) ($1.02) ($0.51)
Dividends per common share: $- $0.02 $- $0.09
(1) Includes contributions from the Wind Projects, which are components of discontinued operations.
Results of Discontinued Operations
The Wind projects, which were sold in June 2015, had no impact on financial results in 2016. For the year ended December 31, 2015, the Wind projects had Project income of $52.6 million and cash provided by operating activities of $21.9 million, as shown in Table 7.
Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. A bridge of Project Adjusted EBITDA to Cash Distributions from Projects, previously included in this release, can be found in the fourth quarter and year end 2016 presentation on the Company's website.
Project income (loss) and Project Adjusted EBITDA by project, previously included in this release, can be found in the fourth quarter and year end 2016 presentation on the Company's website.
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