EXHIBIT 13.2
TRANSALTA CORPORATION FIRST QUARTER REPORT FOR 2014 |
MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See the Forward-Looking Statements section of this MD&A for additional information.
This MD&A should be read in conjunction with the unaudited interim condensed consolidated financial statements of TransAlta Corporation as at and for the three months ended March 31, 2014 and 2013, and should also be read in conjunction with the audited consolidated financial statements and MD&A contained within our 2013 Annual Report. In this MD&A, unless the context otherwise requires, ‘we’, ‘our’, ‘us’, the ‘Corporation’, and ‘TransAlta’ refers to TransAlta Corporation and its subsidiaries. The condensed consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”). All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. Certain financial measures included in this MD&A do not have a standardized meaning as prescribed by IFRS. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. See the Non-IFRS Measures section of this MD&A for additional information. This MD&A is dated April 28, 2014. Additional information respecting TransAlta, including its Annual Information Form, is available on SEDAR at www.sedar.com.
RESULTS OF OPERATIONS
The results of operations are presented on a consolidated basis and by business segment. We have three business segments: Generation, Energy Trading, and Corporate. For this MD&A, we have further split what is reported as our Generation business segment into the various fuel types to provide additional information to our readers. In this MD&A, the impact of foreign exchange fluctuations on foreign currency denominated transactions and balances is discussed with the relevant Condensed Consolidated Statements of Earnings (Loss) and Condensed Consolidated Statements of Financial Position items. While individual line items in the Condensed Consolidated Statements of Financial Position may be impacted by foreign exchange fluctuations, the net impact of the translation of these items relating to foreign operations to our presentation currency is reflected in accumulated other comprehensive income (loss) (“AOCI”) in the equity section of the Condensed Consolidated Statements of Financial Position.
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HIGHLIGHTS
First Quarter Highlights
Consolidated Highlights
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Revenues | 775 | 540 | ||||||
Comparable EBITDA(1) | 310 | 268 | ||||||
Net earnings (loss) attributable to common shareholders | 49 | (11 | ) | |||||
Comparable net earnings attributable to common shareholders(1) | 47 | 32 | ||||||
Funds from operations(1) | 238 | 193 | ||||||
Cash flow from operating activities | 279 | 256 | ||||||
Free cash flow(1) | 139 | 114 | ||||||
Net earnings (loss) per share attributable to common shareholders, basic and diluted | 0.18 | (0.04 | ) | |||||
Comparable net earnings per share(1) | 0.17 | 0.12 | ||||||
Funds from operations per share(1) | 0.88 | 0.75 | ||||||
Free cash flow per share(1) | 0.51 | 0.44 | ||||||
Dividends paid per common share | 0.18 | 0.29 |
As at | March 31, 2014 | Dec. 31, 2013(2) | ||||||
Total assets | 9,565 | 9,624 | ||||||
Total long-term liabilities | 4,735 | 5,348 |
§ | Comparable earnings before interest, taxes, depreciation, and amortization (“EBITDA”) for 2014 increased $42 million to $310 million due primarily to higher power and gas prices in the northeast driving strong results from our Energy Trading Segment, steady operational performance across the Generation Segment, and a full quarter’s contribution from wind units commissioned or acquired in 2013. As a result, funds from operations (“FFO”) increased $45 million compared to the prior year to $238 million. |
§ | Comparable net earnings were $47 million ($0.17 net earnings per share), up from $32 million ($0.12 net earnings per share) in 2013. Higher depreciation and amortization, net interest expense, income tax expense, and income attributable to non-controlling interests partially offset the increase in EBITDA. |
§ | Reported net earnings attributable to common shareholders were $49 million ($0.18 net earnings per share), up $60 million from a net loss of $11 million ($0.04 net loss per share) in 2013. The change is driven by the increase in comparable EBITDA of $42 million and the one time after-tax loss on assumption of pension obligations of $22 million in the prior year. |
(1) | These items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. |
(2) | After giving effect to the reclassification described in the Current Accounting Changes section of this MD&A. |
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Strategic Highlights
§ | Named preferred bidder for the South Hedland Power Project to build, own, and operate a 150 megawatt (“MW”) combined cycle gas power station in Western Australia. |
§ | Secondary offering of TransAlta Renewables Inc. (“TransAlta Renewables”) shares for gross proceeds of $136.2 million. |
§ | Entered into an agreement to sell our 50 per cent ownership of CE Generation LLC (“CE Gen”) and Wailuku Holding Company, LLC (“Wailuku”) for proceeds of U.S.$193.5 million. We expect the sale of CE Gen to close in the second quarter. |
§ | Started construction with our joint venture partner of a $178 million natural gas pipeline to our Solomon power station. We hold a 43 per cent interest in the joint venture. |
Operational Financial Results
Comparable EBITDA is as follows:
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Availability (%)(1) | 91.5 | 91.5 | ||||||
Production (GWh)(1) | 12,067 | 10,644 | ||||||
Comparable EBITDA | ||||||||
Generation Segment | ||||||||
Canadian Coal | 94 | 99 | ||||||
U.S. Coal | 17 | 12 | ||||||
Gas | 82 | 85 | ||||||
Wind | 62 | 50 | ||||||
Hydro | 19 | 24 | ||||||
Total Generation Segment | 274 | 270 | ||||||
Energy Trading Segment | 49 | 14 | ||||||
Corporate Segment | (13 | ) | (16 | ) | ||||
Total comparable EBITDA | 310 | 268 |
§ | Canadian Coal: In 2014, comparable EBITDA was $94 million compared to $99 million in 2013. The decrease in comparable EBITDA is primarily due to higher gas consumption as a result of opacity issues at certain facilities and the derating of Keephills Unit 3. |
§ | U.S. Coal: Comparable EBITDA increased to $17 million in 2014 compared to $12 million in 2013. The increase in comparable EBITDA is primarily due to higher market prices in the Pacific Northwest. |
§ | Gas: Comparable EBITDA decreased by $3 million to $82 million, primarily due contract curtailments and unrealized mark-to-market losses on certain forward contracts. |
§ | Wind: Comparable EBITDA for wind improved by $12 million in 2014 to $62 million, primarily due to the acquisition of Wyoming Wind, a full quarter operations at New Richmond, and higher wind volumes in Eastern Canada. |
§ | Hydro: Comparable EBITDA decreased by $5 million to $19 million, primarily as a result of lower prices in Alberta for power and ancillary services. |
____________________
(1) | Availability and production includes all generating assets (generation operations, finance leases, and equity investments). |
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§ | Energy Trading Segment: Our Energy Trading business showed an improvement in comparable EBITDA of $35 million to $49 million in 2014 by capitalizing on high power and gas prices through our ability to optimize our energy marketing assets, capitalize on arbitrage opportunities, and serve customer demands during extraordinarily volatile market conditions caused by extreme weather events during the quarter in the northeast. |
§ | Corporate Segment: The Corporate Segment incurred operations, maintenance, and administration (“OM&A”) expenses of $13 million in 2014 compared to $16 million in 2013. The reduction in OM&A is primarily due a change in the way in which certain overhead cost allocations are made within the organization, partially offset by an increase in compensation costs. |
AVAILABILITY & PRODUCTION
Availability for the three months ended March 31, 2014 was comparable to the same period in 2013.
Production for the three months ended March 31, 2014 increased 1,423 gigawatt hours (“GWh”) compared to the same period in 2013, primarily due to Sundance Units 1 and 2 returning to service, lower economic dispatching at Centralia Thermal, the acquisition of Wyoming Wind, and a full quarter of operations at New Richmond, partially offset by an unplanned outage at our Mississauga facility and derating of Keephills Unit 3.
FUNDS FROM OPERATIONS AND FREE CASH FLOW
FFO for the three months ended March 31, 2014 increased $45 million compared to the same period in 2013 to $238 million, primarily due to the increase in comparable EBITDA.
Free cash flow for the three months ended March 31, 2014 increased $25 million compared to the same period in 2013 to $139 million due to an increase in FFO, partially offset by increased sustaining capital expenditures and distributions paid to subsidiaries’ non-controlling interests.
SIGNIFICANT EVENTS
Australia Natural Gas Pipeline
On Jan. 15, 2014, we announced the formation of an unincorporated joint venture named Fortescue River Gas Pipeline Joint Venture. The first project of this new joint venture will be to build, own, and operate a $178 million natural gas pipeline from the Dampier to Bunbury Natural Gas Pipeline to our Solomon power station. We hold a 43 per cent interest in the joint venture through a wholly owned subsidiary. In addition to our portion of the pipeline cost, an additional $10 million in plant retrofitting costs will also be incurred as part of the project, which will be recoverable over time through increased lease payments.
Executive Leadership Team Appointments
On March 18, 2014, we announced three senior leadership appointments that will enhance our objectives of operational excellence from the base business and growth. Brett Gellner was appointed to the role of Chief Investment Officer, responsible for leading all growth aspects of the Corporation. Donald Tremblay joined TransAlta as Chief Financial Officer, effective March 31, 2014, and Wayne Collins has accepted a role taking on the leadership accountabilities of our Coal and Mining Operations.
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Fort McMurray Transmission Project
On Jan. 17, 2014, we announced that our strategic partnership with MidAmerican Transmission, TAMA Transmission LP (“TAMA Transmission”), which was formed on May 9, 2013, successfully qualified to participate as a proponent in the Fort McMurray West 500 kilovolt Transmission Project. The Alberta Electric System Operator (“AESO”) announced its selection of a short-list of companies, identifying that TAMA Transmission will participate in the next stage of its competitive process for the project.
Sale of CE Gen, the Blackrock Development Project, CalEnergy, LLC, and Wailuku
On Feb. 20, 2014, we announced an agreement to sell our 50 per cent ownership of CE Gen, the Blackrock Development Project (“Blackrock”), CalEnergy, LLC (“CalEnergy”), and Wailuku to MidAmerican Renewables for proceeds of U.S.$193.5 million. MidAmerican Renewables holds the other 50 per cent interest in CE Gen, CalEnergy, Blackrock, and Wailuku. With the exception of Wailuku, we expect to complete the transaction during the second quarter.
Sundance Unit 6 Agreement
On Feb. 19, 2014, we reached an agreement with the Power Purchase Arrangement (“PPA”) Buyer related to the dispute on Sundance Unit 6. There are no material impacts to the financial statements as a result of the agreement.
Settlement of California Proceedings
On March 18, 2014, TransAlta entered into a settlement to resolve outstanding claims related to the 2000 – 2001 power crisis in the State of California. The settlement, which is subject to approval by the U.S. Federal Energy Regulatory Commission (“FERC”), provides for the payment by TransAlta of U.S.$52 million in two equal payments over a 12-month period and the transfer of approximately U.S.$97 million of accounts receivable owed to TransAlta from the California Independent System Operator and now-defunct California Power Exchange. The impact of the settlement is consistent with the accrual we made for the year ended Dec. 31, 2013.
Proceedings Before the Alberta Utilities Commission
On March 21, 2014, the Alberta Market Surveillance Administrator (the “MSA”) filed an application with the Alberta Utilities Commission (the “AUC”) alleging, among other things, that TransAlta manipulated the price of electricity in the Province of Alberta when it took outages at certain of its coal-fired generating units in late 2010 and early 2011. TransAlta has denied the MSA’s allegations in their entirety. In a separate, but related matter, on Feb. 21, 2014, TransAlta filed a complaint with the AUC concerning the conduct of the MSA in relation to its investigation of TransAlta and its failure to consult with market participants prior to making certain decisions on permitted offer behaviour. The MSA’s application and TransAlta’s complaint are presently before the AUC.
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SUBSEQUENT EVENTS
South Hedland Power Project
On April 15, 2014, we announced that we had been named the preferred bidder for the South Hedland Power Project in Western Australia. Subject to the finalization of necessary contracts and approvals that will take place during the second quarter, the project would see TransAlta build, own, and operate a 150 MW combined cycle gas power station in South Hedland, Western Australia. The investment is estimated at approximately AUD$550 million. The power station is expected to be delivering power in 2016, with full commissioning in 2017. The development will be fully contracted under 25 year agreements with Horizon Power, a state utility company and Fortescue Metals Group Ltd., a mining company. The project may be expanded to accommodate additional customers at later dates.
Secondary Offering of TransAlta Renewables Inc. Shares
In April 2014, we completed the previously announced secondary offering of 10,950,000 common shares of TransAlta Renewables at a price of $11.40 per common share. In addition, the over-allotment option granted to the syndicate of underwriters, led by CIBC and RBC Capital Markets, was partially exercised for an additional 1,000,000 common shares, also at a price of $11.40 per common share.
The offering resulted in gross proceeds to TransAlta of $136.2 million. We will use the net proceeds from the offering to reduce indebtedness, to fund growth, and for general corporate purposes. Following completion of the offering, TransAlta owns approximately 70.3 per cent of the common shares of TransAlta Renewables.
BUSINESS ENVIRONMENT
We operate in a variety of business environments to generate electricity, find buyers for the power we generate, and arrange for its transmission. The major markets we operate in are Western Canada, the Western U.S., and Eastern Canada. For a further description of the regions in which we operate as well as the impact of prices of electricity and natural gas upon our financial results, refer to our 2013 Annual MD&A.
Contracted Cash Flows
During the first quarter of 2014, approximately 88 per cent of our consolidated power portfolio was contracted through the use of PPAs and other long-term contracts. We also entered into short-term physical and financial contracts for the remaining volumes, which are primarily for periods of up to five years. The average prices of these contracts for the balance of 2014 are approximately $55 per megawatt hour (“MWh”) in Alberta and approximately U.S.$40 per MWh in the Pacific Northwest.
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Electricity Prices
Please refer to the Business Environment section of our 2013 Annual MD&A for a full discussion of the spot electricity market and the impact of electricity prices on our business, as well as our strategy to hedge our risks associated with changes in these prices.
The average spot electricity prices for the three months ended March 31, 2014 and 2013 in our three major markets are shown in the following graph.
For the three months ended March 31, 2014, average spot prices in Alberta decreased compared to the same period in 2013, primarily due to an increase in supply as a result of Sundance Units 1 and 2 returning to service. In the Pacific Northwest, average spot prices increased due to higher natural gas prices, particularly in February. Average spot prices in Ontario for the three months ended March 31, 2014 increased compared to the same period in 2013 due to extreme cold weather across the entire northeast, which led to higher natural gas prices and increased demand.
In 2014, power prices in Alberta are expected to be lower than 2013 as a result of more baseload generation and fewer planned maintenance outages across the market. However, prices can vary based on supply and weather conditions. In the Pacific Northwest, we expect prices to settle higher than in 2013 due to marginally higher natural gas prices. In Ontario, prices for the balance of the year are expected to be higher than 2013 due to higher natural gas prices.
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Spark Spreads
Please refer to the Business Environment section of our 2013 Annual MD&A for a full discussion of spark spreads and the impact of spark spreads on our business.
The average spark spreads for the three months ended March 31, 2014 and 2013 in our three major markets are shown in the following graph.
(1) For a 7,000 British Thermal Units per kilowatt hour heat rate plant.
For the three months ended March 31, 2014, average spark spreads decreased in Alberta compared to the same period in 2013 due to lower prices resulting from an increase in supply as a result of Sundance Units 1 and 2 returning to service and higher natural gas prices. In the Pacific Northwest, average spark spreads were comparable to the same period in 2013. Average spark spreads decreased in Ontario compared to the same period in 2013. High natural gas prices throughout the first quarter of 2014 reduced spark spreads in the market. High gas prices can reduce calculated average spark spreads because many of the hourly prices are not set by natural gas generators. During these low-priced hours, the high natural gas price makes natural gas generators unprofitable.
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DISCUSSION OF SEGMENTED RESULTS
We have three business segments: Generation, Energy Trading, and Corporate.
Generation: Owns and operates hydro, wind, natural gas-fired and coal-fired facilities, and related mining operations in Canada, the U.S., and Australia. Generation revenues and overall profitability are derived from the availability and production of electricity and steam as well as ancillary services such as system support. Electricity sales generated by our Commercial and Industrial group are assumed to be sourced from TransAlta’s production and have been included in the Generation Segment on a net basis.
The full capacity of the facilities in which we have a share of ownership is 10,144 MW(1). At March 31, 2014, our generating assets had 9,092 MW of gross generating capacity(3) in operation (8,497 MW(1) net ownership interest). The following information excludes assets that are accounted for using the equity method, which are discussed separately within this discussion of the Generation Segment.
The results of the Generation Segment are as follows:
3 months ended March 31, 2014 | 3 months ended March 31, 2013 | |||||||||||||||||||||||
Reported | Comparable adjustments(2) | Comparable total | Reported | Comparable adjustments | Comparable total | |||||||||||||||||||
Availability (%)(3) | 91.4 | - | 91.4 | 91.7 | - | 91.7 | ||||||||||||||||||
Production (GWh)(3) | 11,753 | - | 11,753 | 10,250 | - | 10,250 | ||||||||||||||||||
Gross installed capacity (MW)(1), (3) | 9,092 | - | 9,092 | 8,388 | - | 8,388 | ||||||||||||||||||
Net installed capacity (MW)(1), (3) | 8,497 | - | 8,497 | 8,007 | - | 8,007 | ||||||||||||||||||
Revenues | 710 | (7 | ) | 703 | 523 | 41 | 564 | |||||||||||||||||
Fuel and purchased power | 335 | - | 335 | 201 | - | 201 | ||||||||||||||||||
Gross margin | 375 | (7 | ) | 368 | 322 | 41 | 363 | |||||||||||||||||
Operations, maintenance, and administration | 112 | (4 | ) | 108 | 92 | - | 92 | |||||||||||||||||
Inventory writedown | 4 | - | 4 | 14 | - | 14 | ||||||||||||||||||
Taxes, other than income taxes | 7 | - | 7 | 7 | - | 7 | ||||||||||||||||||
Finance lease income | (12 | ) | (1 | ) | (13 | ) | (11 | ) | (1 | ) | (12 | ) | ||||||||||||
Intersegment cost allocation | 3 | - | 3 | 4 | - | 4 | ||||||||||||||||||
Gain on sale of property, plant, and equipment | - | - | - | - | (1 | ) | (1 | ) | ||||||||||||||||
Mine depreciation | - | (15 | ) | (15 | ) | - | (11 | ) | (11 | ) | ||||||||||||||
EBITDA | 261 | 13 | 274 | 216 | 54 | 270 | ||||||||||||||||||
Depreciation and amortization | 129 | 15 | 144 | 122 | 12 | 134 | ||||||||||||||||||
Other | - | 1 | 1 | - | 1 | 1 | ||||||||||||||||||
Operating income | 132 | (3 | ) | 129 | 94 | 41 | 135 |
(1) | We measure capacity as net maximum capacity (see Glossary of Key Terms for definition of this and other key terms), which is consistent with industry standards. Capacity figures represent capacity owned and in operation unless otherwise stated. Gross capacity reflects the basis of consolidation of underlying assets, while net capacity deducts capacity attributable to non-controlling interests in these assets. |
(2) | Comparable figures are not defined under IFRS. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders and cash flow from operating activities. |
(3) | Availability, production, and installed capacity include assets under generation operations and finance leases. |
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Coal: TransAlta owns and operates coal-fired facilities and related mining operations in Canada and the U.S. Coal revenues and overall profitability are derived from the availability and production of electricity. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary section of our 2013 Annual MD&A.
Canadian Coal
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Availability (%) | 87.1 | 85.4 | ||||||
Production (GWh) | 6,249 | 5,275 | ||||||
Gross installed capacity (MW) | 3,771 | 3,211 | ||||||
Net installed capacity (MW) | 3,576 | 3,016 | ||||||
Revenues | 254 | 228 | ||||||
Fuel and purchased power | 122 | 94 | ||||||
Comparable gross margin(1) | 132 | 134 | ||||||
Operations, maintenance, and administration | 49 | 43 | ||||||
Taxes, other than income taxes | 3 | 3 | ||||||
Intersegment cost allocation | 1 | 1 | ||||||
Gain on sale of property, plant, and equipment | - | (1 | ) | |||||
Mine depreciation | (15 | ) | (11 | ) | ||||
Comparable EBITDA(1) | 94 | 99 | ||||||
Depreciation and amortization | 76 | 69 | ||||||
Comparable operating income(1) | 18 | 30 | ||||||
Sustaining capital expenditures: | ||||||||
Routine capital | 10 | 6 | ||||||
Mining equipment and land purchases | 5 | 8 | ||||||
Finance leases | 2 | - | ||||||
Planned major maintenance(2) | 28 | 23 | ||||||
Total | 45 | 37 |
Production for the three months ended March 31, 2014 increased 974 GWh compared to the same period in 2013 primarily due to Sundance Units 1 and 2 returning to service. The return to service of Sundance Units 1 and 2 impacted our revenue, fuel and purchased power, and OM&A expenses.
For the three months ended March 31, 2014, comparable EBITDA decreased by $5 million compared to the same period in 2013, due to higher gas consumption as a result of opacity issues at certain coal facilities, derating of the higher margin Keephills Unit 3, and an increase in OM&A as a result of the way in which certain overhead cost allocations are made within the organization, partially offset by lower coal costs and favourable contract pricing.
Depreciation and amortization for the three months ended March 31, 2014 increased by $7 million compared to the same period in 2013 due to an increased asset base, primarily related to Sundance Units 1 and 2 returning to service.
(1) | Comparable figures are not defined under IFRS. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders and cash flow from operating activities. |
(2) | Consists of three planned outages in 2014 and one planned outage in 2013. |
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For the three months ended March 31, 2014, the increase in sustaining capital expenditures compared to 2013 is mainly due to an increase in planned outages. These results include the effects of the Keephills Unit 2 force majeure outage that commenced on Jan. 31, 2014. The Unit returned to service on March 13, 2014.
U.S. Coal
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Availability (%) | 94.9 | 98.3 | ||||||
Production (GWh) | 2,116 | 1,678 | ||||||
Gross and net installed capacity (MW) | 1,340 | 1,340 | ||||||
Revenues | 106 | 71 | ||||||
Fuel and purchased power | 71 | 31 | ||||||
Comparable gross margin | 35 | 40 | ||||||
Operations, maintenance, and administration | 13 | 11 | ||||||
Inventory writedown | 4 | 14 | ||||||
Taxes, other than income taxes | - | 1 | ||||||
Intersegment cost allocation | 1 | 2 | ||||||
Comparable EBITDA | 17 | 12 | ||||||
Depreciation and amortization | 14 | 13 | ||||||
Comparable operating income (loss) | 3 | (1 | ) | |||||
Sustaining capital expenditures: | ||||||||
Routine capital | - | 2 | ||||||
Planned major maintenance | 1 | 1 | ||||||
Total | 1 | 3 |
Production for the three months ended March 31, 2014 increased 438 GWh compared to the same period in 2013 due to higher pricing resulting in lower economic dispatching, partially offset by higher unplanned outages.
For the three months ended March 31, 2014, comparable EBITDA increased by $5 million compared to the same period in 2013, primarily due to higher market prices.
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Gas: TransAlta owns and operates natural gas-fired facilities in Canada, the U.S., and Australia. Gas revenues and overall profitability are derived from the availability and production of electricity and steam. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary section of our 2013 Annual MD&A.
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Availability (%) | 96.1 | 97.7 | ||||||
Production (GWh)(1) | 2,008 | 2,133 | ||||||
Gross installed capacity (MW)(1), (2) | 1,779 | 1,779 | ||||||
Net installed capacity (MW)(1), (2) | 1,618 | 1,618 | ||||||
Revenues | 232 | 167 | ||||||
Fuel and purchased power | 136 | 71 | ||||||
Comparable gross margin | 96 | 96 | ||||||
Operations, maintenance, and administration | 25 | 21 | ||||||
Taxes, other than income taxes | 1 | 1 | ||||||
Intersegment cost allocation | 1 | 1 | ||||||
Finance lease income | (13 | ) | (12 | ) | ||||
Comparable EBITDA | 82 | 85 | ||||||
Depreciation and amortization | 27 | 27 | ||||||
Other | 1 | 1 | ||||||
Comparable operating income | 54 | 57 | ||||||
Sustaining capital expenditures: | ||||||||
Routine capital | 3 | 2 | ||||||
Planned major maintenance | 4 | 4 | ||||||
Total | 7 | 6 |
6
Production for the three months ended March 31, 2014 decreased 125 GWh compared to the same period in 2013 primarily due to contract curtailments and an unplanned outage at our Mississauga facility. The economic impact of the unplanned outage was largely mitigated by the resale of gas in the market.
For the three months ended March 31, 2014, comparable EBITDA decreased by $3 million compared to the same period in 2013, due to contract curtailments and unrealized mark-to-market losses on certain forward contracts.
(1) | Includes production capacity for Fort Saskatchewan and Solomon power stations, which have been accounted for as finance leases. |
(2) | The Centralia gas plant is currently not in operation. We are currently assessing the generation needs of the region and the financial feasibility of bringing the plant back into operation. |
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Renewables: TransAlta owns and operates hydro and wind facilities in Canada and the U.S. Renewable revenues and overall profitability are derived from the availability of water and wind resources and the production of electricity, as well as ancillary services such as system support. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary section of our 2013 Annual MD&A.
Wind
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Availability (%) | 94.2 | 93.9 | ||||||
Production (GWh) | 1,012 | 788 | ||||||
Gross installed capacity (MW) | 1,289 | 1,145 | ||||||
Net installed capacity (MW) | 1,070 | 1,120 | ||||||
Revenues | 80 | 64 | ||||||
Fuel and purchased power | 4 | 4 | ||||||
Comparable gross margin | 76 | 60 | ||||||
Operations, maintenance, and administration | 12 | 9 | ||||||
Taxes, other than income taxes | 2 | 1 | ||||||
Comparable EBITDA | 62 | 50 | ||||||
Depreciation and amortization | 21 | 19 | ||||||
Comparable operating income | 41 | 31 | ||||||
Sustaining capital expenditures: | ||||||||
Routine capital | - | 1 | ||||||
Planned major maintenance | 1 | 1 | ||||||
Total | 1 | 2 |
Production for the three months ended March 31, 2014 increased 224 GWh compared to the same period in 2013 due to the acquisition of Wyoming Wind, a full quarter of operations at New Richmond, and higher wind volumes in Eastern Canada.
For the three months ended March 31, 2014, comparable EBITDA increased by $12 million compared to the same period in 2013, due to the new wind farms and higher wind volumes in Eastern Canada.
Depreciation and amortization for the three months ended March 31, 2014 increased by $2 million compared to the same period in 2013 due to a full quarter of operations at New Richmond and the acquisition of Wyoming Wind.
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Hydro
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Production (GWh) | 368 | 376 | ||||||
Gross installed capacity (MW) | 913 | 913 | ||||||
Net installed capacity (MW) | 893 | 913 | ||||||
Revenues | 31 | 34 | ||||||
Fuel and purchased power | 2 | 1 | ||||||
Comparable gross margin | 29 | 33 | ||||||
Operations, maintenance, and administration | 9 | 8 | ||||||
Taxes, other than income taxes | 1 | 1 | ||||||
Comparable EBITDA | 19 | 24 | ||||||
Depreciation and amortization | 6 | 6 | ||||||
Comparable operating income | 13 | 18 | ||||||
Sustaining capital expenditures: | ||||||||
Routine capital | 3 | 1 | ||||||
Total | 3 | 1 |
Production for the three months ended March 31, 2014 decreased by 8 GWh compared to the same period in 2013 due to unfavourable market conditions.
Comparable EBITDA decreased by $5 million for the three months ended March 31, 2014 compared to the same period in 2013 primarily as a result of lower market pricing in Alberta for power and ancillary services.
Equity Investments
Our interests in the CE Gen and Wailuku joint ventures are comprised of geothermal, natural gas, and hydro facilities in various locations throughout the U.S., with 852 MW of gross generating capacity (396 MW net ownership interest).
As outlined in the Significant Events section of this MD&A, we have entered into agreements to sell our interests in CE Gen and Wailuku. Our interest in CalEnergy is also being sold with CE Gen. While we continue to be the beneficial owner of our 50 per cent interests in CE Gen, CalEnergy, and Wailuku until the proposed sales close, these investments are no longer accounted for using the equity method effective March 1, 2014. The equity method was used to account for the results of these joint ventures for the months of January and February 2014, but ceased with classification of these investments as assets held for sale in compliance with IFRS requirements.
The table below summarizes key operational information adjusted to reflect our interest in these investments:
2 months ended | 3 months ended | |||||||
Feb. 28, 2014 | March 31, 2013 | |||||||
Availability (%) | 97.1 | 86.9 | ||||||
Production (GWh): | ||||||||
Gas | 127 | 140 | ||||||
Renewables | 187 | 254 | ||||||
Total production | 314 | 394 |
14 TRANSALTA CORPORATION / Q1 2014
Availability for the two months ended Feb. 28, 2014 increased compared to the three months ended March 31, 2013 due to lower planned outages.
Production for the two months ended Feb. 28, 2014 decreased by 80 GWh compared to the three months ended March 31, 2013. After the removal of the March 2013 portion of production, the production for the two months ended Feb. 28, 2014 increased by 26 GWh compared to the same period in 2013. The increase was as a result of lower planned outages, partially offset by higher market curtailments.
Equity loss for the two months ended Feb. 28, 2014 was nil compared to $4 million for the three months ended March 31, 2013. The reduction of the loss is primarily due to lower planned outages in the two months ended Feb. 28, 2014 compared to the same period in 2013.
Our investment in TAMA Transmission continues to be accounted for using the equity method.
Energy Trading: Derives revenue and earnings from the wholesale marketing and trading of electricity and other energy-related commodities and derivatives. Achieving gross margins, while remaining within Value at Risk (“VaR”) limits, is a key measure of Energy Trading’s activities. Refer to the Value at Risk and Trading Positions discussion in the Risk Management section of our 2013 Annual MD&A for further discussion on VaR.
Energy Trading markets our production through short-term and long-term contracts, ensures cost effective and reliable fuel supply, and seeks to capture margin upside within dynamic market conditions. We leverage our core marketing capabilities by also serving third party customers' energy supply and marketing needs.
Our marketing commitments are backed by our own supply and through the acquisition of third party supply and proprietary marketing assets, such as transmission, transportation, and storage rights. In the course of managing our portfolio, we actively seek to take advantage of our knowledge of physical power and fuel markets to capture incremental arbitrage margins.
All activities are managed within our core markets and within our low to moderate risk profile. Direct marketing of our own generation is reported in the Generation Segment results. All activities indirectly related to our assets and all other marketing activities are reported in the Energy Trading Segment.
For a more in-depth discussion of our Energy Trading activities, refer to the Discussion of Segmented Results section of our 2013 Annual MD&A.
The results of the Energy Trading Segment, with all trading results presented on a net basis, are as follows:
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Revenues and comparable gross margin | 65 | 17 | ||||||
Operations, maintenance, and administration | 19 | 7 | ||||||
Intersegment cost allocation | (3 | ) | (4 | ) | ||||
Comparable EBITDA and comparable operating income | 49 | 14 |
Extreme weather events caused unprecedented gas and power commodity price volatility in eastern markets during the quarter. Natural gas prices in New England and power prices in NEPool averaged more than double those for the comparative period last year. These conditions positively impacted our ability to optimize our portfolio of generation, transportation, transmission, and storage assets. We also capitalized on low risk arbitrage opportunities brought about by extreme market volatility. We expect the Energy Trading gross margin to return to more normal levels in the $10 to $15 million range per quarter for the balance of year.
TRANSALTA CORPORATION / Q1 2014 15
For the three months ended March 31, 2014, Energy Trading comparable EBITDA increased by $35 million to $49 million. The increase in comparable gross margin was partially offset by higher OM&A expense due to higher compensation costs driven by the strong results.
Corporate: Our Generation and Energy Trading segments are supported by a Corporate group that provides finance, tax, treasury, legal, regulatory, environmental, procurement, health and safety, sustainable development, corporate communications, government and investor relations, information technology, risk management, human resources, internal audit, and other administrative support.
The expenses incurred by the Corporate Segment are as follows:
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Operations, maintenance, and administration and comparable EBITDA | 13 | 16 | ||||||
Depreciation and amortization | 6 | 5 | ||||||
Comparable operating loss | (19 | ) | (21 | ) | ||||
Sustaining capital expenditures: | ||||||||
Routine capital | 7 | 2 | ||||||
Total | 7 | 2 |
For the three months ended March 31, 2014, OM&A expense decreased by $3 million compared to 2013, primarily due to a change in the way in which certain overhead cost allocations are made within the organization, partially offset by an increase in compensation costs.
Routine capital expenditures for the three months ended March 31, 2014 increased compared to 2013 primarily, as a result of an increase in corporate information technology costs.
NET INTEREST EXPENSE
The components of net interest expense are as follows:
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Interest on debt | 61 | 60 | ||||||
Capitalized interest | - | (2 | ) | |||||
Interest expense | 61 | 58 | ||||||
Accretion of provisions | 5 | 4 | ||||||
Net interest expense | 66 | 62 |
The increase in net interest expense for the three months ended March 31, 2014, compared to the same period in 2013, is primarily due to lower capitalized interest and unfavourable foreign exchange impacts.
16 TRANSALTA CORPORATION / Q1 2014
INCOME TAXES
A reconciliation of income taxes and effective tax rates on earnings, excluding non-comparable items, is presented below:
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Earnings (loss) before income taxes | 91 | (9 | ) | |||||
Income attributable to non-controlling interests | (15 | ) | (10 | ) | ||||
Equity loss | - | 4 | ||||||
Impacts associated with certain de-designated and ineffective hedges | (7 | ) | 41 | |||||
Loss on assumption of pension obligations | - | 29 | ||||||
Other non-comparable items | 4 | - | ||||||
Earnings attributable to TransAlta shareholders, excluding non-comparable items, subject to tax | 73 | 55 | ||||||
Income tax expense (recovery) | 18 | (17 | ) | |||||
Income tax (expense) recovery related to impacts associated with certain de-designated and ineffective hedges | (2 | ) | 14 | |||||
Income tax recovery related to changes in corporate income tax rates | - | 6 | ||||||
Income tax recovery related to loss on assumption of pension obligations | - | 7 | ||||||
Income tax recovery related to other non-comparable items | 1 | - | ||||||
Income tax expense excluding non-comparable items | 17 | 10 | ||||||
Effective tax rate on earnings attributable to TransAlta shareholders excluding non-comparable items (%) | 23 | 18 |
The income tax expense excluding non-comparable items for the three months ended March 31, 2014 increased compared to the same period in 2013 due to higher comparable earnings and changes in the amount of earnings between the jurisdictions in which pre-tax income is earned.
The effective tax rate on earnings attributable to TransAlta shareholders, excluding non-comparable items for the three months ended March 31, 2014, increased compared to the same period in 2013 due to the effect of certain deductions that do not fluctuate with earnings and changes in the amount of earnings between the jurisdictions in which pre-tax income is earned.
NON-CONTROLLING INTERESTS
Net earnings attributable to non-controlling interests for the three months ended March 31, 2014 increased $5 million compared to the same period in 2013, primarily due to earnings at TransAlta Renewables, which was formed as a separate public entity in August 2013. As at March 31, 2014, public shareholders owned 19.3 per cent of TransAlta Renewables.
TRANSALTA CORPORATION / Q1 2014 17
ADDITIONAL IFRS MEASURES
An additional IFRS measure is a line item, heading, or subtotal that is relevant to an understanding of the financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an understanding of the financial statements but is not presented elsewhere in the financial statements. We have included line items entitled gross margin and operating income (loss) in our Condensed Consolidated Statements of Earnings (Loss) for the three months ended March 31, 2014 and 2013. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.
NON-IFRS MEASURES
We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These Non-IFRS measures are not necessarily comparable to a similarly titled measure of another company.
Presenting earnings on a comparable basis, comparable gross margin, comparable operating income, and comparable EBITDA from period to period provides management and investors with supplemental information to evaluate earnings trends in comparison with results from prior periods. In calculating these items, we exclude the impact related to certain hedges that are either de-designated or deemed ineffective for accounting purposes, as management believes that these transactions are not representative of our business operations and that these are still effective economic hedges. As these gains (losses) have already been recognized in earnings in current or prior periods, future reported earnings will be lower; however, the expected cash flows from these contracts will not change.
Other adjustments to earnings, such as those included in the earnings on a comparable basis calculation, have also been excluded as management believes these transactions are not representative of our business operations. Earnings on a comparable basis per share are calculated using the weighted average common shares outstanding during the period.
Presenting comparable EBITDA from period to period provides management and investors with a proxy for the amount of cash generated from operating activities before net interest expense, non-controlling interests, income taxes, and working capital adjustments.
Comparable operating income and EBITDA also include the earnings from the finance lease facilities that we operate. The finance lease income is used as a proxy for the operating income and EBITDA of these facilities.
18 TRANSALTA CORPORATION / Q1 2014
A reconciliation of comparable results to reported results is as follows:
3 months ended March 31, 2014 | 3 months ended March 31, 2013 | |||||||||||||||||||||||||
Reported | Comparable adjustments | Comparable total | Reported | Comparable adjustments | Comparable total | |||||||||||||||||||||
Revenues | 775 | (7 | ) | (1) | 768 | 540 | 41 | (1) | 581 | |||||||||||||||||
Fuel and purchased power | 335 | - | 335 | 201 | - | 201 | ||||||||||||||||||||
Gross margin | 440 | (7 | ) | 433 | 339 | 41 | 380 | |||||||||||||||||||
Operations, maintenance, and administration | 144 | (4 | ) | (2) | 140 | 115 | - | 115 | ||||||||||||||||||
Inventory writedown | 4 | - | 4 | 14 | - | 14 | ||||||||||||||||||||
Taxes, other than income taxes | 7 | - | 7 | 7 | - | 7 | ||||||||||||||||||||
Finance lease income reclass | (12 | ) | (1 | ) | (3) | (13 | ) | (11 | ) | (1 | ) | (3) | (12 | ) | ||||||||||||
Gain on sale of property, plant, and equipment | - | - | - | - | (1 | ) | (6) | (1 | ) | |||||||||||||||||
Mine depreciation reclass | - | (15 | ) | (4) | (15 | ) | - | (11 | ) | (4) | (11 | ) | ||||||||||||||
EBITDA | 297 | 13 | 310 | 214 | 54 | 268 | ||||||||||||||||||||
Depreciation and amortization | 135 | 15 | (4) | 150 | 127 | 12 | (7) | 139 | ||||||||||||||||||
Finance lease income reclass | - | 1 | (3) | 1 | - | 1 | (3) | 1 | ||||||||||||||||||
Operating income | 162 | (3 | ) | 159 | 87 | 41 | 128 | |||||||||||||||||||
Equity loss | - | - | - | (4 | ) | - | (4 | ) | ||||||||||||||||||
Foreign exchange loss | (5 | ) | - | (5 | ) | (1 | ) | - | (1 | ) | ||||||||||||||||
Loss on assumption of pension obligations | - | - | - | (29 | ) | 29 | (8) | - | ||||||||||||||||||
Earnings before interest and taxes | 157 | (3 | ) | 154 | 53 | 70 | 123 | |||||||||||||||||||
Net interest expense | 66 | - | 66 | 62 | - | 62 | ||||||||||||||||||||
Income tax expense (recovery) | 18 | (1 | ) | (5) | 17 | (17 | ) | 27 | (5) | 10 | ||||||||||||||||
Net earnings (loss) | 73 | (2 | ) | 71 | 8 | 43 | 51 | |||||||||||||||||||
Non-controlling interests | 15 | - | 15 | 10 | - | 10 | ||||||||||||||||||||
Net earnings (loss) attributable to TransAlta shareholders | 58 | (2 | ) | 56 | (2 | ) | 43 | 41 | ||||||||||||||||||
Preferred share dividends | 9 | - | 9 | 9 | - | 9 | ||||||||||||||||||||
Net earnings (loss) attributable to common shareholders | 49 | (2 | ) | 47 | (11 | ) | 43 | 32 | ||||||||||||||||||
Weighted average number of common shares outstanding in the period | 270 | 270 | 258 | 258 | ||||||||||||||||||||||
Net earnings (loss) per share attributable to common shareholders | 0.18 | 0.17 | (0.04 | ) | 0.12 |
__________________
(1) | Impacts associated with certain de-designated and ineffective hedges. |
(2) | Flood-related maintenance costs. |
(3) | Decrease in finance lease receivable. |
(4) | Mine depreciation that is included in fuel and purchased power for presentation purposes. |
(5) | Net tax effect of all non-comparable items. |
(6) | Gain on sale of PP&E that is included in depreciation and amortization for presentation purposes. |
(7) | Total adjustments for gain on sale of PP&E and mine depreciation. |
(8) | Non-comparable item. |
TRANSALTA CORPORATION / Q1 2014 19
Funds from Operations, Free Cash Flow, Funds from Operations per Share, and Free Cash Flow per Share
Presenting these items from period to period provides management and investors with a proxy for the amount of cash generated from operating activities before changes in working capital, and provides the ability to evaluate cash flow trends more readily in comparison with results from prior periods. During the fourth quarter of 2013, we adjusted the calculation of free cash flow to be calculated as FFO less sustaining capital expenditures, dividends paid on preferred shares, and distributions paid to subsidiaries’ non-controlling interests. FFO per share and free cash flow per share are calculated as follows using the weighted average number of common shares outstanding during the period:
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Cash flow from operating activities | 279 | 256 | ||||||
Payment of restructuring costs | - | 4 | ||||||
Timing of payments related to assumption of pension obligations | - | 9 | ||||||
Decrease in finance lease receivable | 1 | 1 | ||||||
Change in non-cash operating working capital balances | (42 | ) | (77 | ) | ||||
FFO | 238 | 193 | ||||||
Deduct: | ||||||||
Sustaining capital expenditures | (64 | ) | (51 | ) | ||||
Dividends paid on preferred shares | (9 | ) | (9 | ) | ||||
Distributions paid to subsidiaries' non-controlling interests | (26 | ) | (19 | ) | ||||
Free cash flow | 139 | 114 | ||||||
Weighted average number of common shares outstanding in the period | 270 | 258 | ||||||
FFO per share | 0.88 | 0.75 | ||||||
Free cash flow per share | 0.51 | 0.44 |
A reconciliation of comparable EBITDA to FFO is as follows:
3 months ended March 31 | ||||||||
2014 | 2013 | |||||||
Comparable EBITDA | 310 | 268 | ||||||
Realized gain from risk management activities | 5 | - | ||||||
Interest expense | (61 | ) | (58 | ) | ||||
Provisions | (2 | ) | (7 | ) | ||||
Current income tax expense | (8 | ) | (8 | ) | ||||
Realized foreign exchange gain | 4 | 3 | ||||||
Decommissioning and restoration costs settled | (3 | ) | (5 | ) | ||||
Payment of restructuring costs | - | 4 | ||||||
Timing of payments related to assumption of pension obligations | - | 9 | ||||||
Other non-cash items | (7 | ) | (13 | ) | ||||
FFO | 238 | 193 |
20 TRANSALTA CORPORATION / Q1 2014
FINANCIAL POSITION
The following chart highlights significant changes in the Condensed Consolidated Statements of Financial Position from Dec. 31, 2013 to March 31, 2014:
Increase/ | ||
(Decrease) | Primary factors explaining change | |
Accounts receivable | (81) | Timing of customer receipts |
Prepaid expenses | 27 | Prepayment of annual insurance premiums, royalties, and service agreements |
Assets held for sale | 211 | Transfer of CE Gen, Wailuku, and Blackrock from investments and other long-term assets |
Investments | (192) | Transfer of CE Gen and Wailuku under equity investments to assets held for sale |
Finance lease receivable (current and long-term) | 12 | Favourable changes in foreign exchange rates |
Property, plant, and equipment, net | (22) | Depreciation for the period partially offset by additions and favourable changes in foreign exchange rates |
Deferred income tax assets | (10) | Net deferred income tax expense |
Risk management assets (current and long-term)(1) | (11) | Price movements and changes in underlying positions and settlements |
Dividends payable | (32) | Reduction of quarterly dividend |
Long-term debt (including current portion) | (33) | Reduction of borrowings under credit facility partially offset by unfavourable changes in foreign exchange rates |
Decommissioning and other provisions (current and long-term) | 11 | Fluctuations in period end discount rates |
Risk management liabilities (current and long-term)(1) | (14) | Price movements and changes in underlying positions and settlements |
Equity attributable to shareholders | 16 | Net earnings for the period partially offset by declared dividends |
FINANCIAL INSTRUMENTS
Refer to Note 19 of the notes to the audited consolidated financial statements within our 2013 Annual Report and Note 7 of our interim condensed consolidated financial statements as at and for the three months ended March 31, 2014 for details on Financial Instruments. Refer to the Risk Management section of our 2013 Annual Report and Note 8 of our interim condensed consolidated financial statements for further details on our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2013.
Energy Trading may enter into commodity transactions involving non-standard features for which market observable data is not available. These are defined under IFRS as Level III financial instruments. Level III financial instruments are not traded in an active market and fair value is, therefore, developed using valuation models based upon internally developed assumptions or inputs. Our Level III fair values are determined using data such as unit availability, transmission congestion, or demand profiles. Fair values are validated on a quarterly basis by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the financial statements.
__________________
(1) | After giving effect to the $160 million reduction in risk management assets and liabilities as at Dec. 31, 2013, as described in the Current Accounting Changes section of this MD&A. |
TRANSALTA CORPORATION / Q1 2014 21
We also have various contracts with terms that extend beyond five years. As forward market prices are not available for the full period of these contracts, the value of these contracts must be derived by reference to a forecast that is based on a combination of external and internal fundamental modeling, including discounting. As a result, these contracts are classified in Level III. These contracts are for specified prices with counterparties that we believe to be creditworthy.
At March 31, 2014, total Level III financial instruments had a net asset carrying value of $33 million (Dec. 31, 2013 - $66 million net asset).
As at March 31, 2014, cumulative gains of $4 million related to certain cash flow hedges that were previously de-designated and no longer meet the criteria for hedge accounting continue to be deferred in AOCI and will be reclassified to net earnings as the forecasted transactions occur or immediately if the forecasted transactions are no longer expected to occur.
STATEMENTS OF CASH FLOWS
The following chart highlights significant changes in the Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2014 compared to the same period in 2013:
3 months ended March 31 | 2014 | 2013 | Primary factors explaining change | ||||||
Cash and cash equivalents, beginning of period | 42 | 27 | |||||||
Provided by (used in): | |||||||||
Operating activities | 279 | 256 | Increase in cash earnings of $58 million, partially offset by a decrease in the change in working capital of $35 million | ||||||
Investing activities | (105 | ) | (150 | ) | Decrease in additions to PP&E and intangibles of $55 million and an increase in investing non-cash working capital balances of $10 million, partially offset by an increase in realized losses on financial instruments of $14 million and a negative impact of $6 million related to changes in collateral received from or paid to counterparties | ||||
Financing activities | (180 | ) | (84 | ) | An increase in repayments of borrowings under credit facilities of $83 million, an increase in common share cash dividends of $30 million, and an increase in distributions paid to subsidiaries' non-controlling interests of $7 million, partially offset by realized gains on financial instruments of $25 million | ||||
Translation of foreign currency cash | 1 | 1 | |||||||
Cash and cash equivalents, end of period | 37 | 50 |
LIQUIDITY AND CAPITAL RESOURCES
Liquidity risk arises from our ability to meet general funding needs, engage in trading and hedging activities, and manage the assets, liabilities, and capital structure of the Corporation. Liquidity risk is managed by maintaining sufficient liquid financial resources to fund obligations as they come due in the most cost-effective manner.
22 TRANSALTA CORPORATION / Q1 2014
Our liquidity needs are met through a variety of sources, including cash generated from operations, availability under our long-term credit facilities, and long-term debt or equity issued under our Canadian and U.S. shelf registrations. Our primary uses of funds are operational expenses, capital expenditures, dividends, distributions to non-controlling interests partners, and interest and principal payments on debt securities.
Debt
Long-term debt totalled $4.3 billion as at March 31, 2014 compared to $4.3 billion as at Dec. 31, 2013.
Credit Facilities
At March 31, 2014, we had a total of $2.1 billion (Dec. 31, 2013 - $2.1 billion) of committed credit facilities, of which $0.9 billion (Dec. 31, 2013 - $0.9 billion) is not drawn and is available, subject to customary borrowing conditions. At March 31, 2014, the $1.2 billion (Dec. 31, 2013 - $1.2 billion) of credit utilized under these facilities was comprised of actual drawings of $0.8 billion (Dec. 31, 2013 - $0.8 billion) and letters of credit of $0.4 billion (Dec. 31, 2013 - $0.4 billion).
In addition to the $0.9 billion available under the credit facilities, we have $37 million of available cash.
Share Capital
On April 28, 2014, we had 271.8 million common shares outstanding, 12.0 million Series A, 11.0 million Series C, and 9.0 million Series E first preferred shares outstanding. At March 31, 2014, we had 270.4 million (March 31, 2013 - 258.4 million) common shares issued and outstanding. At March 31, 2014, we had 32.0 million (Dec. 31, 2013 - 32.0 million) first preferred shares issued and outstanding.
We issue common shares for the reinvestment of dividends, for cash proceeds, or upon exercise of stock options and other share-based payment plans.
During the three months ended March 31, 2014, 2.1 million (March 31, 2013 - 3.7 million) common shares were issued under the Dividend Reinvestment and Optional Common Share Purchase Plan (the “Plan”) for $28 million (March 31, 2013 - $53 million).
Letters of Credit and Cash Collateral
We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, energy trading activities, hedging activities, and purchase obligations. At March 31, 2014, we provided letters of credit totalling $427 million (Dec. 31, 2013 - $370 million) and cash collateral of $26 million (Dec. 31, 2013 - $20 million). These letters of credit and cash collateral secure certain amounts included on our Condensed Consolidated Statements of Financial Position under risk management liabilities and decommissioning and other provisions.
TRANSALTA CORPORATION / Q1 2014 23
CLIMATE CHANGE AND THE ENVIRONMENT
In Alberta there are requirements for coal-fired generation units to implement additional air emission controls for oxides of nitrogen (“NOx”) and sulphur dioxide (“SO2”) once they reach the end of their respective PPAs, in most cases at 2020. These regulatory requirements were developed by the province in 2004 as a result of multi-stakeholder discussions under Alberta’s Clean Air Strategic Alliance (“CASA”). However, the release of the federal Greenhouse Gas (“GHG”) regulations may create a potential misalignment between the CASA air pollutant requirements and schedules, and the GHG retirement schedules for older coal plants, which in themselves will result in significant reductions of NOx, SO2, and particulates. We are in discussions with the provincial government in an effort to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply.
In the U.S., on June 25, 2013, President Obama announced his Climate Action Plan, which sets out plans for GHG emission standards to be imposed by the Environmental Protection Agency (“EPA”) for new and existing power plants. Subsequently, on Sept. 20, 2013, the EPA issued draft regulations for new coal-fired plants that, if adopted, would require new coal plants to achieve GHG emissions of no more than 1,100 pounds per MWh of carbon dioxide (significantly below current average emissions for coal-fired plants) in order to be approved. These regulations are expected to be finalized by mid-2014. These proposed regulations do not currently have an impact on our operations. Standards for existing units are under development and will be issued in draft form by June 1, 2014 for finalization by mid-2015. State implementation plans are to be completed a year later. There will be few additional details as to how existing coal (and potentially natural gas) units might be treated until the EPA releases a draft rule. Furthermore, the U.S. Supreme Court has agreed to review a challenge to the EPA’s right to regulate GHG emissions from stationary sources like power plants, so the future of this regulation is uncertain.
2014 OUTLOOK
Business Environment
Power Prices
In 2014, power prices in Alberta are expected to be lower than 2013 as a result of more baseload generation and fewer planned maintenance outages across the market. However, prices can vary based on supply and weather conditions. In the Pacific Northwest, we expect prices to settle higher than in 2013 due to marginally higher natural gas prices. In Ontario, prices for the balance of the year are expected to be higher than 2013 due to higher natural gas prices.
Environmental Legislation
The finalization of the federal Canadian GHG regulations for coal-fired power has initiated further activities. We are in discussions with the Alberta government in an effort to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply. This may provide additional flexibility to coal-fired generators in meeting such regulatory requirements. For further information on the Canadian GHG regulations, please refer to the Significant Events section of our 2013 Annual MD&A.
In addition, there are ongoing discussions between the federal and provincial governments regarding a national Air Quality Management System for air pollutants. In Alberta’s recently released Clean Air Strategy, the province indicated that its provincial air quality management system will operationalize any national system. Our current outlook is that, for Alberta, provincial regulations will be considered as equivalent to any future national framework.
24 TRANSALTA CORPORATION / Q1 2014
On Jan. 21, 2013, the Ontario government released a discussion paper for public input on reducing GHG emissions in the province, with the stated intent of developing GHG regulations for all major industrial sectors by 2015. No specific targets or regulatory approaches have yet been proposed.
In the U.S., the President’s Climate Action Plan provides an indication of how GHG regulation of existing fossil-fuel based generation may unfold, although we expect the implementation process to take several years. Our agreement with Washington State, established in April 2011, provides regulatory clarity at the state level regarding an emissions regime related to the Centralia Coal plant until 2025. We expect this agreement may mitigate separate federal action from the EPA. Additionally, new federal air pollutant regulations for the power sector are anticipated, but are not expected to directly affect our coal-fired operations in Washington State.
Effective January 2013, direct deliveries of power to the California Independent System Operator were subject to Cap and Trade Regulations established by the California Air Resource Board. We continue to monitor our GHG inventory into California.
In Australia, the carbon tax implemented in July 2012 remains in place. However, on Nov. 13, 2013, the then elected Liberal government introduced legislation to repeal the carbon tax by July 2014, and replace it with a Direct Action plan that would fund industry for actions to reduce emissions. The legislation has not yet been passed. While TransAlta’s gas-fired operations are subject to the tax, all related costs are passed on to contracted customers.
We continue to closely monitor the progress and risks associated with environmental legislation changes on our future operations.
Economic Environment
In 2014, we expect slow to moderate growth in all markets. We continue to monitor global events and their potential impact on the economy and our supplier and commodity counterparty relationships.
We had no material counterparty losses in the first quarter of 2014. We continue to monitor counterparty credit risk and have established risk management policies to mitigate counterparty risk. We do not anticipate any material change to our existing credit practices and continue to deal primarily with investment grade counterparties.
Operations
Capacity, Production, and Availability
Generating capacity is expected to increase primarily due to the commencement of operations at our Solomon power station in Australia. Prior to the effect of any economic dispatching, overall production is expected to increase in 2014 compared to 2013 due to Sundance Units 1 and 2 returning to service, lower planned and unplanned outages, the commencement of commercial operations at our Solomon power station, and the acquisition of Wyoming Wind. Overall availability is expected to be in the range of 88 to 90 per cent in 2014.
Contracted Cash Flows
As a result of Alberta PPAs, long-term contracts, and other short-term physical and financial contracts, on average, approximately 75 per cent of our capacity is contracted over the next seven years. On an aggregated portfolio basis, depending on market conditions, we target being up to 90 per cent contracted for the upcoming calendar year. As at the end of the first quarter of 2014, approximately 88 per cent of our 2014 capacity was contracted. The average prices of our short-term physical and financial contracts for 2014 are approximately $55 per MWh in Alberta and approximately U.S.$40 per MWh in the Pacific Northwest.
TRANSALTA CORPORATION / Q1 2014 25
Fuel Costs
Mining coal in Alberta is subject to cost increases due to greater overburden removal, inflation, capital investments, and commodity prices. Seasonal variations in coal costs at our Alberta mine are minimized through the application of standard costing. Coal costs for 2014, on a standard cost per tonne basis, are expected to be seven to nine per cent lower than 2013 due to Sundance Units 1 and 2 operating for a full year and the benefits realized from insourcing operational accountability from Prairie Mines and Royalty Ltd. at the Highvale Mine during 2013.
Although we own the Centralia mine in the State of Washington, it is not currently operational. Fuel at Centralia Thermal is purchased from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel per MWh for 2014 is expected to increase between one to three per cent.
The value of coal inventories is assessed for impairment at the end of each reporting period. If the inventory is impaired, further charges are recognized in net earnings.
We purchase natural gas from outside companies coincident with production or have it supplied by our customers, thereby minimizing our risk to changes in prices. The continued success of unconventional gas production in North America could reduce the year-to-year volatility of prices in the near term.
We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risks.
Energy Trading
Earnings from our Energy Trading Segment are affected by prices in the market, overall strategies adopted, and changes in legislation. We continuously monitor both the market and our exposure in order to maximize earnings while still maintaining an acceptable risk profile. Our 2014 objective is for Energy Trading to contribute between $80 million and $100 million in gross margin for the year as markets return to more normal volatility for the remainder of the year.
Exposure to Fluctuations in Foreign Currencies
Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. dollar, euro, and Australian dollar by offsetting foreign-denominated assets with foreign-denominated liabilities and by entering into foreign exchange contracts. We also have foreign-denominated expenses, including interest charges, which largely offset our foreign-denominated revenues.
Net Interest Expense
Net interest expense for 2014 is expected to be higher than in 2013 due to a higher proportion of fixed-rate debt, which has a higher interest rate than variable rate debt, and lower capitalized interest. However, changes in interest rates and in the value of the Canadian dollar relative to the U.S. dollar can affect the amount of net interest expense incurred.
Liquidity and Capital Resources
If there is increased volatility in power and natural gas markets, or if market trading activities increase, we may need additional liquidity in the future. We expect to maintain adequate available liquidity under our committed credit facilities.
26 TRANSALTA CORPORATION / Q1 2014
Accounting Estimates
A number of our accounting estimates, including those outlined in the Critical Accounting Policies and Estimates section of our 2013 Annual MD&A, are based on the current economic environment and outlook. Under the current economic environment, market fluctuations could impact, among other things, future commodity prices, foreign exchange rates, and interest rates, which could, in turn, impact future earnings, and the unrealized gains or losses associated with our risk management assets and liabilities, and asset valuation for our asset impairment calculations.
Income Taxes
The effective tax rate on earnings, excluding non-comparable items for 2014, is expected to be approximately 17 to 22 per cent, which is lower than the statutory tax rate of 25 per cent, due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned and the effect of certain deductions that do not fluctuate with earnings.
Capital Expenditures
Our major projects are focused on sustaining our current operations and supporting our growth strategy.
Growth and Major Project Expenditures
A summary of the significant growth and major projects that are in progress is outlined below:
Total Project | 2014 | Target | |||||||||||||||||||
Estimated spend | Spent to date(1) | Estimated spend | Spent to date(1) | completion date | Details | ||||||||||||||||
Project | |||||||||||||||||||||
Australia natural gas pipeline(2) | 86 | 11 | 86 | 11 | Q1 2015 | 270 kilometer pipeline to supply natural gas to our Solomon power station in Western Australia | |||||||||||||||
Transmission | 10 | - | 10 | - | Q4 2014 | Regulated transmission that receives a return on investment | |||||||||||||||
Hydro life extension | 15 - 20 | 2 | 15 - 20 | 2 | Q4 2014 | Generator replacement and turbine runner improvements to extend the life of selected plants | |||||||||||||||
Total | 111 - 116 | 13 | 111 - 116 | 13 |
__________________
(1) | Represents amounts spent as of March 31, 2014. |
(2) | Includes certain natural gas conversion costs at the Solomon power station that will be recognized as a finance lease receivable. |
TRANSALTA CORPORATION / Q1 2014 27
Sustaining and Productivity Expenditures(1)
For 2014, our estimate for total sustaining and productivity expenditures, net of any contributions received, is allocated among the following:
Category | Description | Expected cost | Spent to date(1) | ||||||
Routine capital | Expenditures to maintain our existing generating capacity | 110 - 115 | 23 | ||||||
Mining equipment and land purchases | Expenditures related to mining equipment and land purchases | 45 - 50 | 5 | ||||||
Finance leases | Payments related to mining equipment under finance leases | 5 - 10 | 2 | ||||||
Planned major maintenance | Regularly scheduled major maintenance | 175 - 190 | 34 | ||||||
Total sustaining expenditures | 335 - 365 | 64 | |||||||
Productivity capital | Projects to improve power production efficiency and corporate improvement initiatives | 10 - 15 | 2 | ||||||
Total sustaining and productivity expenditures | 345 - 380 | 66 |
Our planned major maintenance program relates to regularly scheduled major maintenance activities and includes costs related to inspection, repair and maintenance, and replacement of existing components. It excludes amounts for day-to-day routine maintenance, unplanned maintenance activities, and minor inspections and overhauls, which are expensed as incurred. Details of the 2014 planned major maintenance program are outlined as follows:
Coal | Gas and Renewables | Expected spend in 2014 | Spent to date(1) | |||||||||||||
Capitalized | 120 - 130 | 55 - 60 | 175 - 190 | 34 | ||||||||||||
Expensed | - | 0 - 5 | 0 - 5 | - | ||||||||||||
120 - 130 | 55 - 65 | 175 - 195 | 34 | |||||||||||||
Coal | Gas and Renewables | Total | Lost to date(1) | |||||||||||||
GWh lost | 2,200 - 2,210 | 400 - 410 | 2,600 - 2,620 | 10 |
Financing
Financing for these capital expenditures is expected to be provided by cash flow from operating activities, existing borrowing capacity, dividends reinvested under the Plan, and capital markets. The funds required for committed growth, sustaining capital, and productivity projects are not expected to be significantly impacted by the current economic environment due to the highly contracted nature of our cash flows, our financial position, and the amount of capital available to us under existing committed credit facilities.
28 TRANSALTA CORPORATION / Q1 2014
CURRENT ACCOUNTING CHANGES
Inception Gains and Losses
We restated the Condensed Consolidated Statement of Financial Position as at Dec. 31, 2013 to reclassify the inception gains or losses arising from differences between the fair value of a financial instrument at initial recognition (the transaction price) and the amount calculated through a valuation model. These amounts were previously reported as gross contra-risk management assets or liabilities. The adjustment reclassifies them as direct offsets to the value of the derivative contract to which they relate. As a result of the adjustment, long-term risk management assets and long-term risk management liabilities were reduced by $160 million at Dec. 31, 2013. Corresponding adjustments to the Dec. 31, 2012 Condensed Consolidated Statement of Financial Position were immaterial. Refer to Note 7(C) in our interim condensed consolidated financial statements as at and for the three months ended March 31, 2014 for further information on inception gains and losses.
IAS 32 Financial Instruments: Presentation
On Jan. 1, 2014, we adopted the amendments to IAS 32 Financial Instruments: Presentation. There was no impact of adopting the IAS 32 amendments on the condensed consolidated financial statements.
IAS 36 Impairment of Assets
On Jan. 1, 2014, we adopted the amendments to the disclosure requirements of IAS 36 Impairment of Assets. The amended disclosure requirements did not have an impact on the condensed consolidated financial statements.
Comparative Figures
Certain comparative figures have been reclassified to conform to current period’s presentation. These reclassifications did not impact previously reported net earnings.
FUTURE ACCOUNTING CHANGES
Accounting standards that have been previously issued by the International Accounting Standards Board (“IASB”) but are not yet effective, and have not been applied include: IFRS 9 Financial Instruments. In February 2014, the IASB indicated that IFRS 9 will be effective for annual periods beginning on or after Jan. 1, 2018. We continue to assess the impact of adopting this standard. Please refer to the Future Accounting Changes section of our 2013 Annual MD&A for more information.
TRANSALTA CORPORATION / Q1 2014 29
SELECTED QUARTERLY INFORMATION
Q2 2013 | Q3 2013 | Q4 2013 | Q1 2014 | |||||||||||||
Revenue | 542 | 623 | 587 | 775 | ||||||||||||
Net earnings (loss) attributable to common shareholders | 15 | (9 | ) | (66 | ) | 49 | ||||||||||
Net earnings (loss) per share attributable to common shareholders, basic and diluted | 0.06 | (0.03 | ) | (0.25 | ) | 0.18 | ||||||||||
Comparable net earnings per share | 0.03 | 0.15 | 0.00 | 0.17 | ||||||||||||
Q2 2012 | Q3 2012 | Q4 2012 | Q1 2013 | |||||||||||||
Revenue | 398 | 522 | 646 | 540 | ||||||||||||
Net earnings (loss) attributable to common shareholders | (798 | ) | 56 | 39 | (11 | ) | ||||||||||
Net earnings (loss) per share attributable to common shareholders, basic and diluted | (3.52 | ) | 0.24 | 0.15 | (0.04 | ) | ||||||||||
Comparable net earnings (loss) per share | (0.10 | ) | 0.18 | 0.22 | 0.12 |
Basic and diluted earnings per share attributable to common shareholders and comparable earnings per share are calculated each period using the weighted average common shares outstanding during the period. As a result, the sum of the earnings per share for the four quarters making up the calendar year may sometimes differ from the annual earnings per share.
DISCLOSURE CONTROLS AND PROCEDURES
Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934, as amended (“Exchange Act”) are recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating and implementing possible controls and procedures.
There has been no change in the internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2014, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.
30 TRANSALTA CORPORATION / Q1 2014
FORWARD-LOOKING STATEMENTS
This MD&A, the documents incorporated herein by reference, and other reports and filings made with the securities regulatory authorities include forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumptions were made and on management’s experience and perception of historical trends, current conditions, and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”, “believe”, “expect”, “anticipate”, “intend”, “plan”, “project”, “foresee”, “potential”, “enable”, “continue”, or other comparable terminology. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance to be materially different from that projected.
In particular, this MD&A contains forward-looking statements pertaining to our business and anticipated future financial performance including, for example: the timing and the completion and commissioning of projects under development, including major projects, and their attendant costs; expectations regarding the AESO’s plans for resolving regional constraints on Alberta’s transmission system; spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spend, and maintenance, and the variability of those costs; the impact of certain hedges on future reported earnings and cash flows; expectations related to future earnings and cash flow from operating and contracting activities; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity in both the short term and long term, and the resulting impact on electricity prices; the impact of load growth, increased capacity, and natural gas costs on power prices; expectations in respect of generation availability, capacity, and production; expectations regarding the role different energy sources will play in meeting future energy needs; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation and their expected impact on us and the timing of the implementation of such regimes and regulations, as well as the cost of complying with resulting regulations and laws; our expectations relating to the FERC’s approval of our California settlement and the outcome of proceedings before the AUC; our trading strategies and the risk involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; accounting estimates; anticipated growth rates in our markets; expectations for the outcome of existing or potential legal and contractual claims, regulatory investigations, and disputes; expectations regarding the renewals of collective bargaining agreements; expectations for the ability to access capital markets at reasonable terms; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the U.S. dollar and other currencies in locations where we do business; the monitoring of our exposure to liquidity risk; expectations in respect of the global economic environment and growing scrutiny by investors relating to sustainability performance; our credit practices; the estimated contribution of Energy Trading activities to gross margin; and expectations relating to the performance of TransAlta Renewables’ assets.
TRANSALTA CORPORATION / Q1 2014 31
Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices and the availability of fuel supplies required to generate electricity; our ability to contract our generation for prices that will provide expected returns; the regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water, or wind required to operate our facilities; natural disasters; the threat of domestic terrorism and cyber-attacks; equipment failure and our ability to carry out the repairs in a cost-effective manner or timely manner; energy trading risks; industry risk and competition; fluctuations in the value of foreign currencies and foreign political risks; the need for additional financing; structural subordination of securities; counterparty credit risk; insurance coverage; our provision for income taxes; legal, regulatory, and contractual proceedings involving the Corporation; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; development projects and acquisitions; the satisfactory receipt of applicable regulatory approvals for existing and proposed operations and growth initiatives; and the satisfactory closing of CE Gen, Blackrock, CalEnergy, and Wailuku. The foregoing risk factors, among others, are described in further detail in the Risk Management section of our 2013 Annual MD&A and under the heading “Risk Factors” in our 2014 Annual Information Form.
Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties, and assumptions, the forward-looking events might occur to a different extent or at a different time than we have described, or might not occur. We cannot assure that projected results or events will be achieved.
32 TRANSALTA CORPORATION / Q1 2014
SUPPLEMENTAL INFORMATION
March 31, 2014 | Dec. 31, 2013 | ||||||||
Closing market price (TSX) ($) | 12.84 | 13.48 | |||||||
Price range for the last 12 months (TSX) ($) | High | 15.55 | 16.86 | ||||||
Low | 12.60 | 12.91 | |||||||
Debt to invested capital (%) | 55.3 | 55.6 | |||||||
Debt to invested capital excluding non-recourse debt(1) (%) | 52.8 | 53.3 | |||||||
Debt to invested capital including finance lease obligation and non-recourse debt (%) | 55.4 | 55.7 | |||||||
Debt to comparable EBITDA(2) (times) | 4.0 | 4.2 | |||||||
Return on equity attributable to common shareholders(2) (%) | (0.5 | ) | (3.1 | ) | |||||
Comparable return on equity attributable to common shareholders(1), (2) (%) | 4.2 | 3.6 | |||||||
Return on capital employed(2) (%) | 4.1 | 2.8 | |||||||
Comparable return on capital employed(1), (2) (%) | 5.5 | 5.2 | |||||||
Cash dividends per share(2) ($) | 1.05 | 1.16 | |||||||
Price to comparable earnings ratio(1), (2) (times) | 35.7 | 43.5 | |||||||
Earnings coverage(2) (times) | 1.3 | 0.9 | |||||||
Dividend payout ratio based on net earnings(2) (%) | (2,536.4 | ) | (431.0 | ) | |||||
Dividend payout ratio based on comparable earnings(1), (2) (%) | 290.6 | 377.8 | |||||||
Dividend payout ratio based on funds from operations(1), (2), (3) (%) | 36.0 | 42.0 | |||||||
Dividend yield(2) (%) | 8.2 | 8.6 | |||||||
Adjusted cash flow to debt(2), (3) (%) | 18.4 | 16.9 | |||||||
Adjusted cash flow to interest coverage(2), (3) (times) | 4.2 | 4.0 |
(1) | These ratios incorporate items that are not defined under IFRS. None of these measurements should be used in isolation or as a substitute for the Corporation’s reported financial performance or position as presented in accordance with IFRS. These ratios are useful complementary measurements for assessing the Corporation’s financial performance, efficiency, and liquidity and are common in the reports of other companies but may differ by definition and application. For a reconciliation of the Non-IFRS measures used in this calculation, refer to the Non-IFRS Measures section of this MD&A. |
(2) | Last 12 months. |
(3) | The December 2013 ratios have been adjusted for the impact of the California claim. |
RATIO FORMULAS
Debt to invested capital = long-term debt including current portion - cash and cash equivalents / long-term debt including current portion + non-controlling interests + equity attributable to shareholders - cash and cash equivalents
Debt to comparable EBITDA = long-term debt including current portion - cash and cash equivalents / comparable EBITDA
Return on equity attributable to common shareholders = net earnings attributable to common shareholders or earnings on a comparable basis / average equity attributable to common shareholders excluding AOCI
Return on capital employed = earnings before non-controlling interests and income taxes + net interest expense or comparable earnings before non-controlling interests and income taxes + net interest expense / average invested capital excluding AOCI
Price to comparable earnings ratio = current period’s closing market price / comparable earnings per share
Earnings coverage = net earnings attributable to shareholders + income taxes + net interest expense / interest on debt - interest income
Dividend payout ratio = common share dividends / net earnings attributable to common shareholders or earnings on a comparable basis or funds from operations
Dividend yield = dividend per common share / current period’s closing market price
Adjusted cash flow to debt = cash flow from operating activities before changes in working capital / average total debt - average cash and cash equivalents
Adjusted cash flow to interest coverage = cash flow from operating activities before changes in working capital + interest on debt - interest income - capitalized interest / interest on debt - interest income
TRANSALTA CORPORATION / Q1 2014 33
GLOSSARY OF KEY TERMS
Availability - A measure of the time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year that a generating unit is capable of generating electricity, regardless of whether or not it is actually generating electricity.
British Thermal Units (Btu) - A measure of energy. The amount of energy required to raise the temperature of one pound of water one degree Fahrenheit, when the water is near 39.2 degrees Fahrenheit.
Capacity - The rated continuous load-carrying ability, expressed in megawatts, of generation equipment.
Force Majeure - Literally means “major force”. These clauses excuse a party from liability if some unforeseen event beyond the control of that party prevents it from performing its obligations under the contract.
Geothermal Power – Power derived from a steam turbine. The turbine is driven either by steam produced from hot water or by natural steam that derives its energy from heat found in rocks or fluids at various depths beneath the surface of the earth. The energy is extracted by drilling and/or pumping.
Gigawatt - A measure of electric power equal to 1,000 megawatts.
Gigawatt Hour (GWh) - A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.
Greenhouse Gas (GHG) - Gases having potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.
Heat Rate - A measure of conversion, expressed as Btu/MWh, of the amount of thermal energy required to generate electrical energy.
Megawatt (MW) - A measure of electric power equal to 1,000,000 watts.
Megawatt Hour (MWh) - A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.
Power Purchase Arrangement (PPA) - A long-term arrangement established by regulation for the sale of electric energy from formerly regulated generating units to buyers.
Renewable Power - Power generated from renewable terrestrial mechanisms including wind, geothermal, and solar with regeneration.
Spark Spread - A measure of gross margin per MW (sales price less cost of natural gas).
Turbine - A machine for generating rotary mechanical power from the energy of a stream of fluid (such as water, steam, or hot gas). Turbines convert kinetic energy of fluids to mechanical energy through the principles of impulse and reaction or a mixture of the two.
Unplanned Outage - The shut down of a generating unit due to an unanticipated breakdown.
Value at Risk (VaR) - A measure to manage earnings exposure from energy trading activities.
34 TRANSALTA CORPORATION / Q1 2014
TransAlta Corporation
110 - 12th Avenue S.W.
Box 1900, Station “M”
Calgary, Alberta Canada T2P 2M1
Phone
403.267.7110
Website
www.transalta.com
CST Trust Company
P.O. Box 700 Station “B”
Montreal, Québec Canada H3B 3K3
Phone
Toll-free in North America: 1.800.387.0825
Toronto or outside North America: 416.682.3860
Fax
514.985.8843
E-mail
inquiries@canstockta.com
Website
www.canstockta.com
FOR MORE INFORMATION
Media and Investor Inquiries
Investor Relations
Phone
1.800.387.3598 in Canada and United States
or 403.267.2520
Fax
403.267.7405
E-mail
investor_relations@transalta.com
TRANSALTA CORPORATION / Q1 2014 35