Item 1.-Business of this Form 10-K for further discussion about the United States state environmental regulations we face. At this time, other than with regard to RGGI (further described below) and the proposed Hawaii regulations relating to the collection of fees on GHG emissions, the Company cannot estimate the costs of compliance with United States federal, regional or state CO2 emissions reduction legislation or initiatives, due to the fact that most of these proposals are not being actively pursued or are in the early stages of development and any final regulations or laws, if adopted, could vary drastically from current proposals, or in the case of California, due to the fact that we anticipate such costs will be passed through to our offtakers under the terms of existing tolling agreements.
The RGGI program became effective in January 2009. The first regional auction of RGGI allowances needed to be acquired by power generators to comply with state programs implementing RGGI was held in September 2008, with subsequent auctions occurring approximately every quarter. Our subsidiary in Maryland is our only subsidiary that was subject to RGGI in 2012. Of the approximately 39.9 million metric tonnes of CO2 emitted in the United States by our subsidiaries in 2012 (ownership adjusted), approximately 1.4 million metric tonnes were emitted by our subsidiary in Maryland. While CO2 emissions from businesses operated by subsidiaries of the Company are calculated globally in metric tonnes, RGGI allowances are denominated in short tons. (1 metric tonne equals 2,200 pounds and 1 short ton equals 2,000 pounds.) For forecasting purposes, the Company has modeled the impact of CO2 compliance based on a three-year average of CO2 emissions for its business that is subject to RGGI to the extent that it may not be able to pass through compliance costs. The model includes a conversion from metric tonnes to short tons as well as the impact of some market recovery by merchant plants and contractual and regulatory provisions. The model also utilizes a price of $1.93 per allowance under RGGI. The source of this allowance price estimate was the clearing price in the recent RGGI allowance auction held in December 2012. Based on these assumptions, the Company estimates that the RGGI compliance costs could be approximately $3 million for 2013. Given the fact that the assumptions utilized in the model may prove to be incorrect, there is a significant risk that our actual compliance costs under RGGI will differ from our estimates by a material amount and that our model could underestimate our costs of compliance.
In addition to government regulators, other groups such as politicians, environmentalists and other private parties have expressed increasing concern about GHG emissions. For example, certain financial institutions have expressed concern about providing financing for facilities which would emit GHGs, which can affect our ability to obtain capital, or if we can obtain capital, to receive it on commercially viable terms. Further, rating agencies may decide to downgrade our credit ratings based on the emissions of the businesses operated by our subsidiaries or increased compliance costs which could make financing unattractive. In addition, plaintiffs have brought tort lawsuits against the Company because of its subsidiaries’ GHG emissions. Unless the United States Congress acts to preempt such suits as part of comprehensive federal legislation, additional lawsuits may be brought against the Company or its subsidiaries in the future. While the litigation mentioned has been dismissed, it is impossible to predict whether similar future lawsuits are likely to prevail or result in damages awards or other relief. Consequently, it is impossible to determine whether such lawsuits are likely to have a material adverse effect on the Company’s consolidated results of operations and financial condition.
Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect the Company’s business and operations, and any such potential impact may render it more difficult for our businesses to obtain financing. For example, extreme weather events could result in increased downtime and operation and maintenance costs at the electric power generation facilities and support facilities of the Company’s subsidiaries. Variations in weather conditions, primarily temperature and humidity also would be expected to affect the energy needs of customers. A decrease in energy consumption could decrease the revenues of the Company’s subsidiaries. In addition, while revenues would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of the fossil fuel-fired electric power generation facilities of the Company’s subsidiaries. Changes in temperature, precipitation and snow pack conditions also could affect the amount and timing of hydroelectric generation.
In addition to potential physical risks noted by the Intergovernmental Panel on Climate Change, there could be damage to the reputation of the Company and its subsidiaries due to public perception of GHG emissions by the Company’s subsidiaries, and any such negative public perception or concerns could ultimately result in a decreased demand for electric power generation or distribution from our subsidiaries. The level of GHG emissions made by subsidiaries of the Company is not a factor in the compensation of executives of the Company.
If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on the electric power generation businesses of the Company’s subsidiaries and on the Company’s consolidated results of operations, financial condition and cash flows.
Tax legislation initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.
Our subsidiaries have operations in the United States and various non-United States jurisdictions. As such, we are subject to the tax laws and regulations of the United States federal, state and local governments and of many non-United States jurisdictions. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these initiatives. In addition, United States federal, state and local, as well as non-United States, tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities.
We and our affiliates are subject to material litigation and regulatory proceedings.
We and our affiliates are parties to material litigation and regulatory proceedings. See Item 3.-Legal Proceedings below. There can be no assurances that the outcome of such matters will not have a material adverse effect on our consolidated financial position.
The SEC is conducting an informal inquiry relating to our restatements.
We have been cooperating with an informal inquiry by the SEC Staff concerning our past restatements and related matters, and have been providing information and documents to the SEC Staff on a voluntary basis. Although we have not received correspondence regarding this inquiry for some time, we have not been advised that the matter is closed. Because we are unable to predict the outcome of this inquiry, the SEC Staff may disagree with the manner in which we have accounted for and reported the financial impact of the adjustments to
previously filed financial statements and there may be a risk that the inquiry by the SEC could lead to circumstances in which we may have to further restate previously filed financial statements, amend prior filings or take other actions not currently contemplated.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We maintain offices in many places around the world, generally pursuant to the provisions of long-and short-term leases, none of which we believe are material. With a few exceptions, our facilities, which are described in Item 1 of this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the project’s related finance facility. In addition, the majority of our facilities are located on land that is leased. However, in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate.
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of December 31, 2012.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.3 billion ($626 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the FDC for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the FDC. Eletropaulo’s subsequent appeals were dismissed. In February 2010, the FDC appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directed the FDC to proceed accordingly. However, in December 2012, the FDC disregarded the AC’s decision that the parties were entitled to full discovery and an expert appraisal of the issues prior to the resolution of the case and, instead, issued a decision finding Eletropaulo liable for the debt. The AC subsequently granted Eletropaulo’s request to suspend the execution suit in the FDC and thereafter annulled the FDC’s decision. The case will now return to the FDC for proceedings in accordance with the AC’s April 2010 decision. If the FDC again finds Eletropaulo
liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. In December 2012, the FDC dismissed the lawsuit. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1 million ($488 thousand) as of December 31, 2012, or pay an indemnification amount of approximately R$15 million ($7 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case is being remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision.
In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd. (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and seeking interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. In September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPA’s terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. The matter has been awaiting further hearing. However, in December 2012, the parties executed a settlement agreement amending the PPA and resolving the dispute. The amended PPA is subject to regulatory approval.
In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgás and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers, and requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FSCP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. In May 2010, the MPF filed an appeal with the Superior Court of Justice (“SCJ”) challenging the transfer. In November 2012, the SCJ ruled that the lawsuit must be returned to the FCSP. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008, and the Public Attorney’s office no longer has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained
registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($3 million). The injunction was rejected. The above-referenced proposal to FEPAM with respect to containing and remediating the contamination was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response, Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. In October 2011, the State Prosecution Office presented a new request to the court of Triunfo for an injunction against Florestal, Sul and CEEE for the removal of the alleged sources of contamination and remediation, and the court granted the injunction against CEEE but did not grant injunctive relief against Florestal or Sul. CEEE appealed such decision, and the State of Rio Grande do Sul Court of Appeals upheld the decision. As required by the injunction, CEEE has started the removal and disposal of the contaminants, which is ongoing, and Sul is not at risk to bear any of such remediation costs, which are estimated to be approximately R$14.7 million ($7 million). In November 2012, the inspections performed by the court expert and supervised by Sul confirmed that CEEE is fulfilling the injunction by removing the contaminants. The case is in the evidentiary stage awaiting the production of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area.
In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal is pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska, filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants’ alleged GHG emissions have contributed to alleged global warming which, in turn, allegedly has led to the erosion of the plaintiffs’ alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other unspecified damages from the defendants. The Company filed a motion to dismiss the case, which the District Court granted in October 2009. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit. In September 2012, the Ninth Circuit affirmed the District Court’s decision. The plaintiffs’ subsequent petition for en banc review was denied by the Ninth Circuit. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Esado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF seeks an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserts that if it is determined that AESU is responsible for the termination of the GSA, AESU is liable for TGM’s alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. The hearing on liability issues took place in December 2011, and thereafter the arbitrators took those issues under consideration. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.
In April 2009, the Antimonopoly Agency in Kazakhstan initiated an investigation of the power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”), for the period from January through February 2009. The Antimonopoly Agency determined that the Hydros abused their market position and charged monopolistically high prices for power from January through February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($3 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police have expanded the periods at issue to the entirety of 2009 in the case of UK HPP and from January through October 2009 in the case of Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($8 million) from UK HPP and KZT 1.3 billion ($9 million) from Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida believes it has meritorious defenses in that action; however, there can be no assurances that it will be successful.
In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review (“NSR”) requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material
impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.
In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, and November 2011, substantially similar personal injury lawsuits were filed by a total of 49 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages and the Company is not able to estimate damages, if any, at this time. The AES defendants moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. The AES defendants again moved for partial dismissal of those amended complaints, and in May 2012, the Superior Court ruled on the motion in the November 2009 lawsuit, dismissing the plaintiff’s claims for future medical monitoring expenses but declining to dismiss their claims under Dominican Republic Law 64-00. The Superior Court has not yet ruled on the motion for partial dismissal of the April 2010 lawsuit. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the remaining six lawsuits, as well as any subsequently filed similar lawsuits. The Superior Court has also ordered that, for the present, discovery will proceed only in the November 2009 lawsuit and will be limited to causation and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.
On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately 155 million. The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately 240 million ($317 million) in the arbitration, unspecified damages for alleged injury to reputation, and other relief. The arbitral hearing on the merits was scheduled for March 2013, but recently was rescheduled by the arbitrators to a date to be determined. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
On February 11, 2011 AES Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately
R$1 million ($510,370) and the suspension of AES Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), AES Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction in the fine if AES Eletropaulo agrees to recover the affected area with additional vegetation. AES Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernando do Campo initiated a Civil Proceeding to review the compliance by AES Eletropaulo with the terms of any possible settlement. AES Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. AES Eletropaulo is currently awaiting the approval of the recovery project by the Park Administrator.
In May 2011, a putative class action was filed in the Mississippi federal court against the Company and numerous unrelated companies. The lawsuit alleges that greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert claims for public and private nuisance, trespass, negligence, and declaratory judgment. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. The Company is unable to estimate the alleged damages at this time. These and other plaintiffs previously brought a substantially similar lawsuit in the federal court but failed to obtain relief. In October 2011, the Company and other defendants filed motions to dismiss the lawsuit. In March 2012, the federal court granted the motion and dismissed the lawsuit. The plaintiffs appealed to the U.S. Court of Appeals for the Fifth Circuit. The appeal is fully briefed. The Company believes it has meritorious defenses and will defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.
In February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of Săo Paulo Federal Court against Eletropaulo and all other distribution companies in the State of Săo Paulo, claiming that the distribution companies had overcharged customers for electricity. SOSC asserts that the distribution companies’ tariffs had been incorrectly calculated by the Brazilian Regulatory Agency (“ANEEL”). ANEEL corrected the alleged error in May 2010. There are separate proceedings against ANEEL to determine whether the tariffs had been properly calculated. SOSC has moved for an injunction requiring tariffs to be corrected from the effective dates of the relevant concession contracts. Electropaulo has opposed that request on the ground that it did not wrongfully collect amounts from its customers, since its tariff was calculated in accordance with the concession contract with the Federal Government and ANEEL’s rules. If it does not prevail in the lawsuit, Eletropaulo estimates that its liability to customers could be approximately R$855 million ($417 million). Electropaulo believes it has meritorious defenses and will defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.
In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking approximately R$1.2 billion ($586 million) in services tax (“ISS”) that allegedly had not been collected on revenues for services rendered by Eletropaulo. Eletropaulo estimates that, with interest, the amount at issue has increased to approximately R$2 billion ($1 billion). Eletropaulo has challenged the assessments on the ground that the revenues at issue were not subject to ISS. Eletropaulo believes it has meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NCI”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in
damages. The Dominican District Attorney has accepted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. Further, in August 2012, Coastal and NCI initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NCI have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NCI also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NCI further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however there can be no assurance that they will be successful in their efforts.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Stock Repurchase Program
The Company’s Board of Directors recently increased the share buyback authorization by $300 million, all of which is available. Under the program, the Company may repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and it can be modified or terminated by the Company’s Board at any time.
During the year ended December 31, 2012, shares of common stock repurchased under this plan totaled 24,790,384 at a total cost of $301 million plus a nominal amount of commissions (average of $12.16 per share including commissions), bringing the cumulative total purchases under the program to 58,715,189 shares at a total cost of $680 million, which includes a nominal amount of commissions (average of $11.58 per share including commissions).
There were no repurchases of common stock in the fourth quarter of 2012.
Market Information
Our common stock is currently traded on the New York Stock Exchange (“NYSE”) under the symbol “AES.” The closing price of our common stock as reported by the NYSE on February 20, 2013, was $11.37, per share. The Company repurchased 24,790,384, 25,541,980 and 8,382,825 shares of its common stock in 2012, 2011 and 2010, respectively. The following tables set forth the high and low stock prices and cash dividends declared for the periods indicated:
Dividends
We commenced a cash dividend of $0.04 per share beginning in the fourth quarter of 2012. There can be no assurance that the AES Board will declare the dividend or, if declared, the amount of any dividend.
Under the terms of our senior secured credit facility, which we entered into with a commercial bank syndicate, we have limitations on our ability to pay cash dividends and/or repurchase stock. Our project subsidiaries’ ability to declare and pay cash dividends to us is subject to certain limitations contained in the project loans, governmental provisions and other agreements to which our project subsidiaries are subject. See
the information contained under Item 12.-Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters-Securities Authorized for Issuance under Equity Compensation Plans of this Form 10-K.
Holders
As of February 20, 2013, there were approximately 6,336 record holders of our common stock.
Performance Graph
THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE
Source: Bloomberg
We have selected the Standard and Poor’s (“S&P”) 500 Utilities Index as our peer group index. The S&P 500 Utilities Index is a published sector index comprising the 32 electric and gas utilities included in the S&P 500.
The five year total return chart assumes $100 invested on December 31, 2007 in AES Common Stock, the S&P 500 Index and the S&P 500 Utilities Index. The information included under the heading “Performance Graph” shall not be considered “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected financial data as of the dates and for the periods indicated. You should read this data together with Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and the notes thereto included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K. The selected financial data for each of the
years in the five year period ended December 31, 2012 have been derived from our audited Consolidated Financial Statements. Prior period amounts have been restated to reflect discontinued operations in all periods presented. Our historical results are not necessarily indicative of our future results.
Acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the Notes to the Consolidated Financial Statements included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further explanation of the effect of such activities. Please also refer to Item 1A.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of Our Business
We are a diversified power generation and utility company organized into six market-oriented Strategic Business Units (“SBUs”): US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and the Caribbean), EMEA (Europe, Middle East and Africa), and Asia. For additional information regarding our business, see Item 1.-Business of this Form 10-K.
Our Organization - The management reporting structure is organized along six SBUs-led by our Chief Operating Officer (“COO”), who in turn reports to our Chief Executive Officer (“CEO”). Our CEO and COO are based in Arlington, Virginia. During the fourth quarter of 2012, the Company completed the restructuring of its operational management and reporting process into six SBUs. For financial reporting purposes, the Company has identified eight reportable segments based on the six SBUs. Accordingly, management’s discussion and analysis of revenue and gross margin is organized as follows:
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US SBU
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US-Generation segment
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US-Utilities segment
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Andes SBU
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Andes-Generation
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Brazil SBU
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Brazil-Generation segment
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Brazil-Utilities segment
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MCAC SBU
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MCAC-Generation segment
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EMEA SBU
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EMEA-Generation segment
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Asia SBU
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Asia-Generation segment
Corporate and Other-The Company’s EMEA and MCAC utilities as well as Corporate are reported within “Corporate and Other” because they do not require separate disclosure under segment reporting accounting guidance. See Note 17-Segment and Geographic Information included in Item 8.-Financial Statements and Supplementary Data for further discussion of the Company’s segment structure used for financial reporting purposes.
Management’s Priorities
Management is focused on the following priorities:
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Management of our portfolio of generation and utility businesses to create value for our stakeholders, including customers and shareholders, through safe, reliable, and sustainable operations and effective cost management;
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Driving our operating business to manage capital more effectively and to increase the amount of discretionary cash available for deployment into debt repayment, growth investments, shareholder dividends and share buybacks;
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Realignment of our geographic focus. To this end, we will continue to exit markets where we do not have a competitive advantage or where we are unable to earn a fair risk-adjusted return relative to monetization alternatives. In addition, we will focus our growth investments on platform expansions or opportunities to expand our existing operations; and
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Reduce the cash flow and earnings volatility of our businesses by proactively managing our currency, commodity and political risk exposures, mostly through contractual and regulatory mechanisms, as well as commercial hedging activities. We also will continue to limit our risk by utilizing non-recourse project financing for the majority of our businesses.
2012 Performance
During 2012, we executed on a comprehensive plan to improve operations, leverage our global scale and expertise, reduce our overhead and development costs, increase the sources of cash and the returns from our investments, and streamline the portfolio. These actions helped us to achieve our financial targets, despite challenges we faced at certain businesses, including AES Gener in Chile, Eletropaulo in Brazil and DP&L in the U.S.
Safe, Reliable and Sustainable Operations. In terms of operating performance, we benefitted from the first full year of contributions from our new businesses, which collectively represented more than 1,900 MW of capacity additions brought on-line with the oversight of our in-house construction management team.
We also benefitted from the results of our efforts to enhance the reliability of our generation fleet, particularly at Masinloc (Asia SBU) and Southland (US SBU). Further, we reduced our overhead and development costs by $90 million, exceeding our cost reduction target of $65 million. These positive drivers were partially offset by declines at our Andes and Brazil SBUs due to higher cost of replacement energy, lower prices and outages and in Chile and the negative impact of the tariff reset at Eletropaulo in Brazil. Further, we recognized a $1.82 billion goodwill impairment at DP&L in the U.S.
Improving Available Capital and Deployment of Discretionary Cash. In terms of enhancing the sources and uses of our discretionary cash, we improved our available capital by increasing operating cash flow and selling non-core assets. In 2012, we deployed our discretionary cash to pay down $531 million of recourse debt, repurchase 24.8 million shares for $301 million, at an average share price of $12.16, declared the first cash dividend since 1994 and invested $195 million in our subsidiaries to expand our existing facilities.
Realigning Our Geographic Focus. Finally, in an effort to streamline our portfolio, we sold eight assets for total equity proceeds to AES of more than $600 million and announced plans to exit five countries (China, Czech Republic, France, Hungary and Ukraine) where we did not have a compelling competitive advantage or where we are unable to earn a fair, risk-adjusted return, relative to monetization alternatives. To supplement our future growth, we commenced construction on 208 MW of platform expansion projects, including Guacolda V in Chile, Tunjita in Colombia and two wind projects in the United Kingdom.
Despite some challenges in 2012, we met our financial goals and completed the capital allocation commitments we made to our shareholders.
Earnings Per Share Results in 2012
(1) See reconciliation and definition under Non-GAAP Measures.
During the year ended December 31, 2012, diluted earnings per share from continuing operations decreased principally due to the goodwill impairment expense of $2.41 per share recognized in connection with the interim goodwill impairment indicator identified during the third quarter at DPL, in the United States. See Item 8.-Financial Statements and Supplementary Data - Note 10 - Goodwill and Other Intangible Assets for further details.
Adjusted earnings per share, a non-GAAP measure, increased by 22% primarily due to the contribution of new businesses, lower general and administrative expenses and a lower share count, partially offset by the tariff reset at Eletropaulo and higher cost of replacement energy and lower prices in Chile.
Other Operating Highlights
(1) See reconciliation and definition below under Non-GAAP Measures.
The following briefly describes the key changes in our reported revenue, gross margin, net income attributable to The AES Corporation, net cash provided by operating activities, diluted earnings per share from continuing operations and adjusted earnings per share (a non-GAAP measure) for the year ended December 31, 2012 compared to 2011 and 2010 and should be read in conjunction with our Consolidated Results of Operations and Segment Analysis discussion within Management’s Discussion and Analysis of Financial Condition below.
Components of Revenue and Cost of Sales-Revenue includes revenue earned from the sale of energy from our utilities and the production of energy from our generation plants, which are classified as regulated and non-regulated on the Consolidated Statements of Operations, respectively. Revenue also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the sale of electricity. Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, operations and maintenance costs, depreciation and amortization expense, bad debt expense and recoveries, general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.
Net Cash Provided by Operating Activities-Consists of the operating cash flow of all consolidated subsidiaries, including noncontrolling interests.
Year Ended December 31, 2012
Revenue increased $1.2 billion, or 7%, to $18.1 billion in 2012 compared with $16.9 billion in 2011. Key drivers of the increase included:
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the impact of new business of $1.9 billion including DPL, acquired in November 2011; Angamos, Maritza, Laurel Mountain and Changuinola, which commenced commercial operations in April, June, July and October of 2011, respectively, along with MountainView 4 which commenced operations in February 2012; and
•
the unfavorable impact of foreign currency translation of $1.3 billion.
Excluding the impact of foreign currency and new businesses mentioned above, the SBU drivers included:
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US-Overall favorable impact of $121 million due to the temporary restart of two units at Southland in California, higher prices at IPL in Indiana and fewer outage days at Hawaii, slightly offset by lower volume at IPL due to milder weather.
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Andes-Overall unfavorable impact of $6 million due to lower exports from Termoandes in Argentina to Chile, lower prices in Argentina and the impact of outages in Argentina, almost entirely offset by higher volume in Chile and Argentina and higher prices in Colombia.
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Brazil-Overall favorable impact of $262 million due to higher tariffs to cover pass-through costs, higher contract and spot prices at Tietê and higher demand in the distribution companies partially offset by lower tariff at Eletropaulo due to the tariff reset.
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MCAC-Overall favorable impact of $216 million due to higher prices and volume from gas sales and higher ancillary services in the Dominican Republic, higher pass-through electricity costs in El Salvador and the favorable impact of Esti coming back into service, slightly offset by lower pass-through fuel costs at Merida in Mexico.
•
EMEA-Overall unfavorable impact of $70 million due to the sale of 80% of our ownership in Cartagena in February 2012 and lower availability and reduced contract capacity prices in Ballylumford in Northern Ireland, partially offset by a non-recurring arbitration settlement at Cartagena, a mark-to-market loss on an embedded derivative at Sonel in Cameroon in 2011 that did not recur, higher volume and tariffs in the Ukraine and higher volume net of lower prices at Kilroot.
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Asia-Overall favorable impact of $121 million due to higher market demand and the reversal of a contingency at Masinloc in the Philippines and higher demand at Kelanitissa in Sri Lanka caused by lower hydrology and better plant reliability.
Gross margin decreased $349 million, or 9%, to $3.7 billion in 2012 compared with $4.1 billion in 2011. Key drivers of the decrease included:
•
the unfavorable impact of foreign currency translation of $172 million; offset by
•
the favorable impact of new business of $463 million, as discussed above.
Excluding the impact of foreign currency and new businesses on gross margin as mentioned above, the key SBU drivers included:
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US-Overall favorable impact of $67 million due to the temporary restart of two units at Southland, better availability at Hawaii, higher demand at DPL and higher prices at IPL slightly offset by lower volume at IPL.
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Andes-Overall unfavorable impact of $169 million due to lower prices in Chile, higher replacement energy cost in Chile and outages, outages in Argentina, and maintenance and higher fixed costs in Argentina and Chile partially offset by higher volume in Chile.
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Brazil-Overall unfavorable impact of $689 million due to lower tariffs as a result of the tariff reset of 2011 which was postponed to 2012 at Eletropaulo, for which we have a 16% economic ownership, and higher fixed costs at all businesses partially offset by higher volume and tariffs at Sul.
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MCAC-Overall unfavorable impact of $28 million due to lower volume in Panama and higher fixed costs in Puerto Rico partially offset by the impact of Esti returning to service.
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EMEA-Overall favorable impact of $128 million due to a non-recurring arbitration settlement at Cartagena, a mark-to-market loss on an embedded derivative at Sonel in 2011 that did not recur, higher volume offset by lower prices at Kilroot, higher volume and tariffs in the Ukraine and lower fixed costs at Sonel partially offset by the sale of 80% of our ownership in Cartagena.
•
Asia-Overall favorable impact of $66 million due to higher market demand and the reversal of a contingency at Masinloc.
Net loss attributable to The AES Corporation was $912 million in 2012, which is a decrease of $1 billion compared to net income of $58 million in 2011. The key driver of the decrease was the goodwill impairment at DPL of $1.82 billion as described in Note 10-Goodwill Impairment and Other Intangible Assets included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K.
Excluding the goodwill impairment at DPL, the Company would have reported net income attributable to AES of $905 million, which is an improvement of $847 million compared to 2011. The key drivers of this increase were:
•
the favorable impact of gross margin earned by new businesses, mainly our wholly-owned subsidiaries: DPL, Maritza, and Changuinola, unfavorable impact in 2011 of an unrealized mark-to-market derivative at Sonel, which is a 56% owned subsidiary, higher demand at Masinloc, a 92% owned subsidiary, partially offset by a reduced gross margin at Eletropaulo, in which we hold only a 16% economic interest and a lower gross margin earned by our generation businesses in Chile and Argentina;
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the gains related to the sale in 2012 of 80% of our interest in Cartagena and the sale of our investments in China, as well as the loss recorded in 2011 on the sale of our Argentina distribution businesses;
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a decrease in losses from the operation of discontinued businesses, mainly related to Eastern Energy in New York, which was deconsolidated in December 2011;
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the decrease in asset impairments related to Wind projects and Kelanitissa;
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lower general and administrative expenses in 2012 compared to 2011; and
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the prior year premium paid on the early retirement of debt in Chile and at IPL.
These increases were partially offset by:
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higher foreign currency transaction losses in 2012 compared to 2011; and
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an increase in interest expense primarily due to debt at DPL, which was acquired in November 2011, and additional debt at the Parent Company to finance the acquisition of DPL.
Net cash provided by operating activities increased $17 million, or 1%, to $2.9 billion during 2012 compared to 2011, mainly due to the following:
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US-an increase of $320 million at our utility businesses primarily due to the operations, net of debt service costs, of DPL which was acquired in November 2011;
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Andes-an increase of $57 million driven by cash provided by the operating activities of the new plant at Angamos, recovery of value added tax at Campiche and reduced working capital requirements at Gener, partially offset by reduced gross margin from Gener operations other than Angamos;
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Brazil-a decrease of $503 million at our utility businesses primarily driven by higher priced energy purchases, regulatory charges and transmission costs payments, higher operating and maintenance expenses and lower accounts receivable collections due to the lower tariff starting in July 2012 at Eletropaulo, partially offset by a lower payment of income taxes;
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MCAC-an increase of $25 million at our generation businesses primarily due to the operations of the Esti plant being back on line from June 2012 and higher volumes of PPA sales at Panama and lower coal volume and price in 2012 at Itabo, partially offset by lower collections and lower sales in the Dominican Republic and higher taxes paid at Panama;
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EMEA-an increase of $42 million driven primarily by cash provided by the operating activities of the new plant at Maritza partially offset by a loss in revenue from a generator failure at Ballylumford in Northern Ireland; and
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Asia-an increase of $88 million driven primarily by Masinloc in the Philippines due to higher demand and reduced working capital requirements.
Year Ended December 31, 2011
Revenue increased $1.5 billion, or 10%, to $16.9 billion in 2011 compared with $15.4 billion in 2010. Key drivers of the increase included:
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the favorable impact of foreign currency of $460 million; and
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the impact of new businesses of $746 million including Ballylumford in Northern Ireland and DPL in the United States, acquired in August and late November 2011, respectively, and Angamos I, in Chile, and Maritza, in Bulgaria, and Angamos II, in Chile, that commenced operations in April, June and October 2011, respectively.
Excluding the impact of foreign currency and new businesses mentioned above, the SBU drivers included:
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US-Overall favorable impact of $3 million due to higher prices related to a fuel adjustment clause almost entirely offset by lower retail and wholesale volume at IPL.
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Andes-Overall favorable impact of $297 million due to higher prices in Argentina and Gener and higher volume at Chivor in Colombia, partially offset by lower prices in Chivor.
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Brazil-Overall unfavorable impact of $128 million due to lower prices at Eletropaulo primarily related to the estimated impact of the July 2011 tariff reset which was finalized by the Brazilian energy regulatory agency in July 2012, partially offset by higher demand at Eletropaulo.
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MCAC-Overall favorable impact of $270 million due to higher prices, volume and gas sales and higher ancillary services in the Dominican Republic, higher prices in Puerto Rico and higher pass-through electricity costs in El Salvador partially offset by outages in Panama.
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EMEA-Overall unfavorable impact of $157 million due to lower revenue from pass-through energy costs at Cartagena in Spain and by an unrealized mark-to-market derivative loss at Sonel in Cameroon partially offset by higher rates in the Ukraine and better plant availability at Ballylumford.
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Asia-Overall unfavorable impact of $12 million due to lower volume and price at Masinloc in the Phillipines almost entirely offset by higher rates and demand at Kelanitissa in Sri Lanka.
Gross margin increased $243 million, or 6%, to $4.1 billion in 2011 compared with $3.8 billion in 2010. Key drivers of the increase included:
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the favorable impact of foreign currency of $111 million; and
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new businesses of $197 million as discussed above.
Excluding the impact of foreign currency and new businesses on gross margin as mentioned above, the key SBU drivers included:
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US-Overall unfavorable impact of $41 million due to higher fuel costs at Shady Point in Oklahoma and Hawaii and lower wholesale margin and retail margin at IPL.
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Andes-Overall favorable impact of $175 million due to higher volume in Electrica Santiago at Gener in Chile.
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Brazil-Overall unfavorable impact of $11 million due to lower prices at Eletropaulo, as discussed above, offset by increased volume and lower fixed costs.
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MCAC-Overall favorable impact of $53 million due to higher volume and prices in the Dominican Republic as discussed above and higher volume in Panama partially offset by outages in Panama.
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EMEA-Overall unfavorable impact of $165 million due to an unrealized mark-to-market derivative loss at Sonel and lower volume and rates at Kilroot in Northern Ireland.
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Asia-Overall unfavorable impact of $71 million due to lower demand and prices and higher fuel and fixed costs at Masinloc.
Net income attributable to The AES Corporation increased $49 million to $58 million in 2011, compared to $9 million in 2010. Key drivers of the increase included:
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an increase in gross margin as described above;
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a decrease in asset impairment expense due to higher prior year impairments related to the Southland generation facility offset primarily by current year impairments on wind turbines and deposits; and
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a decrease in losses from discontinued operations primarily related to a gain on sale of Brazil Telecom in 2011 partially offsetting a loss on disposal of our Argentina distribution businesses and losses at other discontinued businesses compared to a significant impairment recorded at New York in 2010.
These increases were partially offset by:
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an increase in interest expense due to increased debt and fees related to the DPL acquisition, reduced interest capitalization at Maritza due to commencement of operations in June 2011, and an unfavorable impact of foreign currency translation in Brazil; and
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a decrease in net equity in earnings of affiliates partially offset by income tax expense related to the sale of the Company’s indirect investment in Companhia Energética de Minas Gerais (“CEMIG”).
Net cash provided by operating activities decreased $581 million, or 17%, to $2.9 billion in 2011 compared with $3.5 billion in 2010, mainly due to the following:
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US-a decrease of $131 million at our generation businesses primarily due to reduced operations in New York prior to its deconsolidation in December 2011, partially offset by the deconsolidation of Thames in 2011;
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Brazil-a decrease of $352 million at our utility businesses primarily driven by higher income tax payments of which $84 million was due to the sale of Brazil Telecom in October 2011, for which the pre-tax net sales proceeds of $890 million are recorded in cash flows from investing activities, and a one-time cash savings of $107 million mainly related to the utilization of a tax credit received as a result of the REFIS program in 2010, lower accounts receivable collections at Eletropaulo and higher payments for energy purchases, operation and maintenance expenses and pension contributions. These impacts were partially offset by higher accounts receivable collections at Sul;
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Asia-a decrease of $56 million at Masinloc, due to lower gross margin.
Non-GAAP Measures
Adjusted pre-tax contribution (“adjusted PTC”) and Adjusted earnings per Share (“adjusted EPS”) are non-GAAP supplemental measures that are used by management and external users of our consolidated financial statements such as investors, industry analysts and lenders.
We define adjusted PTC as pre-tax income from continuing operations attributable to AES excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) significant gains or losses due to dispositions and acquisitions of business interests, (d) significant losses due to impairments, and (e) costs due to the early retirement of debt. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis.
We define adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) significant gains or losses due to dispositions and acquisitions of business interests, (d) significant losses due to impairments, and (e) costs due to the early retirement of debt.
The GAAP measure most comparable to adjusted PTC is income from continuing operations attributable to AES. The GAAP measure most comparable to adjusted EPS is diluted earnings per share from continuing operations. We believe that adjusted PTC and adjusted EPS better reflect the underlying business performance of the Company and are considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose or acquire business interests or retire debt, which affect results in a given period or periods. In addition, for adjusted PTC, earnings before tax represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Adjusted PTC and adjusted EPS should not be construed as alternatives to income from continuing operations attributable to AES and diluted earnings per share from continuing operations, which are determined in accordance with GAAP.
The Company reported a loss from continuing operations of $1.21 per share in 2012. The Company did not have a loss from continuing operations in 2011 and 2010. For purposes of measuring diluted loss per share under GAAP, potential common stock was excluded from weighted average shares in 2012 as their inclusion would be anti-dilutive. However, for purposes of computing adjusted EPS, the Company has included the impact of potential common stock as the inclusion of the defined adjustments result in income for adjusted EPS. The table below reconciles the weighted average shares used in GAAP diluted loss per share to the weighted average shares used in calculating the non-GAAP measure of diluted loss per share, a component of the adjusted EPS calculation. The weighted average shares used in calculating the non-GAAP measure of diluted loss per share has also been used in calculating the per share impact of the adjusting items in the calculation of adjusted EPS.
Reconciliation of denominator used for Adjusted Earnings Per Share
* NCI is defined as noncontrolling interest
(1) Unrealized derivative (gains) losses were net of income tax per share of $0.04, $0.01 and $0.00 in 2012, 2011 and 2010, respectively.
(2) Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.00, $0.00 and ($0.01) in 2012, 2011 and 2010, respectively.
(3) Amount primarily relates to the gains from the sale of 80% of our interest in Cartagena for $178 million ($109 million, or $0.14 per share, net of income tax of $0.09 per share) and equity method investments in China of $24 million ($25 million, or $0.03 per share, including an income tax credit of $1 million, or $0.00 per share).
(4) The Company did not adjust for the gain or the related tax effect from the sale of its indirect investment in CEMIG in its determination of Adjusted EPS because the gain was recognized by an equity method investee. The Company does not adjust for transactions of its equity method investees in its determination of Adjusted EPS.
(5) Amount primarily relates to the goodwill impairment at DPL of $1.82 billion ($1.82 billion, or $2.39 per share, net of income tax of $0.00 per share). Amount also includes other-than-temporary impairment of equity method investments in China of $32 million ($32 million, or $0.04 per share, net of income tax of $0.00 per share), and at InnoVent of $17 million ($17 million, or $0.02 per share, net of income tax of $0.00 per share), as well as asset impairments of wind turbines and projects of $41 million ($26 million, or $0.03 per share, net of income tax of $0.02 per share), at Kelanitissa of $19 million ($17 million, or $0.02 per share, net of noncontrolling interest of $2 million and of income tax of $0.00 per share), and at St. Patrick of $11 million ($11 million, or $0.01 per share, net of income tax of $0.00 per share).
(6) Amount includes other-than-temporary impairment of equity method investments at Chigen, including Yangcheng, of $79 million ($79 million, or $0.10 per share, net of income tax of $0.00 per share), asset impairments of wind turbines of $116 million ($75 million, or $0.10 per share, net of income tax of $0.05 per share), Kelanitissa of $42 million ($38 million, or $0.05 per share, net of noncontrolling interest of $4 million and of income tax of $0.00 per share), Bohemia of $9 million ($9 million, and $0.01 per share, net of income tax of $0.00 per share), and goodwill impairment at Chigen of $17 million ($17 million or $0.02 per share, net of income tax of $0.00 per share).
(7) Amount primarily relates to asset impairments at Southland (Huntington Beach) of $200 million ($130 million, or $0.17 per share, net of income tax of $0.09 per share), at Deepwater of $79 million ($51 million, or $0.07 per share, net of income tax of $0.04 per share), and a goodwill impairment at Deepwater of $18 million ($18 million, or $0.02 per share, net of income tax of $0.00 per share).
(8) Amount primarily relates to the loss on retirement of debt at the Parent Company of $15 million ($10 million, or $0.01 per share, net of income tax of $0.01 per share).
(9) Amount includes loss on retirement of debt at Gener of $38 million ($22 million, or $0.03 per share, net of noncontrolling interest of $11 million and of income tax of $0.01 per share) and at IPL of $15 million ($10 million, or $0.01 per share, net of income tax of $0.01 per share).
(10) Amount includes loss on retirement of debt at the Parent Company of $15 million ($10 million, or $0.01 per share, net of income tax per share of $0.01), at Andres of $10 million ($10 million, or $0.01 per share, net of income tax per share of $0.00) and at Itabo of $8 million ($4 million, or $0.01 per share, net of noncontrolling interest of $4 million and income tax of $0.00 per share).
Consolidated Results of Operations
(1) Corporate and Other includes revenue from our utility businesses in El Salvador, Africa and Europe.
(2) Represents inter-segment eliminations primarily related to transfers of electricity from Tietê (Brazil-Generation) to Eletropaulo (Brazil-Utilities).
(3) Corporate and Other gross margin includes gross margin from our utility businesses in El Salvador, Africa and Europe.
Key Trends and Uncertainties
For key trends and uncertainties, see Item 1.-Business and Item 1A.-Risk Factors of this Form 10-K. Some of these factors are also described below. However, management expects that improved operating performance at certain businesses, growth from new business and global cost reduction initiatives may lessen or offset the impact of the challenges described below. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our gross margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise.
In 2013, we expect to face continued challenges at certain of our businesses:
On-going Regulatory Proceedings
Some of our utility companies, including DPL in the United States and AES Sul in Brazil, are in the process of their regulated tariff review and/or reset by the applicable regulatory agency. The tariff outcome will determine the amount that our utility companies can charge to customers for electricity.
On October 5, 2012, DPL filed an ESP with the PUCO to establish SSO rates that were to be in effect starting January 1, 2013. The plan requested approval of a non-bypassable charge that is designed to recover $138 million per year for five years from all customers. DPL also requested approval of a switching tracker that would measure the incremental amount of switching over a base case and defer the lost value into a regulatory asset which would be recovered from all customers beginning January 2014. The ESP states that DPL plans to file on or before December 31, 2013 its plan for legal separation of its generation assets. The ESP proposes a three year and five month transition to market, whereby a wholesale competitive bidding structure will be phased in to supply generation service to SSO customers. The PUCO is currently reviewing the filing and an evidentiary hearing is scheduled to begin on March 11, 2013. The PUCO authorized that the rates being collected prior to December 31, 2012 would continue until the new ESP rates go into effect. See Item 1.-Business-United States SBU, DPL included in this Form 10-K for further information. In addition to the regulatory risks noted above, DPL also faces a number of additional uncertainties related to the impact of customer switching and low power prices which could impact DPL’s results of operations, its ability to refinance certain debt (or to do so on favorable terms) which is due in the near to intermediate term, and/or realize the benefits associated with the remaining goodwill. Any of the above-referenced conditions, events or factors could have a material impact on the Company or its results of operations.
AES Sul in Brazil is currently undergoing the tariff reset process. A public hearing has started and will be concluded in March 2013, with the revised tariff to be implemented in April 2013.
Macroeconomic and Political Conditions
The Company is sensitive to changes in economic and political conditions, including foreign exchange rates. In Argentina and the Dominican Republic, the potential weakening of economic indicators, such as increased inflation, devaluation of the local currency, currency convertibility restrictions and large government deficits could have a material impact on the Company. Potential outcomes can include negative impacts in our gross
margin and cash flows, and create an inability of the business to pay dividends or obtain currency to service foreign obligations, all of which can negatively impact the value of our assets. See Item 7A
Item 7A - Quantitative and Qualitative Disclosures about Market Risk of this Form 10-K for more information.
Due to our global presence, the Company has significant exposure to foreign currency fluctuations. The exposure is primarily associated with the impact of the translation of our foreign subsidiaries’ operating results from their local currency to U.S. dollars that is required for the preparation of our consolidated financial statements. Additionally, there is a risk of transaction exposure when an entity enters into transactions, including debt agreements, in currencies other than their functional currency. These risks are further described in Item 1A.-Risk Factors of this Form 10-K, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.” In the year ended December 31, 2012, changes in foreign currency exchange rates have had a significant impact on our operating results. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics could be affected.
Fluctuations in Commodity Prices
The Company is sensitive to changes in natural gas prices. High coal prices relative to natural gas creates pressure at our U.S. businesses, which may affect the results of certain of our coal plants, particularly those which are merchant plants that are exposed to market risk and those that have hybrid merchant risk, meaning those businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts. See Item 7A.-Quantitative and Qualitative Disclosures About Market Risk of this Form 10-K for more information.
Global diversification helps us mitigate certain risks. Our presence in mature markets helps mitigate the exposure associated with our businesses in emerging markets. Additionally, our portfolio employs a broad range of fuels, including coal, gas, fuel oil, water (hydroelectric power), wind and solar, which reduces the risks associated with dependence on any one fuel source. However, to the extent the mix of fuel sources enabling our generation capabilities in any one market is not diversified, the spread in costs of different fuels may also influence the operating performance and the ability of our subsidiaries to compete within that market. For example, in a market where gas prices fall to a low level compared to coal prices, power prices may be set by low gas prices which can affect the profitability of our coal plants in that market. In certain cases, we may attempt to hedge fuel prices to manage this risk, but there can be no assurance that these strategies will be effective.
We also attempt to limit risk by hedging much of our interest rate and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the underlying business. However, we only hedge a portion of our currency and commodity risks, and our businesses are still subject to these risks, as further described in Item 1A.-Risk Factors of this Form 10-K, “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.” Commodity and power price volatility could continue to impact our financial metrics to the extent this volatility is not hedged. For a discussion of our sensitivities to commodity, currency and interest rate risk, see Item 7A.-Quantitative and Qualitative Disclosures About Market Risk of this Form 10-K.
Global Economic Considerations
During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatile and could have an adverse impact on our businesses in the event these recent trends continue.
Our business or results of operations could be impacted if we or our subsidiaries are unable to access the capital markets on favorable terms or at all, are unable to raise funds through the sale of assets or are otherwise unable to finance or refinance our activities. At this time, several European Union countries continue to face uncertain economic environments, the impacts of which are described below. The Company could also be
adversely affected if capital market disruptions result in increased borrowing costs (including with respect to interest payments on the Company’s or our subsidiaries’ variable rate debt) or if commodity prices affect the profitability of our plants or their ability to continue operations.
The Company could be adversely affected if general economic or political conditions in the markets where our subsidiaries operate deteriorate, resulting in a reduction in cash flow from operations, a reduction in the availability and/or an increase in the cost of capital, or if the value of our assets remains depressed or declines further. Any of the foregoing events or a combination thereof could have a material impact on the Company, its results of operations, liquidity, financial covenants, and/or its credit rating.
Our subsidiaries are subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our PPAs, fuel supply agreements, hedging agreements and other contractual arrangements) to deliver contracted commodities or services at the contracted price or to satisfy their financial or other contractual obligations. We have not suffered any material effects related to our counterparties during the year ended December 31, 2012. However, if macroeconomic conditions impact our counterparties, they may be unable to meet their commitments which could result in the loss of favorable contractual positions, which could have a material impact on our business.
United States-As noted in Item 1A - Risk Factors-“We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” of this Form 10-K and Item 7A.-Quantitative and Qualitative Disclosures About Market Risk-Commodity Price Risk of this Form 10-K, the Company’s U. S. businesses continue to face pressure as a result of low natural gas prices, the marginal price setting fuel in most U. S. markets. This has affected the results of certain of our coal-fired plants in the region, including our coal-fired generating assets within our utility businesses, like IPL, which benefit from high wholesale power prices in periods where our available generation exceeds our captive load obligations. At DPL, where retail competition exists, our coal-fired generating assets do not benefit from the captive load offset and, as such, are subject to greater sensitivity to changes in power prices. Businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts may not be fully hedged against changes in either power or fuel prices.
On December 27, 2012, the U.S. Bankruptcy Court for the District of Delaware issued its Order Confirming the Second Amended Joint Plan of Liquidation under Chapter 11 of the Bankruptcy Code filed by AES Eastern Energy, L.P. and certain affiliates that owned coal-fired plants in New York and had filed for bankruptcy in 2011. In accordance with its terms, the Plan became effective on December 28, 2012. An integral component of the Plan was the settlement between the Company, the Debtors and the Official Committee of Unsecured Creditors. Pursuant to that settlement, the Debtors and the Committee have released the Company and its non-debtor affiliates from claims and causes of action they have or may have in the future. In exchange, the Company paid $47 million to and waived all unpaid claims against the Debtors. In addition, the Company assumed a net pension liability of $25 million for employees of AES NY, L.L.C.
Argentina-In Argentina, the deterioration of certain economic indicators such as non-receding inflation, increased government deficits and foreign currency accessibility combined with the potential devaluation of the local currency and the potential fall in export commodity prices could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to corporate, and the value of our assets. At December 31, 2012, AES had noncurrent assets of $564 million in Argentina, including long-term receivables of $316 million. In addition, recent actions by the Argentine government may indicate deeper government intervention in the local economy. For example, on April 16, 2012, the Argentine government expropriated 51% of the assets of the country’s largest oil company. The statute used to expropriate the oil company is not applicable to our businesses in Argentina. However, potential deteriorating economic conditions or further government action could have a material impact on the Company or its financial statements.
Brazil-Given that approximately two-thirds of Brazil’s electric supply is dependent upon hydroelectric generation, changes in weather conditions can have a significant impact on reservoir levels and electricity prices.
The hot, dry summer has cause the reservoir levels to be lower than they have been in a number of years. If reservoir levels are not able to recover, or deteriorate further, it is expected that higher thermal dispatch will cause more volatility in spot prices. Although the purchased energy cost is a pass-through for AES’ distribution businesses in Brazil, gaps between the purchase of energy and recovery in the tariff could cause temporary cash flow constraints on those businesses. Also, to the extent that the hydroelectric facility would need to purchase energy to meet its contract needs, rather than generate the energy, it could have a material adverse impact on our results of operations.
Bulgaria-Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned national electricity distribution company. Maritza, a coal-fired generation facility, has experienced on-going delays in collections from their offtaker, although they were able to collect $73 million of past due receivables in the fourth quarter of 2012 from NEK, which brought down the outstanding receivables balance to $55 million as of December 31, 2012. There can be no assurance that the business will succeed in making these collections, which could result in a write-off of the receivables. In addition, depending on NEK’s ability to honor its obligations and other factors, the value of other assets could also be impaired, or the business may be in default of its loan covenants. The Company has long-lived assets in Bulgaria of $1.8 billion. Any of the above items could have a material impact on our results of operations. For further information on the importance of long-term contracts and our counterparty credit risk, see Item 1A.-Risk Factors-“We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” of this Form 10-K. As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
Euro Zone-During the past few years, certain European Union countries have continually faced a sovereign debt crisis and it is possible that this crisis could spread to other countries. This crisis has resulted in an increased risk of default by governments and the implementation of austerity measures in certain countries. If the crisis continues, worsens, or spreads, there could be a material adverse impact on the Company. Our businesses may be impacted if they are unable to access the capital markets, face increased taxes or labor costs, or if governments fail to fulfill their obligations to us or adopt austerity measures which adversely impact our projects. As discussed in Item 1A.-Risk Factors-“Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges” of this Form 10-K, our renewables businesses are dependent on favorable regulatory incentives, including subsidies, which are provided by sovereign governments, including European governments. If these subsidies or other incentives are reduced or repealed, or sovereign governments are unable or unwilling to fulfill their commitments or maintain favorable regulatory incentives for renewables, in whole or in part, this could impact the ability of the affected businesses to continue to sustain and/or grow their operations and could result in losses or asset impairments for these businesses which could be material. The carrying value of our investment in AES Solar Energy Ltd., whose primary operations are in Europe, was $130 million at December 31, 2012. In addition, any of the foregoing could also impact contractual counterparties of our subsidiaries in core power or renewables. If such counterparties are adversely impacted, then they may be unable to meet their commitments to our subsidiaries.
If global economic conditions deteriorate further, it could also affect the prices we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions pursuant to PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.
Impairments
Goodwill-The Company seeks business acquisitions as one of its growth strategies. We have achieved significant growth in the past as a result of several business acquisitions, which also resulted in the recognition of goodwill. As noted in Item 1A.-Risk Factors of this Form 10-K, there is always a risk that “Our acquisitions may not perform as expected.” One factor contributing to goodwill is the synergies expected from an acquisition that follow the integration of the acquired business with the existing operations of an entity. Thus, an entity’s ability to realize benefits of goodwill depends on the successful integration of the acquired business. If such integration efforts are not successful, it could be difficult to realize the benefits of goodwill, which could result in impairment of goodwill. Another factor relates to the market or commodity dynamics, which can change after the acquisition. For example, DPL recognized a goodwill impairment of $1.82 billion during 2012. See Note 10-Goodwill and Other Intangible Assets included in Item 1.- Financial Statements and Supplementary Data of this Form 10-K for further information.
The value of goodwill is also positively correlated with the economic environments in which our acquired businesses operate. Also, the evolving environmental regulations, including GHG regulations, around the world continue to increase the operating costs of our generation businesses. In extreme situations, environmental regulations could even make a once profitable business uneconomical. In addition, most of our generation businesses have a finite life and as the acquired businesses reach the end of their finite lives, the carrying amount of goodwill is gradually realized through their periodic operating results. The accounting guidance, however, prohibits the systematic amortization of goodwill and rather requires an annual impairment evaluation. Thus, as some of our acquired businesses approach the end of their finite lives, they may incur goodwill impairment charges even if there are no discrete adverse changes in the economic environment. For example, Ebute, our 294 MW gas-fired plant in Nigeria, currently operates under a 15 year PPA with the Nigerian national electricity distribution company that expires within the next few years. The inability to replace the PPA on similar terms or identify alternate uses for the plant could adversely affect the carrying amount of Ebute’s goodwill, which could be material. In our calculation of the fair value of the Ebute reporting unit, we have considered a market participant view that assumes significant expansion of the generation facility, which may be uncertain and is dependent upon regulatory approvals and financing availability, among other uncertainties. The carrying amount of the goodwill at December 31, 2012 was approximately $58 million.
In the fourth quarter of 2012, the Company completed its annual October 1 goodwill impairment evaluation and identified two reporting units, DPL and Ebute, that were considered “at risk”. A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. While there were no potential impairment indicators during the fourth quarter of 2012 related to DPL and Ebute that could result in the recognition of goodwill impairment, it is possible that we may incur goodwill impairment at any of our reporting units in future periods if adverse changes in their business or operating environments occur. The carrying amount of the goodwill at DPL and Ebute as of December 31, 2012 was approximately $759 million and $58 million, respectively.
Long-lived assets-The global economic conditions and other adverse factors discussed above heighten the risk of significant asset impairment. The Company continually evaluates the impact of any adverse changes in operating and business environments on the fair value of its long-lived assets.
Wind turbines-During the third quarter of 2012, the Company recognized an impairment expense of $20 million related to certain wind turbines held in storage. The Company determined that these turbines met the held-for-sale criteria due to the ongoing receipt of offers from potential buyers and less viable internal deployment scenarios. The turbines with a carrying amount of $45 million were written down to their estimated fair value (less costs to sell) of $25 million. As of December 31, 2012 the Company concluded the turbines should continue to be classified as held for sale and no adjustment to the carrying amount is required. It is reasonably possible that the turbines could incur further loss in value due to changing market conditions, regulatory environment and advances in technology. Refer to Note 21-Asset Impairment Expense included in Item 1.-Financial Statements and Supplementary Data of this Form 10-K for further information
Revenue and Gross Margin Analysis
US SBU
US-Generation
The following table summarizes revenue and gross margin for our US Generation segment for the periods indicated:
Fiscal Year 2012 versus 2011
Generation revenue for 2012 increased $77 million, or 10%, from 2011 primarily due to:
•
an increase of $28 million at Southland in California, primarily due to the short-term restart of two generating units at the Huntington Beach which were contracted through October 2012;
•
the impact of new business of $25 million from Mountain View IV in California and Laurel Mountain in West Virginia, which began operations in February of 2012 and July of 2011, respectively;
•
an increase of $13 million in Hawaii and $7 million at Beaver Valley in Pennsylvania, primarily due to higher volumes as a result of fewer outage days; and
•
$7 million higher revenue at Deepwater in Texas, primarily due to the sale of NOx allowances.
Generation gross margin for 2012 increased $37 million, or 19%, from 2011 primarily due to:
•
an increase of $21 million at Southland, primarily due to the short-term restart of two generating units at Huntington Beach;
•
an increase of $20 million in Hawaii, primarily due to higher volumes as a result of fewer outage days and lower fixed costs; and
•
the impact of new business of $4 million from Mountain View IV and Laurel Mountain, which began operations in February of 2012 and July of 2011, respectively
For the year ended December 31, 2012, revenue increased 10% while gross margin increased 19%, primarily due to higher volumes and the short-term restart of two generating units at Huntington Beach that had a positive impact on gross margin and a decrease in fixed costs.
Fiscal Year 2011 versus 2010
Generation revenue for 2011 decreased $22 million, or 3%, from 2010 primarily due to:
•
a decrease in volume of $21 million at Deepwater in Texas due to the layup of the plant in January 2011 caused by high fuel costs and diminishing power prices.
Generation gross margin for 2011 decreased $5 million, or 2%, from 2010 primarily due to:
•
higher fuel costs and lower volume at Hawaii of $11 million;
•
higher fuel costs at Shady Point in Oklahoma of $10 million; and
•
a decrease in volume of $6 million at Deepwater as discussed above.
These decreases were partially offset by:
•
an increase of $15 million in Hawaii due to a favorable impact of prior year mark-to-market derivative adjustments; and
•
lower fixed costs at Deepwater of $10 million.
US-Utilities
The following table summarizes revenue and gross margin for our US Utilities segment for the periods indicated:
Fiscal Year 2012 versus 2011
Utilities revenue for 2012 increased $1.6 billion, or 119%, from 2011 primarily due to:
•
the impact of new business of $1.5 billion from the operations of DPL, in Ohio, which was acquired in November 2011;
•
higher prices of $68 million at IPL in Indiana, primarily due to higher fuel adjustment and other pass-through charges; and
•
higher volume of $27 million at DPL in December 2012, primarily due to increased energy available for wholesale sales caused by switching of regulated customers to other suppliers as well as new retail customers added in the Illinois service territory which are served with power purchased by DPL.
These increases were partially offset by:
•
lower prices of $24 million at DPL in December 2012, primarily due to lower capacity revenue and lower average retail prices due to downward price pressure as a result of generation services competition which we expect to continue in 2013 given the cleared auction prices for capacity; and
•
lower volume of $16 million at IPL, primarily due to warmer winter weather in 2012 and because IPL’s generating units are being priced out of market more often in 2012, reducing wholesale sales opportunities.
Utilities gross margin for 2012 increased $263 million, or 120%, from 2011 primarily due to:
•
the impact of new business of $222 million from DPL, in Ohio, in 2012 which was acquired in November 2011;
•
higher margin of $42 million in December 2012, primarily due to increases in wholesale margins due to increased volumes as described above and reductions in fixed operating costs primarily related to the acquisition of DPL by AES; and
•
lower repairs and maintenance costs at IPL of $21 million, primarily due to fewer generating unit outages.
These increases were partially offset by:
•
lower rates of $10 million primarily due to DP&L customers switching to DPL Inc.’s competitive retail supplier; and
•
higher pension expenses of $5 million at IPL, primarily due to a decrease in the estimated pension obligations at December 31, 2011.
Fiscal Year 2011 versus 2010
Utilities revenue for 2011 increased $181 million, or 16%, from 2010 primarily due to:
•
an increase of $154 million from the operations of DPL, which was acquired on November 28, 2011; and
•
higher prices of $67 million, primarily due to higher fuel adjustment charges of $57 million at IPL.
These increases were partially offset by:
•
lower retail volume of $21 million, primarily due to unfavorable weather and economic conditions at IPL; and
•
lower wholesale volume of $16 million at IPL, primarily due to increased generating unit outages.
Utilities gross margin for 2011 decreased $30 million, or 12%, from 2010 primarily due to the following at IPL:
•
lower wholesale margin of $12 million, primarily due to increased generating unit outages;
•
lower retail margin of $11 million, primarily due to unfavorable volume as discussed above; and
•
higher salaries, wages and benefits of $7 million, primarily due to increased overtime and higher pay rates in 2011.
These decreases were partially offset by:
•
increase of $6 million from the operations of DPL, which was acquired on November 28, 2011.
For the year ended December 31, 2011, revenue increased 16% while gross margin decreased 12%, primarily due to the positive impact of higher-pass through on revenue at IPL, which had no corresponding impact on gross margin and the unfavorable impact on gross margin from one-time acquisition charges of $16 million related to DPL.
Andes SBU
Andes-Generation
The following table summarizes revenue and gross margin for our Andes Generation segment for the periods indicated:
Fiscal Year 2012 versus 2011
Excluding the unfavorable impact of foreign currency translation of $66 million, generation revenue for 2012 increased $97 million, compared to 2011 primarily due to:
•
new business impact of $106 million at Angamos in Chile, which commenced operations in 2011,
•
higher spot and contract prices of $75 million at Chivor in Colombia due to pressure on prices from lower water inflows caused by El Nino; and
•
higher contract levels and lower energy prices of $25 million at Gener in Chile.
These increases were offset by:
•
The adverse impact of $57 million on prices in Argentina as a result of higher generation using natural gas and a price adjustment agreement executed in 2011; and
•
negative impact of $55 million in Argentina as a result of outages at our San Nicolas and Parana plants.
Excluding the unfavorable impact of foreign currency translation of $4 million, generation gross margin for 2012 decreased $159 million, or 21%, from 2011 primarily due to:
•
negative impact of $109 million due to lower exports from Termoandes in Argentina to Chile, higher cost of replacement energy and higher gas prices in Chile,
•
higher fixed and operating costs of $45 million across the region , primarily attributable to higher maintenance costs and employee costs offset by $11 million from a non-recurring equity tax in Chivor in 2011; and
•
lower prices in Argentina of $28 million as a result of a price adjustment agreement executed in 2011.
These decreases were partially offset by:
•
new business impact of $11 million at Angamos in Chile, which commenced operations in 2011
For the year ended December 31, 2012, revenue increased by 1% while gross margin decreased 22%, primarily due to the impact of purchasing replacement energy and higher maintenance and employee costs.
Fiscal Year 2011 versus 2010
Excluding the unfavorable impact of foreign currency translation of $37 million, generation revenue for 2011 increased $507 million, or 20%, from 2010 primarily due to:
•
higher energy prices of $210 million in Argentina attributable to a price adjustment for consuming an alternate fuel;
•
new business of $175 million at Angamos;
•
higher contract and spot prices of $150 million at Gener as a result of lower water inflows in the Central Interconnected System and PPA price indexation; and
•
higher volume of $91 million in Colombia due to higher water inflows in the system during 2011.
These increases were partially offset by:
•
lower spot prices of $128 million in Colombia due to higher water inflows in the system during 2011.
Excluding the unfavorable impact of foreign currency translation of $2 million, generation gross margin for 2011 increased $226 million, or 44%, from 2010 primarily due to:
•
higher volume of $158 million at Gener-Electrica Santiago due to improved fuel availability;
•
higher volume of $110 million in Colombia as a result of higher water inflows in the system during 2011;
•
new business of $51 million at Angamos; and
•
higher volume and price of $26 million at our coal generation businesses in Argentina as a result of low hydrology.
These increases were partially offset by:
•
lower spot prices of $92 million in Colombia due to higher water inflows in the system during 2011; and
•
higher fixed and operating costs of $31 million in Argentina, primarily attributable to higher employee costs, maintenance costs, an increase in non-income taxes.
For the year ended December 31, 2011, revenue increased by 19% while gross margin increased 43%, primarily due to lower energy purchases at Gener due to higher generation.
Brazil SBU
Brazil-Generation
The following table summarizes revenue and gross margin for our Brazil Generation segment for the periods indicated:
Fiscal Year 2012 versus 2011
Excluding the unfavorable impact of foreign currency translation of $181 million, generation revenue for 2012 increased $140 million, or 12%, from 2011 at Tietê primarily due to:
•
higher contract prices of $77 million as a result of PPA annual indexation in July each year;
•
$51 million of higher spot prices as a result of increase in demand and lower water inflows in the system; and
•
higher volume of $12 million due to higher demand in the market.
Excluding the unfavorable impact of foreign currency translation of $124 million, generation gross margin for 2012 increased $44 million, or 5%, from 2011 at Tietê primarily due to:
•
higher prices of $72 million, as discussed above;
These increases were partially offset by:
•
higher fixed and operating costs of $27 million primarily attributable to higher maintenance costs, transmission charges and employee costs.
For the year ended December 31, 2012, revenue decreased 4% while gross margin decreased 10%, primarily due to higher fixed costs partially offset by higher spot and contract prices at Tietê.
Fiscal Year 2011 versus 2010
Excluding the favorable impact of foreign currency translation of $51 million, generation revenue for 2011 increased $46 million, or 4%, from 2010 primarily due to:
•
higher contract prices of $45 million at Tietê as a result of PPA annual indexation in July each year; and
•
higher volume of $35 million due to higher demand at Tietê by the offtakers.
These increases were partially offset by:
•
a decrease of $32 million related to the final settlement of the power sales agreement between Uruguaiana and Sul in the second quarter of 2010.
Excluding the favorable impact of foreign currency translation of $36 million, generation gross margin for 2011 increased $36 million, or 5%, from 2010 primarily due to:
•
higher contract prices and volume of $72 million at Tietê, as discussed above; and
•
lower cost of energy purchases of $12 million at Tietê.
These increases were partially offset by:
•
a decrease of $32 million related to the final settlement of the power sales agreement between Uruguaiana and Sul as discussed above; and
•
higher depreciation of $16 million at Tietê due to the change in useful lives and salvage values of property, plant and equipment, as a result of new regulatory information received.
Brazil-Utilities
The following table summarizes revenue and gross margin for our Brazil Utilities segment which includes Sul which is 100% owned and Eletropaulo which has an economic ownership of 16% for the periods indicated:
Fiscal Year 2012 versus 2011
Excluding the unfavorable impact of foreign currency translation of $934 million, utilities revenue for 2012 increased $33 million compared to 2011 primarily due to:
•
higher tariffs of $130 million at Sul due to the April 2012 annual adjustment that increased the tariff by 12% to cover energy and transmission costs, regulatory charges, taxes and operations and maintenance; and
•
higher volume of $98 million due to increased market demand across the segment.
These increases were partially offset by:
•
lower tariffs of $104 million at Eletropaulo mainly driven by:
•
decrease of $446 million as a result of the July 2011 tariff reset passed by the Brazilian energy regulator in July 2012;
•
decrease of $111 million starting in July 2012 compared to the tariff charged in 2011; partially offset by
•
increase of $453 million due to the annual adjustment to cover energy and transmission pass through costs.
•
reduction in other revenue related to reactive energy and excess energy demand revenue by $60 million, that are now recorded as special obligations as a result of a change in the regulation; and
•
lower transmission revenue and other adjustments of $35 million at Eletropaulo.
Excluding the unfavorable impact of foreign currency translation of $22 million, utilities gross margin for 2012 decreased $732 million, or 74%, from 2011 primarily due to:
•
lower tariffs of $550 million at Eletropaulo mainly driven by:
•
decrease of $439 million as a result of the July 2011 tariff reset passed by the Brazilian energy regulator in July 2012; and
•
decrease of $111 million starting in July 2012 compared to the tariff charged in 2011
•
reduction in other revenue related to reactive energy and excess energy demand revenue by $60 million, that are now recorded as special obligations as a result of a change in the regulation; and
•
lower transmission revenue and other adjustments of $30 million at Eletropaulo.
•
higher fixed costs of $218 million at Eletropaulo mainly driven by:
•
higher employee costs resulting from a collective wage agreement and higher pension expense of $100 million;
•
higher contingencies (mainly labor) of $41 million;
•
higher bad debt expense of $33 million;
•
VAT over commercial losses reversal recorded in 2011 of $22 million; and
•
An increase in maintenance and other expense of $22 million.
These decreases were partially offset by:
•
higher volume of $86 million due to increased market demand partially offset by higher spot market purchases at Sul; and
•
higher tariffs of $33 million at Sul due to the annual adjustment described above.
For the year ended December 31, 2012, revenue decreased 14% while gross margin decreased 76%, primarily due to higher fixed costs at Eletropaulo and pass-through revenue at Eletropaulo and Sul which helped offset the revenue decline but had no corresponding impact on gross margin.
Fiscal Year 2011 versus 2010
Excluding the favorable impact of foreign currency translation of $362 million, utilities revenue for 2011 decreased $81 million, or 1% from 2010 primarily due to:
•
lower tariffs of $207 million at Eletropaulo, related to the estimated impact of the July 2011 tariff reset which was finalized by the Brazilian energy regulatory agency in 2012;
•
lower tariffs of $139 million at Eletropaulo due to lower energy prices associated with energy purchases and pass-through transmission costs; and
These decreases were partially offset by:
•
higher volume of $266 million due to increased market demand; and
•
higher tariffs of $27 million at Sul due to higher volume of energy purchases which are passed through to customers.
Excluding the favorable impact of foreign currency translation of $63 million, utilities gross margin for 2011 decreased $43 million, or 4%, from 2010 primarily due to:
•
lower tariffs of $207 million, primarily related to the estimated impact of the July 2011 tariff reset at Eletropaulo as discussed above;
•
higher depreciation of $49 million mainly due to the change in estimates of the useful lives and salvage values of property, plant and equipment, as a result of new regulatory information.
These decreases were partially offset by:
•
higher volume of $117 million due to increased market demand;
•
lower fixed costs of $71 million primarily due to contingency reversals and a non-recurring reduction in bad debt expense; and
•
a decrease of $32 million related to the final settlement of the power sales agreement between Sul and Uruguaiana in the second quarter of 2010.
MCAC SBU
MCAC-Generation
The following table summarizes revenue and gross margin for our MCAC Generation segment for the periods indicated:
Fiscal Year 2012 versus 2011
Excluding the unfavorable impact of foreign currency translation of $17 million, generation revenue for 2012 increased $165 million, or 10%, from 2011 primarily due to:
•
the positive impact of $126 million at Andres-Los Mina in the Dominican Republic mainly from higher international gas prices and volume of gas sales to third parties and ancillary services;
•
new business of $50 million at Changuinola in Panama, which commenced operations in 2011;
•
increase of $40 million at Panama mainly due to the Esti plant being back on-line from June 2012 as well as higher volume of PPA sales;
•
an increase of $23 million at Merida in Mexico, primarily due to higher volume; and
•
an increase at TEG/TEP in Mexico, of $18 million, primarily due to higher availability bonuses and higher rates.
These increases were partially offset by:
•
decrease of $42 million at Andres-Los Mina due to lower volume and lower PPA prices mainly driven by price indexation due to a decrease in NYMEX gas prices;
•
lower pass-through rates of $31 million at Merida due to lower fuel costs;
•
a decrease of $15 million in Puerto Rico, primarily due to lower availability resulting from higher forced outages; and
•
a decrease of $15 million at Changuinola mainly due to lower rates and PPA prices.
Excluding the unfavorable impact of foreign currency translation of $2 million, generation gross margin for 2012 increased $42 million, or 9%, from 2011 primarily due to:
•
new business of $101 million at Changuinola as described above;
•
the positive impact of $41 million at Andres-Los Mina of higher gas sales and ancillary services as discussed above;
•
higher contract prices of $25 million at Itabo in the Dominican Republic, primarily related to lower fuel costs; and
•
the positive impact of $17 million due to the Esti plant as described above.
These increases were partially offset by:
•
a decrease in Panama of $72 million primarily related to higher energy purchases;
•
lower volume and PPA prices of $44 million at Andres-Los Mina as described above;
•
a decrease of $17 million in Puerto Rico primarily due to lower availability and higher fixed costs as a result of higher forced outages; and
•
a decrease of $9 million at Merida due to higher outages and lower rates as described above.
Fiscal Year 2011 versus 2010
Excluding the favorable impact of foreign currency translation of $9 million, generation revenue for 2011 increased $166 million, or 12%, from 2010 primarily due to:
•
higher ancillary services and third party gas sales of $57 million and $21 million higher volume at Andres-Los Mina;
•
higher contract prices of $53 million at Itabo primarily from PPAs indexed to coal;
•
an increase in Puerto Rico of $23 million primarily due to a prior year forced outage and the related penalty and $20 million due to higher rates;
•
higher volume of $22 million in Panama due to higher water inflows in the system during 2011; and
•
higher volume of $8 million at TEG/TEP.
These increases were partially offset by the following:
•
a net decrease of $19 million related to the forced outage in Panama; and
•
decreases at Merida of $18 million due to lower rates and volume and $7 million due to a combination of forced and scheduled outages.
Generation gross margin for 2011 increased $58 million, or 14%, from 2010 primarily due to:
•
higher ancillary services and gas sales of $36 million and higher energy prices of $27 million at Andres-Los Mina;
•
higher volume of $40 million in Panama as a result of higher water inflows in the system during 2011; and
•
an increase in Puerto Rico of $9 million primarily due to a prior year forced outage and the related penalty.
These increases were partially offset by:
•
a decrease of $39 million related to higher spot purchases and the forced outage in Panama; and
•
a decrease of $17 million at TEG/TEP and Merida due to a combination of forced and scheduled outages and higher fuel costs.
EMEA SBU
EMEA-Generation
The following table summarizes revenue and gross margin for our EMEA generation segment for the periods indicated:
Fiscal Year 2012 versus 2011
Excluding the unfavorable impact of foreign currency translation of $41 million, generation revenue for 2012 decreased $84 million, or 6%, from 2011 primarily due to:
•
a decrease of $233 million as a result of the sale of 80% of our ownership of Cartagena, in Spain, in February 2012;
•
a decrease of $136 million at Ballylumford in Northern Ireland, due to higher forced and planned outages, lower pass through costs included in revenue as a result of lower dispatch and lower capacity prices in the PPA; and
•
a decrease of $25 million as a result of the sale of Bohemia, in the Czech Republic, in September 2011.
These decreases were partially offset by:
•
new business contribution of $174 million from Maritza, in Bulgaria, which commenced commercial operations in June 2011;
•
a non-recurring favorable arbitration settlement at Cartagena of $95 million; and
•
an increase of $47 million at Kilroot, in Northern Ireland, primarily due to increased dispatch of the plant.
Excluding the unfavorable impact of foreign currency translation of $22 million, generation gross margin for 2012 increased $134 million, or 31%, from 2011 primarily due to:
•
the new business impact of $117 million at Maritza, as discussed above;
•
a non-recurring favorable arbitration settlement at Cartagena of $95 million; and
•
an increase of $35 million at Kilroot, as discussed above.
These increases were partially offset by:
•
a decrease of $68 million from Cartagena as a result of the sale of 80% of our ownership in February 2012;
•
a decrease of $48 million at Ballylumford, as discussed above and also due to higher fixed costs and depreciation;
•
a decrease of $8 million in Kazakhstan primarily due to higher fixed costs; and
•
a decrease of $6 million as a result of the sale of Bohemia, in the Czech Republic, in September 2011.
For the year ended December 31, 2012, revenue decreased 8% primarily due to the sale of 80% of our ownership in Cartagena while gross margin increased 26% primarily due to favorable arbitration settlement at Cartagena.
Fiscal Year 2011 versus 2010
Excluding the favorable impact of foreign currency translation of $41 million, generation revenue for 2011 increased $252 million, or 21%, from 2010 primarily due to:
•
the favorable impact of $256 million from the operations at Ballylumford, acquired in August 2010, driven by $224 million resulting from the acquisition and $32 million primarily from better availability due to a planned outage in 2010; and
•
new business of $182 million at Maritza, which commenced commercial operations in June 2011.
These increases were partially offset by:
•
a decrease of $160 million at Cartagena primarily due to lower pass-through energy costs;
•
a decrease of $46 million at Kilroot, in Northern Ireland, primarily resulting from the cancellation of the long-term PPA and supplementary agreements in November 2010.
Excluding the favorable impact of foreign currency translation of $11 million, generation gross margin for 2011 increased $90 million, or 28%, from 2010 primarily due to:
•
the favorable impact of $77 million from the operations at Ballylumford, acquired in August 2010, driven by $64 million resulting from the acquisition and $13 million primarily from better availability due to a planned outage in 2010; and
•
the new business impact of $66 million at Maritza, which commenced operations in June 2011.
These increases were partially offset by:
•
a decrease of $68 million at Kilroot, primarily resulting from cancellation of the long-term PPA and supplementary agreements in November 2010, lower capacity factor due to a decline in market demand, partially offset by CO2 costs passed through in the market price in 2011.
Asia SBU
Asia-Generation
The following table summarizes revenue and gross margin for our Asia Generation segment for the periods indicated:
Fiscal Year 2012 versus 2011
Excluding the unfavorable impact of foreign currency translation of $9 million, generation revenue for 2012 increased $121 million, or 19%, from 2011 primarily due to:
•
an increase at Masinloc in the Philippines of $64 million primarily driven by:
•
the $36 million favorable impact of higher market demand, partially offset by lower rates;
•
the reversal of a contingency of $16 million; and
•
the $13 million favorable impact of a mark-to-market adjustment on an inflation-related embedded derivative.
•
an increase of $51 million at Kelanitissa in Sri Lanka primarily attributable to higher offtaker demand as a result of lower hydrology, and higher fuel pass-through revenue, as well as better plant reliability.
Excluding the favorable impact of foreign currency translation of $6 million, primarily in the Philippines, generation gross margin for 2012 increased $66 million, or 37%, from 2011 primarily due to the following:
•
an increase at Masinloc in the Philippines of $66 million primarily driven by:
•
the $35 million favorable impact of higher market demand, partially offset by lower rates;
•
the reversal of a contingency of $16 million; and
•
the $13 million favorable impact of a mark-to-market adjustment on an inflation-related embedded derivative.
These increases were partially offset by:
•
higher fixed costs of $7 million related to commitment fees on undrawn construction loans at Mong Duong II in Vietnam.
For the year ended December 31, 2012, revenue increased 18% while gross margin increased 40%. This was primarily due to the impact of higher spot market margins at Masinloc and a gain on a mark-to-market inflation-related embedded derivative and reversal of a contingency. We expect gross margin in 2013 to be reduced due to a step down in the PPA at Masinloc
Fiscal Year 2011 versus 2010
Excluding the favorable impact of foreign currency translation of $20 million, generation revenue for 2011 decreased $12 million, or 2%, from 2010 primarily due to:
•
a decrease of $39 million at Masinloc primarily due to lower generation prices and volume. Spot volume and prices were lower due to flat electricity demand and higher available capacity in the grid;
•
a decrease of $12 million due to the closure of Aixi in China in November 2010; and
•
outages of $9 million at Kelanitissa resulting in lower plant availability in 2011.
These decreases were partially offset by:
•
higher generation rates of $18 million due to higher pass-through fuel costs and higher generation volume of $29 million at Kelanitissa due to higher offtaker demand as a result of lower hydrology.
Excluding the favorable impact of foreign currency translation of $8 million, generation gross margin for 2011 decreased $71 million, or 29%, from 2010 primarily due to:
•
decrease of $59 million at Masinloc primarily attributable to a combination of flat market demand, lower spot prices, higher coal prices and increased fixed costs.
For the year ended December 31, 2011, revenue increased 1% while gross margin decreased 26%, primarily due to higher pass-through fuel costs at Kelanitissa which had a positive impact on revenue but no corresponding impact on gross margin and the negative influence on gross margin arising from lower spot prices at Masinloc, as well as increases in coal prices and fixed costs.
Corporate and Other
Corporate and other includes the net operating results from our utility businesses in El Salvador, Africa and Europe, which are immaterial for the purposes of separate segment disclosure. The following table excludes inter-segment activity and summarizes revenue and gross margin for Corporate and Other entities for the periods indicated:
Fiscal Year 2012 versus 2011
Excluding the unfavorable impact of foreign currency translation of $42 million, Corporate and Other revenue increased $286 million for 2012, or 18% from 2011 primarily due to:
•
higher pass-through tariffs of $76 million in El Salvador primarily due to increased energy prices driven by higher fuel prices;
•
higher volume and rates at our utility businesses in the Ukraine of $79 million; and
•
the unfavorable impact of a mark-to-market derivative adjustment in 2011 at Sonel in Cameroon of $75 million.
Excluding the unfavorable impact of foreign currency translation of $3 million, Corporate and Other gross margin increased $114 million for 2012 from 2011. The increase was primarily due to:
•
an increase of $107 million at Sonel primarily due to the unfavorable impact of a mark-to-market derivative adjustment in 2011 of $75 million as discussed above.
Fiscal Year 2011 versus 2010
Excluding the favorable impact of foreign currency translation of $14 million, primarily in Cameroon, Corporate and Other revenue increased $116 million from 2010 or 8%, from 2010. The increase was primarily due to:
•
higher pass-through tariffs of $94 million in El Salvador primarily due to increased energy prices driven by higher fuel prices and drier weather; and
•
higher rates at our utility businesses in the Ukraine of $71 million.
These increases were partially offset by:
•
a net decrease of $52 million at Sonel in Cameroon primarily due to the unfavorable impact of an unrealized mark-to-market derivative adjustment, partially offset by higher tariff and volume.
Excluding the unfavorable impact of foreign currency translation of $4 million, primarily in Cameroon, Corporate and Other gross margin decreased $133 million for 2011, or 92%, from 2010. The decrease was primarily due to:
•
a decrease of $119 million at Sonel primarily due to the unfavorable impact of an unrealized mark-to-market derivative adjustment and higher fixed costs; and
•
a decrease of $16 million in the Ukraine primarily due to higher fixed costs.
General and administrative expenses
General and administrative expenses includes expenses related to corporate and region staff functions and/or initiatives, executive management, finance, legal, human resources, information systems, and development costs.
General and administrative expenses decreased $90 million, or 23%, to $301 million in 2012 from 2011. The decrease was primarily due to reduction in business development and systems administration costs.
General and administrative expenses remained flat at $391 million in 2011 and 2010. A reduction of business development costs and SAP implementation costs was offset by DPL transaction costs.
Interest expense
Interest expense increased $19 million, or 1%, to $1.6 billion in 2012 from 2011. This increase was primarily due to debt at DPL, acquired in November 2011, additional indebtedness at the Parent Company to finance the acquisition of DPL, and less interest capitalization due to the commencement of operations at various projects. The increase was partially offset by a reduction in interest expense in Brazil, due to lower short-term interest rates, lower debt principal and favorable foreign currency translation, as well as lower interest expense for Cartagena, which was deconsolidated following the sale of 80% of our interest in the first quarter of 2012 and higher capitalized interest at Gener in 2012.
Interest expense increased $104 million, or 7%, to $1.6 billion in 2011 from 2010. This increase was primarily due to less interest capitalization at Maritza due to commencement of operations in June 2011, interest on value-added tax for commercial losses at Eletropaulo, the unfavorable impact of foreign currency translation in Brazil, higher interest rates at Eletropaulo, and increased debt and fees related to the DPL acquisition. These increases were partially offset by lower interest rates at Tietê, and a fee on a non-exercised credit line that was written off in Brazil in 2010.
Interest income
Interest income decreased $50 million, or 13%, to $349 million in 2012 from 2011. The decrease was mainly in Brazil, due to a reduction in interest-bearing assets, unfavorable foreign currency translation and lower interest rates, partially offset by inflation adjustments on interest-bearing assets and interest earned on receivables for spot sales in the Dominican Republic.
Interest income decreased $8 million, or 2%, to $399 million in 2011 from 2010. This decrease was primarily due to the settlement of a dispute related to inflation adjustments for energy sales at Tietê in 2010. The decrease was partially offset by favorable foreign currency translation in Brazil.
Other income and expense
See discussion of the components of other income and expense in Note 20-Other Income and Expense included in Item 8.
Item 8. - Financial Statements and Supplementary Data of this Form 10-K.
Fair Value of Nonfinancial Assets and Liabilities
Significant estimates are made in determining the fair value of long-lived tangible and intangible assets (i.e., property, plant and equipment, intangible assets and goodwill) during the impairment evaluation process. In addition, the majority of assets acquired and liabilities assumed in a business combination are required to be recognized at fair value under the relevant accounting guidance. In determining the fair value of these items, management makes several assumptions discussed in the Impairments section.
Accounting for Derivative Instruments and Hedging Activities
We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage our interest rate, commodity and foreign currency exposures. We do not enter into derivative transactions for trading purposes.
In accordance with the accounting standards for derivatives and hedging, we recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value except where derivatives qualify and are designated as “normal purchase/normal sale” transactions. Changes in fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Income and expense related to derivative instruments are recognized in the same category as that generated by the underlying asset or liability. See Note 6-Derivative Instruments and Hedging Activities included in Item 8 of this Form 10-K for further information on the classification.
The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is highly effective and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging.
The fair value measurement accounting standard provides additional guidance on the definition of fair value and defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The fair value measurement standard requires the Company to consider and reflect the assumptions of market participants in the fair value calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). Due to the nature of the Company’s interest rate swaps, which are typically associated with non-recourse debt, credit risk for AES is evaluated at the subsidiary level rather than at the Parent Company level. Nonperformance risk on the Company’s derivative instruments is an adjustment to the initial asset/liability fair value position that is derived from internally developed valuation models that utilize observable market inputs.
As a result of uncertainty, complexity and judgment, accounting estimates related to derivative accounting could result in material changes to our financial statements under different conditions or utilizing different assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance, volatilities, market liquidity, future commodity prices, interest rates, credit ratings (both ours and our counterparty’s) and exchange rates.
The fair value of our derivative portfolio is generally determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities. The Company derives most of its financial instrument market assumptions from market efficient data sources (e.g., Bloomberg, Reuters and Platt’s). In some cases, where market data is not
readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine a financial instrument’s fair value. In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve. Additionally, in the absence of quoted prices, we may rely on “indicative pricing” quotes from financial institutions to input into our valuation model for certain of our foreign currency swaps. These indicative pricing quotes do not constitute either a bid or ask price and therefore are not considered observable market data. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.
Regulatory Assets and Liabilities
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, any asset write-offs would be required to be recognized in operating income.
New Accounting Pronouncements Adopted
The Company adopted the new accounting standard on comprehensive income, which became effective January 1, 2012. In addition, the Company early adopted the new accounting standard on the impairment testing of intangible assets. The adoption of these new accounting pronouncements did not have a material impact on the Company’s financial position or results of operations. See Note 1-General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K for further information.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks
Our generation and utilities business lines are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.
These disclosures set forth in this Item 7A are based upon a number of assumptions; actual impacts to the Company may not follow the assumptions made by the Company. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 7A. For further information regarding market risk, see Item 1A.-Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of this Form 10-K.
Commodity Price Risk
Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an un-hedged exposure on some of capacity, or through imperfect pass throughs. At our generation businesses, for 2013-2015 75% to 80% of our variable margin is hedged against changes in commodity prices. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations, and sharing or pass through mechanisms. At our utility businesses, for 2013-2015 85% to 90% of our variable margin is insulated from changes in commodity prices. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options.
When hedging the output of our generation assets, we have contract sales that lock in the spread per MWh between variable costs, such as fuel, to generate a unit of electricity and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements will be exposed to commodity price risk or to the extent indexation is not perfectly matched to the business drivers.
AES businesses will see changes in variable margin performance as global commodity prices shift. For 2013, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $25 million for coal, $15 million for oil and $20 million for natural gas. Our estimates exclude correlation. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some our businesses.
Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Generation costs can be directly affected by movements in the price of natural gas, oil and coal. Spot power prices and contract indexation provisions are affected by the same commodity price movements. We have some natural offsets across our businesses such that low commodity prices may benefit
certain businesses and be a cost to others. Offsets are not perfectly linear or symmetric. The sensitivities are affected by a number of non-market, or indirect market factors. Examples of these factors include hydrology, energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may reduce dispatch in low market environments limiting downside exposure. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.
In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers; DPL sells generation in excess of its retail demand under short-term sales; and the outcome of the DPL regulatory filing may affect our level of commodity price exposure over time. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during peak periods.
For the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. While we have been adding coal-fired generation to our portfolio in Chile, a small amount of efficient generation is sold into the spot market. Other assets in Chile include natural gas/diesel, hydroelectric and biomass generation facilities. Generators with oil or oil-linked fuel generally set power prices in these markets impacting spot power margins. In our other Andes SBU markets, Colombia and Argentina, we operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets in Colombia, contracts are not indexed to fuel. In Argentina some prices are set according to government rules that result in commodity exposure based on several factors, one of which is the spread between the cost of coal-fired and oil-fired generation.
The businesses in the MCAC SBU have commodity exposure on un-hedged volumes. Panama is largely contracted under a portfolio of contract sales, and the un-hedged portion of our hydroelectric assets in Panama is sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices.
In the EMEA SBU, our Kilroot facility operates on a short-term sales strategy. The commodity risk at our Kilroot business is due to the dark spread, the difference between electricity price and our coal based variable dispatch cost, to the extent sales are un-hedged. Natural gas-fired generators set power prices for many periods, so higher natural gas prices expand margins and higher coal prices cause a decline. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. At our Ballylumford facility, NIAUR, the regulator, has the right to terminate the contract, which would impact our commodity exposure. Our operations in Turkey are sensitive to the spread between power and natural gas prices, both of which have historically demonstrated a relationship to oil. As a result of these relationships, falling oil prices could compress margins realized at the business.
In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume sold in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices.
Foreign Exchange Rate Risk
In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. Primarily, we are exposed to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Cameroonian Franc, Chilean Peso, Colombian Peso, Dominican Peso, Euro, Indian Rupee, Kazakhstani Tenge, Philippine Peso, and Ukrainian Hryvnia. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.
We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. As of December 31, 2012, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Brazilian Real, Colombian Peso, Philippine Peso and Euro (the earnings attributable to the subsidiaries exposed to the Cameroonian Franc movements are included under Euro due to the fixed exchange rate of the Cameroonian Franc to the Euro) relative to the U.S. Dollar are projected to be reduced by approximately $25 million, $10 million, $5 million, and $15 million, respectively, for 2013. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for 2013 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.
Interest Rate Risks
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap and floor and option agreements.
Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of December 31, 2012, the portfolio’s pretax earnings exposure for 2013 to a 100 basis point increase in interest rates for our Argentine Peso, Brazilian Real, Columbian Peso, British Pound, Euro, Indian Rupee, Philippine Peso, Kazakhstani Tenge, and U.S. Dollar denominated debt would be approximately $25 million based on the impact of a one-time, 100 basis point upward shift in interest rates on interest expense for the debt denominated in these currencies. The amounts do not take into account the historical correlation between these interest rates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of The AES Corporation:
We have audited the accompanying consolidated balance sheets of The AES Corporation as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedules listed in the index at Item 15(a). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The AES Corporation at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The AES Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
McLean, Virginia
February 26, 2013
THE AES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2012 AND 2011
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2012, 2011, AND 2010
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The AES Corporation is a holding company (the “Parent Company”) that through its subsidiaries and affiliates, (collectively, “AES” or “the Company”) operates a geographically diversified portfolio of electricity generation and distribution businesses. Generally, given this holding company structure, the liabilities of the individual operating entities are not recourse to the parent and are isolated to the operating entities. Most of our operating entities are structured as limited liability entities, which limit the liability of shareholders. The structure is generally the same regardless of whether a subsidiary is consolidated under a voting or variable interest model.
PRINCIPLES OF CONSOLIDATION-The Consolidated Financial Statements of the Company include the accounts of The AES Corporation, its subsidiaries and controlled affiliates. Furthermore, variable interest entities (“VIEs”) in which the Company has a variable interest have been consolidated where the Company is the primary beneficiary. Investments in which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting. Intercompany transactions and balances are eliminated in consolidation.
A VIE is an entity (a) that has a total equity investment at risk that is not sufficient to finance its activities without additional subordinated financial support or (b) where the group of equity holders does not have (i) the ability to make significant decisions about the entity’s activities, (ii) the obligation to absorb the entity’s expected losses or (iii) the right to receive the entity’s expected residual returns or (c) where the voting rights of some equity holders are not proportional to their obligations to absorb expected losses, receive expected residual returns, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights.
The determination of which party has the power to direct the activities that most significantly impact the economic performance of the VIE could require significant judgment and assumptions. That determination considers the purpose and design of the business, the risks that the business was designed to create and pass along to other entities, the activities of the business that can be directed and which party can direct them, and the expected relative impact of those activities on the economic performance of the business through its life. The businesses for which significant judgment and assumptions were required were primarily certain generation businesses who have power purchase agreements (“PPAs”) to sell energy exclusively or primarily to a single counterparty for the term of those agreements. For these generation businesses, the counterparty has the power to dispatch energy and, in some instances, to make decisions regarding the sale of excess energy. As such, the counterparty has the power to direct certain activities that significantly impact the economic performance of the business primarily through the cash flows and gross margin, if any, earned by the business from the sale of energy to the counterparty and sometimes through the counterparty’s absorption of fuel price risk. However, the counterparty usually does not have the power to direct any of the other activities that could significantly impact the economic performance. These other activities include: daily operation and management, maintenance, repairs and capital expenditures, plant expansion, decisions regarding the overall financing of ongoing operations and budgets and, in some instances, decisions regarding the sale of excess energy. As such, AES has the power to direct some activities of the business that significantly impact its economic performance, primarily through the cash flows and gross margin earned from capacity payments received from being available to produce energy and from the sale of energy to other entities (particularly during any period beyond the end of the power purchase agreement). For these businesses, the determination as to which set of activities most significantly impact the economic performance of the business requires significant judgment and the use of assumptions. The Company concluded that the activities directed by the counterparty were less significant than those directed by AES.
DP&L, our utility in Ohio, has undivided interests in seven generation facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in our
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
consolidated financial statements. Certain expenses, primarily fuel costs for the generating units, are allocated to the joint owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies and capital additions are allocated to the joint owners in accordance with their respective ownership interests.
USE OF ESTIMATES-The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Items subject to such estimates and assumptions include: the carrying amount and estimated useful lives of long-lived assets; impairment of goodwill, long-lived assets and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of deferred regulatory assets; the estimation of deferred regulatory liabilities; the fair value of financial instruments; the fair value of assets and liabilities acquired in a business combination accounted for under the purchase method; the determination of noncontrolling interest using the hypothetical liquidation at book value (“HLBV”) method for certain wind generation partnerships; pension liabilities; environmental liabilities; and potential litigation claims and settlements.
DISCONTINUED OPERATIONS AND RECLASSIFICATIONS-A discontinued operation is a component of the Company that either has been disposed of or is classified as held for sale. A component of the Company comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the Company. Prior period amounts have been retrospectively revised to reflect the businesses determined to be discontinued operations, as further discussed in Note 23-Discontinued Operations and Held for Sale Businesses. Cash flows at discontinued and held for sale businesses are included within the relevant categories within operating, investing and financing activities. As cash at such businesses is reported within Current assets of discontinued and held for sale businesses, the aggregate amount of cash flows is offset by the net increase or decrease in cash of discontinued and held for sale businesses, which is presented as a separate line item in the Consolidated Statements of Cash Flows.
COMPREHENSIVE INCOME-In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income” (“ASU No. 2011-05”) which requires comprehensive income to be reported in either a single statement or in two consecutive statements reporting net income and other comprehensive income. The amendment does not change what items are reported in other comprehensive income or the U.S. GAAP requirement to report the reclassification of items from other comprehensive income to net income. The Company adopted ASU No. 2011-05 on January 1, 2012 and chose to report comprehensive income in two consecutive statements by adding a new consolidated statement of comprehensive income. To be consistent with this new presentation, the Company has presented consolidated statements of comprehensive income for each year in the three-year period ended December 31, 2012 in these consolidated financial statements. As ASU No. 2011-05 impacts financial statement presentation only, the adoption did not have an impact on the Company’s historical financial position or results of operations and is not expected to have an impact in future periods.
FAIR VALUE-Fair value, as defined in the fair value measurement accounting guidance, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The Company applies the fair value measurement accounting guidance to financial assets and liabilities in determining the fair value of investments in marketable debt and equity securities, included in the consolidated balance sheet line items “Short-term investments” and “Other assets (noncurrent),” derivative assets, included in “Other current assets” and “Other assets (noncurrent)” and
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
derivative liabilities, included in “Accrued and other liabilities (current)” and “Other long-term liabilities.” The Company applies the fair value measurement guidance to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill.
The fair value measurement accounting guidance requires that the Company make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments’ fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity.
Fair value, where available, is based on observable quoted market prices. Where observable prices or inputs are not available, several valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments’ complexity.
To increase consistency and enhance disclosure of fair value, the fair value measurement accounting guidance creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:
Level 1-unadjusted quoted prices in active markets accessible by the reporting entity for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2-pricing inputs other than quoted market prices included in Level 1 which are based on observable market data, that are directly or indirectly observable for substantially the full term of the asset or liability. These include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities or default rates observable at commonly quoted intervals or inputs derived from observable market data by correlation or other means. The fair value of most over-the-counter derivatives derived from internal valuation models using market inputs and most investments in marketable debt securities qualify as Level 2.
Level 3-pricing inputs that are unobservable, or less observable, from objective sources. Unobservable inputs are only used to the extent observable inputs are not available. These inputs maintain the concept of an exit price from the perspective of a market participant and should reflect assumptions of other market participants. An entity should consider all market participant assumptions that are available without unreasonable cost and effort. These are given the lowest priority and are generally used in internally developed methodologies to generate management’s best estimate of the fair value when no observable market data is available. The fair value of implied goodwill and long-lived assets determined using discounted cash flows valuation models for impairment evaluation purposes qualify as Level 3.
Any transfers between all levels within the fair value hierarchy levels are recognized at the end of the reporting period.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
CASH AND CASH EQUIVALENTS-The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit and short-term marketable securities, that mature within three months or less from the date of purchase, to be cash and cash equivalents. The carrying amounts of such balances approximate fair value.
RESTRICTED CASH AND DEBT SERVICE RESERVES-These include cash balances which are restricted as to withdrawal or usage. The nature of restrictions includes restrictions imposed by financing agreements such as security deposits kept as collateral, debt service reserves, maintenance reserves and others, as well as restrictions imposed by long-term PPAs.
INVESTMENTS IN MARKETABLE SECURITIES-Short-term investments in marketable debt and equity securities consist of securities with original or remaining maturities in excess of three months but less than one year. The Company’s marketable investments are primarily unsecured debentures, certificates of deposit, government debt securities and money market funds.
Marketable debt securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at amortized cost. Other marketable securities that the Company does not intend to hold to maturity are classified as available-for-sale or trading and are carried at fair value. Available-for-sale investments are marked-to-market at the end of each reporting period, with unrealized holding gains or losses, which represent changes in the market value of the investment, reflected in accumulated other comprehensive loss (“AOCL”), a separate component of equity. In measuring the other-than-temporary impairment of debt securities, the Company identifies two components: 1) the amount representing the credit loss, which is recognized as “other non-operating expense” in the Consolidated Statements of Operations; and 2) the amount related to other factors, which is recognized in AOCL unless there is a plan to sell the security, in which case it would be recognized in earnings. The amount recognized in AOCL for held-to-maturity debt securities is then amortized in earnings over the remaining life of such securities.
Investments classified as trading are marked-to-market on a periodic basis through the Consolidated Statements of Operations. Interest and dividends on investments are reported in interest income and other income, respectively. Gains and losses on sales of investments are determined using the specific identification method.
See Note 4-Fair Value and the Company’s fair value policy for additional discussion regarding the determination of the fair value of the Company’s investments in marketable debt and equity securities.
ACCOUNTS AND NOTES RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS-Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other currently available evidence of the collectability, and records an allowance for doubtful accounts for the estimated uncollectible amount as appropriate. Certain of our businesses charge interest on accounts receivable either under contractual terms or where charging interest is a customary business practice. In such cases, interest income is recognized on an accrual basis. In situations where the collection of interest is uncertain, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectible.
INVENTORY-Inventory primarily consists of coal, fuel oil and other raw materials used to generate power, and spare parts and supplies used to maintain power generation and distribution facilities. Inventory is
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
carried at lower of cost or market. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. Cost is determined under the first-in, first-out (“FIFO”), average cost or specific identification method. Generally, cost is reduced to market value if the market value of inventory has declined and it is probable that the utility of inventory, in its disposal in the ordinary course of business, will not be recovered through revenue earned from the generation of power.
LONG-LIVED ASSETS-Long-lived assets include property, plant and equipment, assets under capital leases and intangible assets subject to amortization (i.e., finite-lived intangible assets).
Property, plant and equipment
Property, plant and equipment are stated at cost, net of accumulated depreciation. The cost of renewals and improvements that extend the useful life of property, plant and equipment are capitalized.
Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction in progress are capitalized during the construction period, provided the completion of the project is deemed probable, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. Construction in progress balances are transferred to electric generation and distribution assets when an asset group is ready for its intended use. Government subsidies, liquidated damages recovered for construction delays and income tax credits are recorded as a reduction to property, plant and equipment and reflected in cash flows from investing activities.
Depreciation, after consideration of salvage value and asset retirement obligations, is computed primarily using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. Maintenance and repairs are charged to expense as incurred. Capital spare parts, including rotable spare parts, are included in electric generation and distribution assets. If the spare part is considered a component, it is depreciated over its useful life after the part is placed in service. If the spare part is deemed part of a composite asset, the part is depreciated over the composite useful life even when being held as a spare part.
The Company’s Brazilian subsidiaries, which include both generation and distribution companies, operate under concession contracts. Certain estimates are utilized to determine depreciation expense for the Brazilian subsidiaries, including the useful lives of the property, plant and equipment and the amounts to be recovered at the end of the concession contract. The amounts to be recovered under these concession contracts are based on estimates that are inherently uncertain and actual amounts recovered may differ from those estimates.
Intangible Assets Subject to Amortization
Finite-lived intangible assets are amortized over their useful lives which range from 1 - 50 years. The Company accounts for purchased emission allowances as intangible assets and records an expense when utilized or sold. Granted emission allowances are valued at zero.
Impairment of Long-lived Assets
The Company evaluates the impairment of long-lived assets (asset group) using internal projections of undiscounted cash flows when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under the relevant accounting standards. Events or changes in circumstances that may necessitate a recoverability evaluation may include but are not limited to: adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, or an expectation that it is more likely than not that the asset will be disposed of before the end of its previously estimated useful life. The carrying amount of a long-lived asset (asset group) may not be recoverable if it exceeds
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
the sum of undiscounted cash flows expected to result from the use and eventual disposal of the asset (asset group). In such cases, fair value of the long-lived asset (asset group) is determined in accordance with the fair value measurement accounting guidance. The excess of carrying amount over fair value, if any, is recognized as an impairment expense. For regulated assets, an impairment expense could be reduced by the establishment of a regulatory asset, if recovery through approved rates was probable. For non-regulated assets, impairment is recognized as an expense against net income.
DEFERRED FINANCING COSTS-Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method or the straight-line method when it does not differ materially from the effective interest method. Make-whole payments in connection with early debt retirements are classified as cash flows used in financing activities.
EQUITY METHOD INVESTMENTS-Investments in entities over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and reported in “Investments in and advances to affiliates” on the Consolidated Balance Sheets. The Company periodically assesses the recoverability of its equity method investments. If an identified event or change in circumstances requires an impairment evaluation, management assesses the fair value based on valuation methodologies, including discounted cash flows, estimates of sale proceeds and external appraisals, as appropriate. The difference between the carrying amount of the equity method investment and its estimated fair value is recognized as impairment when the loss in value is deemed other-than-temporary and included in “Other non-operating expense” in the Consolidated Statements of Operations.
The Company discontinues the application of the equity method when an investment is reduced to zero and the Company is not otherwise committed to provide further financial support to the investee. The Company resumes the application of the equity method if the investee subsequently reports net income to the extent that the Company’s share of such net income equals the share of net losses not recognized during the period in which the equity method of accounting was suspended.
GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS-The Company evaluates goodwill and indefinite-lived intangible assets for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. The Company’s annual impairment testing date is October 1.
Goodwill:
The Company evaluates goodwill impairment at the reporting unit level, which is an operating segment, as defined in the segment reporting accounting guidance, or a component (i.e., one level below an operating segment). In determining its reporting units, the Company starts with its management reporting structure. Operating segments are identified and then analyzed to identify components which make up these operating segments. Two or more components are combined into a single reporting unit if they share the economic similarity criteria prescribed by the accounting guidance. Assets and liabilities are allocated to a reporting unit if the assets will be employed by or a liability relates to the operations of the reporting unit or would be considered by a market participant in determining its fair value. Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit from the synergies of the acquisition. Generally, each AES business constitutes a reporting unit.
Goodwill is evaluated for impairment either under the qualitative assessment option or the two-step test approach depending on facts and circumstances of a reporting unit. Examples of such facts and circumstances
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
include: the excess of fair value over carrying amount in the last valuation, or changes in business environment. If the Company determines it is “more likely than not” that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two step test, the carrying amount of a reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When a Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations (which in some cases may be based in part on third party valuation reports), or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss.
Most of the Company’s reporting units are not publicly traded. Therefore, the Company estimates the fair value of its reporting units using internal budgets and forecasts, adjusted for any market participants’ assumptions and discounted at the rate of return required by a market participant. The Company considers both market and income-based approaches to determine a range of fair value, but typically concludes that the value derived using an income-based approach is more representative of fair value due to the lack of direct market comparables. The Company does use market data to corroborate and determine the reasonableness of the fair value derived from the income-based discounted cash flow analysis.
Indefinite-lived Intangible Assets:
The Company’s indefinite-lived intangible assets primarily include land use rights, easements, concessions and trade name. These are tested for impairment on an annual basis or whenever events or changes in circumstances necessitate an evaluation for impairment. If the carrying amount of an intangible asset exceeds its fair value, the excess is recognized as impairment expense.
In July 2012, the FASB issued ASU No. 2012-02, Testing Indefinite-Lived Intangible Assets for Impairment (ASU No. 2012-02), which amended the existing guidance for indefinite-lived intangible assets impairment testing. Under the amendments in ASU No. 2012-02, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances indicate that it is more likely than not that an intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity determines that it is not more likely than not that an intangible asset is impaired, then the entity is not required to take further action. An entity also has the option to bypass the qualitative assessment for any intangible asset in any period and proceed directly to performing the quantitative impairment test. ASU No. 2012-02 is effective for annual and interim impairment tests performed for fiscal periods beginning on or after September 15, 2012 and early adoption is permitted. AES elected to adopt ASU No. 2012-02 early for its 2012 annual intangible asset impairment evaluations performed at October 1 and qualitatively assessed certain of its intangible assets. The adoption did not have an impact on the Company’s financial position, results of operations or cash flows and is not expected to have an impact in future periods.
ACCOUNTS PAYABLE AND OTHER ACCRUED LIABILITIES-Accounts payable consists of amounts due to trade creditors related to the Company’s core business operations. The nature of these payables include amounts owed to vendors and suppliers for items such as energy purchased for resale, fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, regulatory liabilities, legal contingencies and employee-related costs including payroll, benefits and related taxes.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
REGULATORY ASSETS AND LIABILITIES-The Company records assets and liabilities that result from the regulated ratemaking process that are not recognized under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred due to the probability of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs previously deferred ceases to be probable, the related regulatory assets are written off and recognized in income from continuing operations.
PENSION AND OTHER POSTRETIREMENT PLANS-The Company recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current year changes in the funded status recognized in AOCL, except for those plans at certain of the Company’s regulated utilities that can recover portions of their pension and postretirement obligations through future rates. All plan assets are recorded at fair value. AES follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
INCOME TAXES-Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more-likely-than-not recognition threshold and measurement analysis before they are recognized for financial statement reporting.
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
ASSET RETIREMENT OBLIGATIONS-The Company records the fair value of the liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
NONCONTROLLING INTERESTS-Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income in the Consolidated Statements of Operations and Consolidated Statements of Changes in Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero.
Although in general, the noncontrolling ownership interest in earnings is calculated based on ownership percentage, certain of the Company’s wind businesses use the HLBV method as an approximation of certain
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
profit sharing arrangements. HLBV uses a balance sheet approach, which measures the Company’s equity in income or loss by calculating the change in the amount of net worth the partners are legally able to claim based on a hypothetical liquidation of the entity at the beginning of a reporting period compared to the end of that period. This method is used in Wind Generation partnerships which contain agreements designating different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership.
GUARANTOR ACCOUNTING-At the inception of a guarantee, the Company records the fair value of a guarantee as a liability, with the offset dependent on the circumstances under which the guarantee was issued. The Company does not recognize guarantees given to third parties for its subsidiaries’ performance.
TRANSFER OF FINANCIAL ASSETS-As of December 31, 2012, the Company has $50 million recognized as accounts receivable and as an associated secured borrowing on its Consolidated Balance Sheet. IPL, the Company’s integrated utility in Indianapolis, has securitized these accounts receivable through IPL Funding, a special-purpose entity. Under the arrangement, interests in these accounts receivable are sold, on a revolving basis, to unrelated parties (the Purchasers) up to the lesser of $50 million or an amount determinable under the facility agreement. The Purchasers assume the risk of collection on the interest sold without recourse to IPL, which retains the servicing responsibilities for the interest sold. While no direct recourse to IPL exists, IPL risks loss in the event collections are not sufficient to allow for full recovery of the retained interests. No servicing asset or liability is recorded since the servicing fee paid to IPL approximates a market rate. The retained interest in these securitized accounts receivable does not meet the definition of a participating interest thereby requiring the Company to recognize on its Consolidated Balance Sheet the portion transferred and the proceeds received as accounts receivable and a secured borrowing, respectively.
FOREIGN CURRENCY TRANSLATION-A business’ functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is a currency other than the U.S. Dollar translate their assets and liabilities into U.S. Dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. Dollars at the average exchange rates that prevailed during the period. Translation adjustments are included in AOCL. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in AOCL. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in determining net income. Accumulated foreign currency translation adjustments are reclassified to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity.
REVENUE RECOGNITION-Revenue from Utilities is classified as regulated in the Consolidated Statements of Operations. Revenue from the sale of energy is recognized in the period during which the sale occurs. The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial. The Company has businesses where it makes sales and purchases of power to and from Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”). In those instances, the Company accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis. Revenue from Generation businesses is classified as non-regulated and is recognized based upon output delivered and capacity provided, at rates as specified under contract terms or prevailing market rates. Certain of the Company PPAs meet the definition of an operating lease or contain similar arrangements. Typically, minimum
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
lease payments from such PPAs are recognized as revenue on a straight line basis over the lease term whereas contingent rentals are recognized when earned. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
SHARE-BASED COMPENSATION-The Company grants share-based compensation in the form of stock options and restricted stock units. The expense is based on the grant-date fair value of the equity or liability instrument issued and is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. Currently, the Company uses a Black-Scholes option pricing model to estimate the fair value of stock options granted to its employees.
GENERAL AND ADMINISTRATIVE EXPENSES-General and administrative expenses include corporate and other expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments. Additionally, all costs associated with business development efforts are classified as general and administrative expenses.
DERIVATIVES AND HEDGING ACTIVITIES-Under the accounting standards for derivatives and hedging, the Company recognizes all contracts that meet the definition of a derivative, except those designated as normal purchase or normal sale at inception, as either assets or liabilities in the Consolidated Balance Sheets and measures those instruments at fair value. See the Company’s fair value policy and Note 4-Fair Value for additional discussion regarding the determination of the fair value. The PPAs and fuel supply agreements entered into by the Company are evaluated to determine if they meet the definition of a derivative or contain embedded derivatives, either of which require separate valuation and accounting. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for the commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could then be net settled and meet the definition of a derivative.
Derivatives primarily consist of interest rate swaps, cross-currency swaps, foreign currency instruments, and commodity derivatives. The Company enters into various derivative transactions in order to hedge its exposure to certain market risks, primarily interest rate, foreign currency and commodity price risks. Regarding interest rate risk, AES and its subsidiaries generally utilize variable rate debt financing for construction projects and operations so interest rate swap, lock, cap, and floor agreements are entered into to manage interest rate risk by effectively fixing or limiting the interest rate exposure on the underlying financing and are typically designated as cash flow hedges. Regarding foreign currency risk, we are exposed to it as a result of our investments in foreign subsidiaries and affiliates that may be impacted by significant fluctuations in foreign currency exchange rates so foreign currency options and forwards are utilized, where deemed appropriate, to manage the risk related to these fluctuations. Cross-currency swaps are utilized in certain instances to manage the risk related to fluctuations in both interest rates and certain foreign currencies. In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives as a portion of the contracts is denominated in a currency other than the functional or local currency of that subsidiary or the currency of the item. Regarding commodity price risk, we are exposed to the impact of market fluctuations in the price of electricity, fuel and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions (which provide our distribution businesses with a franchise to serve a specific geographic region), a portion of our current and expected future revenues are derived from businesses without significant long-term purchase or sales contracts. We use an overall hedging strategy, not just derivatives, to hedge our financial performance against the effects of fluctuations in commodity prices.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. The Company only has cash flow hedges at this time. Changes in the fair value of a derivative that is highly effective, designated and qualifies as a cash flow hedge are deferred in AOCL and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is recognized in earnings immediately. For all designated and qualifying hedges, the Company maintains formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If AES determines that the derivative is no longer highly effective as a hedge, hedge accounting will be discontinued prospectively. For cash flow hedges of forecasted transactions, AES estimates the future cash flows of the forecasted transactions and evaluates the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from AOCL into earnings.
While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting. Changes in the fair value of derivatives not designated and qualifying as cash flow hedges are immediately recognized in earnings. Regardless of when gains or losses on derivatives (including all those where the fair value measurement is classified as Level 3) are recognized in earnings, they are generally classified as follows: interest expense for interest rate and cross-currency derivatives, foreign currency transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity and other derivatives. However, gains and losses on interest rate and cross-currency derivatives are classified as foreign currency transaction gains and losses if they offset the remeasurement of the foreign currency-denominated debt being hedged by the cross-currency swaps and the amount reclassified from AOCL to cost of sales to offset depreciation where the variable-rate interest capitalized as part of the asset was hedged during its construction. Cash flows arising from derivatives are included in the Consolidated Statements of Cash Flows as an operating activity given the nature of the underlying risk being economically hedged and the lack of significant financing elements, except that cash flows on designated and qualifying hedges of variable-rate interest during construction are classified as an investing activity.
The Company has elected not to offset net derivative positions in the financial statements. Accordingly, the Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
2. INVENTORY
As of December 31, 2012, 78% of the Company’s inventory was valued using average cost, 14% was determined using the FIFO method and the remaining inventory was valued using the specific identification method. The following table summarizes our inventory balances as of December 31, 2012 and 2011:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
3. PROPERTY, PLANT AND EQUIPMENT
The following table summarizes the components of the electric generation and distribution assets and other property, plant and equipment with their estimated useful lives. The amounts are stated net of impairment losses recognized as further discussed in Note 21-Asset Impairment Expense.
(1) Net electric generation and distribution assets and other related to our held for sale businesses of $1.2 billion as of December 31, 2011, were excluded from the table above and were included in the noncurrent assets of discontinued and held for sale businesses in the consolidated balance sheet. There were no amounts excluded as of December 31, 2012.
(2) Net electric generation and distribution assets, and other include unamortized internal use software costs of $153 million and $156 million as of December 31, 2012 and 2011, respectively.
The following table summarizes depreciation expense (including the amortization of assets recorded under capital leases), amortization of internal use software and interest capitalized during development and construction on qualifying assets for the years ended December 31, 2012, 2011 and 2010:
Property, plant and equipment, net of accumulated depreciation, of $16.0 billion and $15.2 billion was mortgaged, pledged or subject to liens as of December 31, 2012 and 2011, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes regulated and non-regulated generation and distribution property, plant and equipment and accumulated depreciation as of December 31, 2012 and 2011:
The following table summarizes the amounts recognized, which were related to asset retirement obligations, for the years ended December 31, 2012 and 2011:
The Company’s asset retirement obligations covered by the relevant guidance primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. There were no legally restricted assets for purposes of settling asset retirement obligations at December 31, 2012. The fair value of legally restricted assets for purposes of settling asset retirement obligations was $1 million at December 31, 2011.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Ownership of Coal-Fired Facilities
DP&L has undivided ownership interests in seven coal-fired generation facilities jointly owned with other utilities. As of December 31, 2012, DP&L had $36 million of construction work in process at such facilities. DP&L’s share of the operating costs of such facilities is included in Cost of Sales in the Consolidated Statement of Operations and its share of investment in the facilities is included in Property, Plant and Equipment in the Consolidated Balance Sheet. DP&L’s undivided ownership interest in such facilities at December 31, 2012 is as follows:
4. FAIR VALUE
The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Valuation Techniques
The fair value measurement accounting guidance describes three main approaches to measuring the fair value of assets and liabilities: (1) market approach, (2) income approach and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on current market expectations of the return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and emissions allowances, etc.). In general, the Company determines the fair value of investments and derivatives using the market approach and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
liabilities, all three approaches are considered; however, the value estimated under the income approach is often the most representative of fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of the fair value of the assets and liabilities and their placement within the fair value hierarchy levels.
Investments
The Company’s investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are measured at fair value using quoted market prices. Debt securities primarily consist of unsecured debentures, certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to London Inter-Bank Offered Rate, or LIBOR, a benchmark interest rate widely used by banks in the interbank lending market) or Selic (overnight borrowing rate) rates in Brazil. Fair value is determined from comparisons to market data obtained for similar assets and are considered Level 2 in the fair value hierarchy. For more detail regarding the fair value of investments see Note 5-Investments in Marketable Securities.
Derivatives
Any Level 1 derivative instruments are exchange-traded commodity futures for which the pricing is observable in active markets, and as such, these are not expected to transfer to other levels. There have been no transfers between Level 1 and Level 2.
For all derivatives, with the exception of any classified as Level 1, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. Among the most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate (“EURIBOR”)), foreign exchange rates and commodity prices. Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published information provided from another source. When significant inputs are not observable, the Company uses relevant techniques to best estimate the inputs, such as regression analysis or prices for similarly traded instruments available in the market.
For derivatives for which there is a standard industry valuation model, the Company uses a third-party treasury and risk management software product that uses a standard model and observable inputs to estimate the fair value. For these derivatives, the Company performs analytical procedures and makes comparisons to other third-party information in order to assess the reasonableness of the fair value. For derivatives for which there is not a standard industry valuation model (such as PPAs and fuel supply agreements that are derivatives or include embedded derivatives), the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. At each quarter-end, the models for the commodity and foreign currency-based derivatives are generally prepared and reviewed by employees who globally manage the respective commodity and foreign currency risks and are analytically reviewed independent of those employees.
Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR). The Company then makes a credit valuation adjustment (“CVA”) by further discounting the cash flows for nonperformance or credit risk based on the observable or estimated debt spread of the Company’s subsidiary or its counterparty and the tenor of the respective derivative instrument. The CVA for asset positions
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
is based on the counterparty’s credit ratings and debt spreads. The CVA for liability positions is based on the Parent Company’s or the subsidiary’s current debt spread. In the absence of readily obtainable credit information, the Parent Company’s or the subsidiary’s estimated credit rating (based on applying an standard industry model to historical financial information and then considering other relevant information) and spreads of comparably rated entities or the respective country’s debt spreads are used as a proxy. All derivative instruments are analyzed individually and are subject to unique risk exposures.
The Company’s methodology to fair value its derivatives is to start with any observable inputs; however, in certain instances the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. In addition, in certain instances, there may not be market or market-corroborated data readily available, requiring the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. The fair value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are classified as Level 3 when the use of unobservable inputs is significant. When the use of unobservable inputs is insignificant, assets and liabilities are classified as Level 2. Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and result from changes in significance of unobservable inputs used to calculate the CVA.
The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) at December 31, 2012:
Changes in the above significant unobservable inputs that lead to a significant and unusual impact to current period earnings are disclosed to the Financial Audit Committee. For interest rate derivatives, increases (decreases) in the estimates of our own credit spreads would decrease (increase) the value of the derivatives in a liability position. For foreign currency derivatives, increases (decreases) in the estimate of the above exchange rate would increase (decrease) the value of the derivative. For commodity and other derivatives in the above table, increases (decreases) in the estimated inflation would increase (decrease) the value of those embedded derivatives, while increases (decreases) in the estimated market price for power would increase (decrease) the value of that embedded derivative.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Debt
Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon the type of loan. In general, the carrying amount of variable rate debt is a close approximation of its fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow analyses. In the discounted cash flow analysis, the discount rate is based on the credit rating of the individual debt instruments, if available, or the credit rating of the subsidiary. If the subsidiary’s credit rating is not available, a synthetic credit rating is determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry specific factors. For subsidiaries located outside the U.S., in the event that the country rating is lower than the credit rating previously determined, the country rating is used for purposes of the discounted cash flow analysis. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date. The fair value was determined using available market information as of December 31, 2012. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to December 31, 2012.
Nonfinancial Assets and Liabilities
For nonrecurring measurements derived using the income approach, fair value is determined using valuation models based on the principles of discounted cash flows (“DCF”). The income approach is most often used in the impairment evaluation of long-lived tangible assets, goodwill and intangible assets. The Company uses its internally developed DCF valuation models as the primary means to determine nonrecurring fair value measurements though other valuation approaches prescribed under the fair value measurement accounting guidance are also considered. Depending on the complexity of a valuation, an independent valuation firm may be engaged to assist management in the valuation process. A few examples of input assumptions to such valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates and power and commodity prices. Whenever possible, the Company attempts to obtain market observable data to develop input assumptions. Where the use of market observable data is limited or not available for certain input assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis and extrapolations.
For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to identify sale transactions of identical or similar assets. This approach is used in impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.
For nonrecurring measurements derived using the cost approach, fair value is typically determined using the replacement cost approach. Under this approach, the depreciated replacement cost of assets is determined by first determining the current replacement cost of assets and then applying the remaining useful life percentages to such costs. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Fair Value Considerations
In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company’s or its counterparty’s nonperformance. The conditions and criteria used to assess these factors are:
Sources of market assumptions
The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Reuters). To determine fair value, where market data is not readily available, management uses comparable market sources and empirical evidence to develop its own estimates of market assumptions.
Market liquidity
The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company’s current trading volume and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of assets traded without significantly affecting the market price. Another factor the Company considers when determining whether a market is active or inactive is the presence of government or regulatory controls over pricing that could make it difficult to establish a market based price when entering into a transaction.
Nonperformance risk
Nonperformance risk refers to the risk that an obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited to, the Company or its counterparty’s credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are parties to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives, which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.
Nonperformance risk on the investments held by the Company is incorporated in the fair value derived from quoted market data to mark the investments to fair value.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Recurring Measurements
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2012 and December 31, 2011:
The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2012 and 2011 (presented net by type of derivative where any foreign currency impacts are presented as part of gains (losses) in earnings or other comprehensive income as appropriate):
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Nonrecurring Measurements:
For purposes of impairment evaluation, the Company measured the fair value of long-lived assets and equity method investments under the fair value measurement accounting guidance. To measure the amount of impairment, the Company compares the fair value of assets and liabilities at the evaluation date to the carrying amount at the end of the month prior to the evaluation date. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
(1) See Note 21-Asset Impairment Expense for further information.
(2) See Note 9-Other Non-Operating Expense for further information.
(3) See Note 10-Goodwill and Other Intangible Assets for further information.
(4) The carrying amounts and fair value of the asset groups also include other assets and liabilities; however, impairment expense recognized was limited to the carrying amounts of long-lived assets.
The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets for the year ended December 31, 2012:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Financial Instruments not Measured at Fair Value in the Condensed Consolidated Balance Sheets
The following table sets forth the carrying amount and fair value of the Company’s financial assets and liabilities that are not measured at fair value in the condensed consolidated balance sheets as of December 31, 2012 and December 31, 2011, but for which fair value is disclosed. In addition, the fair value level hierarchy of such assets and liabilities is presented as of December 31, 2012:
(1) These accounts receivable principally relate to amounts due from the independent system operator in Argentina and are included in “Non-current assets-Other” in the accompanying consolidated balance sheets. The fair value of these accounts receivable includes the carrying amount of value added tax which is collected from customers and paid to the government. During the year ended December 31, 2012, the significant decline in fair value of these accounts receivable was a result of the increased credit risk in Argentina. See Note 7-Long-term Financing Receivables for further information.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
5. INVESTMENTS IN MARKETABLE SECURITIES
The following table sets forth the Company’s investments in marketable debt and equity securities classified as trading and available-for-sale as of December 31, 2012 and 2011 by type of investment and by level within the fair value hierarchy. The security types are determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its securities.
(1) Amortized cost approximated fair value at December 31, 2012 and 2011, with the exception of certain common stock investments with a cost basis of $4 million carried at their fair value of $1 million at December 31, 2011.
As of December 31, 2012 and 2011, the Company did not have any Level 3 marketable securities. During 2011, the Company sold Level 3 market securities of $42 million held at the beginning of the year. As of December 31, 2012 and 2011, all available-for-sale debt securities had stated maturities of less than one year.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes the pre-tax gains and losses related to available-for-sale securities for the years ended December 31, 2012, 2011 and 2010. Gains and losses on the sale of investments are determined using the specific identification method. There was no other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income for the years ended December 31, 2012, 2011 and 2010.
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Volume of Activity
The following tables set forth, by type of derivative, the Company’s outstanding notional under its derivatives and the weighted average remaining term as of December 31, 2012, regardless of whether the derivative instruments are in designated and qualifying cash flow hedging relationships:
(1) The Company’s interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between December 31, 2012 and the maturity of the derivative instrument, which includes forward starting derivative instruments. The interest rate and cross currency derivatives range in maturity through 2030 and 2028, respectively.
(2) The percentage of variable-rate debt currently hedged is based on the related index and excludes forecasted issuances of debt and variable-rate debt tied to other indices where the Company has no interest rate derivatives.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
(1) Represents contractual notionals. The notionals for options have not been probability adjusted, which generally would decrease them.
(2) Represents the remaining tenor of our foreign currency derivatives weighted by the corresponding notional. These options and forwards and these embedded derivatives range in maturity through 2014 and 2025, respectively.
(1)
Represents the remaining tenor of our commodity and embedded derivatives weighted by the corresponding volume. These derivatives range in maturity through 2019.
(2) Our exposure is to fluctuations in the price of aluminum while the notional is based on the amount of power we sell under the PPA.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Accounting and Reporting
Fair Value Hierarchy & Hedging Designation
The following tables set forth the fair value of the Company’s types of derivative instruments as of December 31, 2012 and 2011 by level within the fair value hierarchy then by whether or not they are designated hedging instruments.
As of December 31, 2012 and 2011, these tables include current assets of $14 million and $49 million, respectively, noncurrent assets of $86 million and $71 million, respectively, current liabilities of $186 million and $153 million, respectively, and noncurrent liabilities of $471 million and $537 million, respectively. These tables do not include the following balances that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated PPA: $186 million and
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
$163 million of assets as of December 31, 2012 and 2011, respectively and $191 million of liabilities as of December 31, 2012. The amortization is included in the table below under “Not Designated for Hedge Accounting”.
Effective Portion of Cash Flow Hedges
The following table sets forth the pre-tax gains (losses) recognized in AOCL and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships (including amounts that were reclassified from AOCL to interest expense related to interest rate derivative instruments that previously, but no longer, qualify for cash flow hedge accounting), as defined in the accounting standards for derivatives and hedging, for the years ended December 31, 2012, 2011 and 2010:
For the years ended December 31, 2012, 2011 and 2010, the above table includes pre-tax gains (losses) of $(10) million, $0 million, and $(1) million, respectively, that were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter. The pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
taxes over the next twelve months as of December 31, 2012 is $(110) million for interest rate hedges, $9 million for cross currency swaps, $(3) million for foreign currency hedges, and $(7) million for commodity and other hedges.
Ineffective Portion of Cash Flow Hedges
The following table sets forth the pre-tax gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the years ended December 31, 2012, 2011 and 2010:
Not Designated for Hedge Accounting
The following table sets forth the gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, for the years ended December 31, 2012, 2011 and 2010:
Credit Risk-Related Contingent Features
Our generation business in Chile has cross currency swap agreements that contain credit contingent provisions which would permit the counterparties with which Gener is in a net liability position to require collateral credit support when the mark-to-market value of the derivatives exceeds the unsecured thresholds established in the agreements. If Gener’s credit rating were to fall below the minimum threshold, the counterparties can demand immediate collateralization of the entire mark-to-market loss of the swaps (fair value excluding credit valuation adjustments), which was $2 million and $18 million at December 31, 2012 and 2011, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
DPL, our utility in Ohio, has certain over-the-counter commodity derivative contracts under master netting agreements that contain provisions that require its debt to maintain an investment-grade credit rating from credit rating agencies. If its debt were to fall below investment grade, the business would be in violation of these provisions and the counterparties to the derivative contracts could request immediate payment or demand immediate and ongoing full overnight collateralization of the mark-to-market loss (fair value excluding credit valuation adjustments), which was $13 million and $28 million as of December 31, 2012 and 2011, respectively. As of December 31, 2012 and 2011, DPL had posted $5 million and $16 million, respectively, of cash collateral directly with third parties or in a broker margin account and DPL held $0 million and $3 million, respectively, of cash collateral that it received from counterparties to its derivative instruments that were in an asset position.
7. LONG-TERM FINANCING RECEIVABLES
Long-term financing receivables represent receivables from certain Latin American governmental bodies, primarily in Argentina, that have contractual maturities of greater than one year. In Argentina, as a result of energy market reforms which began in 2004, and consistent with contractual arrangements, the Company converted certain accounts receivable into long-term financing receivables. These receivables accrue interest and are collected in monthly installments over 10 years once the related plant begins operations. In addition, the Company also receives an ownership interest in these newly-built plants once the receivables have been fully repaid. Collection of the Argentina financing receivables is subject to various business risks and uncertainties including timely payment of principal and interest, completion and operation of power plants which provide for payments of the long-term receivables, regulatory changes that could impact the timing and amount of collections and economic conditions in Argentina. The Company periodically analyzes each of these factors and assesses collectability of the related accounts receivable. The Company’s collection estimates are based on assumptions that it believes to be reasonable but are also inherently uncertain. Actual future cash flows could differ from these estimates. The decrease in the long-term financing receivables from December 31, 2011 is primarily related to the impact of foreign currency translation. The receivables are included in “Noncurrent assets -other” on the Consolidated Balance Sheets. The following table sets forth the breakdown of financing receivables by country as of December 31, 2012 and 2011:
(1) Excludes noncurrent receivables of $120 million and $82 million, respectively, as of December 31, 2012 and 2011, which have not been converted into long-term financing receivables and currently have no due date.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
8. INVESTMENTS IN AND ADVANCES TO AFFILIATES
The following table summarizes the relevant effective equity ownership interest and carrying values for the Company’s investments accounted for under the equity method as of December 31, 2012 and 2011.
(1) Represent our investments in AES Solar Energy Ltd in Europe, AES Solar Power LLC in the United States and AES Solar Power, PR, LLC in Puerto Rico.
(2) Represent VIEs in which the Company holds a variable interest, but is not the primary beneficiary.
(3) The Company sold 80% of its interest in AES Energia Cartagena S.R.L. during 2012 resulting in the deconsolidation of this entity. Refer to Note 24-Acquisitions and Dispositions for further information.
(4) Represent our investments in Chengdu AES Kaihua Gas Turbine Company Ltd. and Yangcheng International Power Generating Co. Ltd. The Company sold its interest in the Yangcheng affiliates during 2012. Refer to Note 24-Acquisitions and Dispositions for further information.
(5) Represent our investments in Guohua AES (Huanghua) Wind Power Co. Ltd., Guohua AES (Hulunbeier) Wind Power Co. Ltd., Guohua AES (Chenba’-erhu) Wind Power Co. Ltd., and Guohua AES (Xinba’-erhu) Wind Power Co. Ltd. The Company sold its interest in the affiliates during 2012. Refer to Note 24-Acquisitions and Dispositions for further information.
(6) IC Ictas Energy Group joint venture was dissolved during 2012. See the Entek description below.
(7) The Company sold its interest in InnoVent during 2012. Refer to Note 9-Other Non-Operating Expense for further information.
(8) The Company completed the sale of its interest in JHRH in the fourth quarter of 2012. Refer to Note 9-Other Non-Operating Expense for further information.
AES Barry Ltd.-The Company holds a 100% ownership interest in AES Barry Ltd. (“Barry”), a dormant entity in the United Kingdom that disposed of its generation and other operating assets. Due to a debt agreement,
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
no material financial or operating decisions can be made without the banks’ consent, and the Company does not control Barry. As of December 31, 2012 and 2011, other long-term liabilities included $55 million and $52 million, respectively, related to this debt agreement.
AES Entek Elektrik Üretimi A.Ş. (“Entek”)- Entek, a joint venture with Koc Holding, owns and operates gas-fired and hydroelectric generation facilities in Turkey with an aggregate capacity of 378 MW and is also engaged in an energy trading business. During the fourth quarter of 2012, AES entered into an agreement to dissolve a separate joint venture in Turkey with IC Ictas Energy Group. Under the agreement, AES received net proceeds of $10 million and a 100% interest in three hydroelectric plants with an aggregate generation capacity of 62 MW from IC Ictas Energy Group. The Company recognized a pretax gain of $1 million on the dissolution. Thereafter, the Company sold these hydropower plants to Entek and received net proceeds of $82 million. Both transactions closed in the fourth quarter of 2012.
Trinidad Generation Unlimited (“TGU”)-Although the Company’s ownership in TGU is 10%, the Company accounts for the investment as an equity method investment due to the Company’s ability to exercise significant influence through the supermajority vote requirement for any significant future project development activities. TGU has four gas turbines, which commenced commercial operations in 2011 and 2012.
Summarized Financial Information
The following tables summarize financial information of the Company’s 50%-or-less owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for using the equity method.
At December 31, 2012, accumulated deficit included $150 million related to the undistributed earnings of the Company’s 50%-or-less owned affiliates. Distributions received from these affiliates were $22 million, $36 million, and $49 million for the years ended December 31, 2012, 2011, and 2010, respectively. As of December 31, 2012, the aggregate carrying amount of our investments in equity affiliates exceeded the underlying equity in their net assets by $37 million.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
9. OTHER NON-OPERATING EXPENSE
Other non-operating expense for the years ended December 31, 2012, 2011 and 2010 consisted of:
China-During the first quarter of 2012, the Company concluded it was more likely than not that it would sell its interests in certain joint ventures in China before the end of their terms. These investments include coal-fired, hydroelectric and wind generation facilities accounted for under the equity method of accounting. This conclusion was considered an impairment indicator. In measuring the other-than-temporary impairment, the carrying value of $165 million of these investments was compared to their fair value of $133 million resulting in an other-than-temporary impairment expense of $32 million. The Company signed two separate sale agreements for the sale of these investments, which were closed in the third and fourth quarters of 2012. See Note 24-Acquisitions and Dispositions for further information.
InnoVent-During the first quarter of 2012, the Company concluded it was more likely than not that it would sell its interest in InnoVent S.A.S. (“InnoVent”), an equity method investment in France with wind generation projects totaling 75 MW. InnoVent had a carrying value of $36 million which exceeded its fair value of $19 million, resulting in an other-than-temporary impairment expense of $17 million. The sale transaction was completed on June 28, 2012.
China- During the third quarter of 2011, the Company recognized other-than-temporary-impairment on its 25% investment in Yangcheng, a 2100 MW coal-fired plant in China. During the nine months ended September 30, 2011, continually increasing coal prices in China reduced operating margins of coal generation facilities with no corresponding increase in tariffs. Further, under the Yangcheng venture agreement in effect at this time, AES was to surrender its equity interest to the venture partners in 2016 without additional compensation. As of September 30, 2011, Yangcheng had a carrying amount of $100 million which was written down to its estimated fair value of $26 million determined under the discounted cash flow analysis, and the difference was recognized as other non-operating expense.
Other-Other non-operating expense of $7 million for the year ended December 31, 2010 primarily consisted of an other-than-temporary impairment of an equity method investment. During the second quarter of 2010, AES decided not to pursue its investment in a project to generate environmental offset credits and recognized the other-than-temporary impairment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
10. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
The following table summarizes the changes in the carrying amount of goodwill, by segment for the years ended December 31, 2012 and 2011.
(1) Both the gross carrying amount and the accumulated impairment losses of the Asia generation segment have been reduced by $17 million with no impact on the net carrying amount for the segment. This relates to Chigen, which had fully impaired goodwill of $17 million and was sold during the year.
DPL-In connection with its acquisition of DPL, the Company recognized goodwill of approximately $2.6 billion, which was allocated between the two reporting units identified during the purchase price allocation: The Dayton Power and Light Company (“DP&L”, DPL’s regulated utility in Ohio) and certain related entities, and
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
DPL Energy Resources, Inc. (“DPLER”, DPL’s wholly-owned competitive retail electric service provider). Of the total goodwill, approximately $2.4 billion was allocated to DP&L and the remainder was allocated to DPLER.
On October 5, 2012, DP&L filed for approval an Electric Security Plan (“ESP”) with the Public Utility Commission of Ohio (“PUCO”). The plan was re-filed on December 31, 2012 to correct for certain projected costs. Within the ESP filing, DP&L agreed to request a separation of its generation assets from its transmission and distribution assets in recognition that a restructuring of DP&L operations will be necessary, in compliance with Ohio law. Also, during 2012, North American natural gas prices fell significantly from the previous year exerting downward pressure on wholesale electricity prices in the Ohio power market. Falling power prices compressed wholesale margins at DP&L. Furthermore, these lower power prices have led to increased customer switching from DP&L to other competitive retail electric service (“CRES”) providers, including DPLER, who are offering retail prices lower than DP&L’s current standard service offer. Also, several municipalities in DP&L’s service territory have passed ordinances allowing them to become government aggregators and some municipalities have contracted with CRES providers to provide generation service to the customers located within the municipal boundaries, further contributing to the switching trend. CRES providers have also become more active in DP&L’s service territory. In September 2012, management revised its cash flow forecasts based on these new developments and forecasted lower profitability and operating cash flows than previously prepared forecasts. These new developments have reduced DP&L’s forecasted profitability, operating cash flows, liquidity and may impact DPL and DP&L’s ability to access the capital markets and maintain their current credit ratings in the future. Collectively, in the third quarter of 2012, these events were considered an interim impairment indicator for goodwill at the DP&L reporting unit. There were no interim impairment indicators identified for the goodwill at DPLER.
The Company performed an interim impairment test for the $2.4 billion of goodwill at the DP&L reporting unit level. In the preliminary Step 1 of the goodwill impairment test, the fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The material assumptions included within the discounted cash flow valuation model were customer switching and aggregation trends, capacity price curves, energy price curves, amount of the non-bypassable charge, commodity price curves, dispatching, transition period for the conversion to a wholesale competitive bidding structure, amount of the standard service offer charge, valuation of regulatory assets and liabilities, discount rates and deferred income taxes. The reporting unit failed the preliminary Step 1 and a preliminary Step 2 of the goodwill impairment test was performed. Further refinements to these assumptions were performed in the fourth quarter of 2012 as part of the finalization of Step 1 and Step 2 tests. During the year ended December 31, 2012, the Company recognized goodwill impairment expense of $1.82 billion at the DP&L reporting unit. DPL is reported in the US Utilities segment. The goodwill associated with the DPL acquisition is not deductible for tax purposes. Accordingly, there is no cash tax or financial statement tax benefit related to the impairment. The pretax impairment impacted the Company’s effective tax rate for the year ended December 31, 2012, which was 225%.
Chigen-During the third quarter of 2011, the Company identified higher coal prices and the resulting reduced operating margins in China as an impairment indicator for the goodwill at Chigen, our wholly-owned subsidiary that holds equity interests in Chinese ventures and reported in the Asia Generation segment. A significant downward revision of cash flow forecasts indicated that the fair value of Chigen reporting unit was lower than its carrying amount. As of September 30, 2011, Chigen had goodwill of $17 million. The Company performed an interim impairment evaluation of Chigen’s goodwill and determined that goodwill had no implied fair value. As a result, the entire carrying amount of $17 million was recognized as goodwill impairment in the third quarter of 2011.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Deepwater-During the third quarter of 2010, Deepwater, our petcoke-fired merchant generation facility in Texas, reported in the US Generation segment, incurred a goodwill impairment of $18 million. The Company determined the adverse market conditions as an impairment indicator, performed the two-step goodwill impairment test and recognized the entire $18 million carrying amount of goodwill as goodwill impairment in the third quarter of 2010.
Intangible Assets
The following tables summarize the balances comprising other intangible assets in the accompanying Consolidated Balance Sheets as of December 31, 2012 and 2011:
(1) Represent development rights, including but not limited to, land control, various permits and right to acquire equity interests in development projects resulting from asset acquisitions by our wind operations in Poland and the U.K.
(2) Represent legal rights to receive system reliability payments from the regulator.
(3) Includes renewable energy credits, land use rights and various other intangible assets none of which is individually significant.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes, by category, intangible assets acquired during the years ended December 31, 2012 and 2011:
(1) Represents intangible assets arising from the acquisition of DPL. See Note 24-Acquisitions and Dispositions for further information.
(2) Electric Security Plan is a rate plan for the supply and pricing of electric generation service applicable to Ohio’s electric utilities under state law. It provides a level of price stability to consumers of electricity as compared to market-based electricity prices. The plan was recognized as an intangible asset since the prices under the plan are higher than market prices charged by competitive retailers or CRES.
(3) Customer relationships represent the value assigned to customer information possessed by DPL in the purchase price allocation, where DPL has regular contact with the customer, and the customer has the ability to make direct contact with DPL. See Note 24-Acquisitions and Dispositions for further information.
(4) The amortization method used reflects the pattern in which the economic benefits of the intangible asset are consumed.
(5) Trademark/trade name represents the value assigned to trade name of DPLER, DPL’s subsidiary engaged in competitive retail business in Ohio.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes the estimated amortization expense, by intangible asset category, for 2013 through 2017:
Intangible asset amortization expense was $119 million, $36 million and $14 million for the years ended December 31, 2012, 2011 and 2010, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
11. REGULATORY ASSETS AND LIABILITIES
The Company has recorded regulatory assets and liabilities that it expects to pass through to its customers in accordance with, and subject to, regulatory provisions as follows:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
(1) Recoverable per National Electric Energy Agency (“ANEEL”) regulations through the Annual Tariff Adjustment (“IRT”). These costs are generally non-controllable costs and primarily consist of purchased electricity, energy transmission costs and sector costs that are considered volatile. These costs are recovered in 24 installments through the annual IRT process and are amortized over the tariff reset period.
(2) Deferred fuel costs incurred by our El Salvador subsidiaries associated with purchase of energy from the El Salvador spot market and the power generation plants. In El Salvador, the deferred fuel adjustment represents the variance between the actual fuel costs and the fuel costs recovered in the tariffs. The variance is recovered semi-annually at the tariff reset period.
(3) Includes assets with and without a rate of return. Other current regulatory assets that did not earn a rate of return were $19 million and $12 million, as of December 31, 2012 and 2011, respectively. Other noncurrent regulatory assets that did not earn a rate of return were $60 million and $37 million, as of December 31, 2012 and 2011, respectively. Other current and noncurrent regulatory assets primarily consist of:
•
Unamortized losses on long-term debt reacquired or redeemed in prior periods at IPL and DPL, which are amortized over the lives of the original issues in accordance with the FERC and PUCO rules.
•
Unamortized carrying charges and certain other costs related to Petersburg unit 4 at IPL.
•
Deferred storm costs incurred to repair 2008 storm damage at DPL, which have been deferred until such time that DPL seeks recovery in a future rate proceeding.
(4) Past expenditures on which the Company does not earn a rate of return.
(5) The regulatory accounting standards allow the defined pension and postretirement benefit obligation to be recorded as a regulatory asset equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Pension expense is recognized based on the plan’s actuarially determined pension liability. Recovery of costs is probable, but not yet determined. Pension contributions made by our Brazilian subsidiaries are not included in regulatory assets as those contributions are not covered by the established tariff in Brazil.
(6) Probability of recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. This amount is expected to be recovered, without interest, over the period as book-tax temporary differences reverse and become current taxes.
(7) Transmission service costs and other administrative costs from IPL’s participation in the Midwest ISO market, which are recoverable but do not earn a rate of return. Recovery of costs is probable, but the timing is not yet determined.
(8) In July 2012, the Brazilian energy regulator (the “Regulator”) approved the periodic review and reset of a component of Eletropaulo’s regulated tariff, which determines the margin to be earned by Eletropaulo. The review and reset of this tariff component is retroactive to July 2011 and will be applied to customers’ invoices from July 2012 to June 2015. From July 2011 through June 2012, Eletropaulo invoiced customers under the then existing tariff rate, as required by the Regulator. As the new tariff rate is lower than the pre-existing tariff rate, Eletropaulo is required to reduce customer tariffs for this difference over the next three years. Accordingly, from July 2011 through June 2012, Eletropaulo recognized a regulatory liability for such estimated future refunds, which was subsequently adjusted as of June 30, 2012 upon the finalization of the new tariff with the Regulator. As of December 31, 2012, Eletropaulo had recorded a current and noncurrent regulatory liability of $89 million and $445 million, respectively.
(9) Amounts received for costs expected to be incurred to improve the efficiency of our plants in Brazil as part of the IRT.
(10) Other current and noncurrent regulatory liabilities primarily consist of liabilities owed to electricity generators due to variance in energy prices during rationing periods (“Free Energy”). Our Brazilian
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
subsidiaries are authorized to recover or refund this cost associated with monthly energy price variances between the wholesale energy market prices owed to the power generation plants producing Free Energy and the capped price reimbursed by the local distribution companies which are passed through to the final customers through energy tariffs.
(11) Obligations for removal costs which do not have an associated legal retirement obligation as defined by the accounting standards on asset retirement obligations.
(12) Obligations established by ANEEL in Brazil associated with electric utility concessions and represent amounts received from customers or donations not subject to return. These donations are allocated to support energy network expansion and to improve utility operations to meet customers’ needs. The term of the obligation is established by ANEEL. Settlement shall occur when the concession ends.
The current regulatory assets and liabilities are recorded in “Other current assets” and “Accrued and other liabilities,” respectively, on the accompanying Consolidated Balance Sheets. The noncurrent regulatory assets and liabilities are recorded in “Other noncurrent assets” and “Other noncurrent liabilities,” respectively, in the accompanying Consolidated Balance Sheets.
The following table summarizes regulatory assets and liabilities by segment as of December 31, 2012 and 2011:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
12. DEBT
Non-Recourse Debt
The following table summarizes the carrying amount and terms of non-recourse debt as of December 31, 2012 and 2011:
(1) The interest rate on variable rate debt represents the total of a variable component that is based on changes in an interest rate index and of a fixed component. The Company has interest rate swaps and option agreements in an aggregate notional principal amount of approximately $3.6 billion on non-recourse debt outstanding at December 31, 2012. These agreements economically fix the variable component of the interest rates on the portion of the variable-rate debt being hedged so that the total interest rate on that debt has been fixed at rates ranging from approximately 4.33% to 8.70% and 6.53% to 8.75% for swaps and options, respectively. These agreements expire at various dates from 2013 through 2030.
(2) Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.
(3) Non-recourse debt of $1.3 billion as of December 31, 2011 was excluded from non-recourse debt and included in current and noncurrent liabilities of held for sale and discontinued businesses in the accompanying Consolidated Balance Sheets. There were no amounts excluded in 2012.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Non-recourse debt as of December 31, 2012 is scheduled to reach maturity as set forth in the table below:
As of December 31, 2012, AES subsidiaries with facilities under construction had a total of approximately $1.2 billion of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $1.6 billion in a number of available but unused committed credit lines to support their working capital, debt service reserves and other business needs. These credit lines can be used for borrowings, letters of credit, or a combination of these uses. The weighted average interest rate on borrowings from such revolving credit facilities was 13.53% at December 31, 2012.
Non-Recourse Debt Covenants, Restrictions and Defaults
The terms of the Company’s non-recourse debt include certain financial and non-financial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include but are not limited to maintenance of certain reserves, minimum levels of working capital and limitations on incurring additional indebtedness.
As of December 31, 2012 and 2011, approximately $612 million and $594 million, respectively, of restricted cash was maintained in accordance with certain covenants of the non-recourse debt agreements, and these amounts were included within “Restricted cash” and “Debt service reserves and other deposits” in the accompanying Consolidated Balance Sheets.
Various lender and governmental provisions restrict the ability of certain of the Company’s subsidiaries to transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to approximately $1.7 billion at December 31, 2012.
The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of December 31, 2012 and is included in the current portion of non-recourse debt unless otherwise indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
(1) In January 2013, Maritza and its lenders reached an agreement in principle to waive the defaults subject to a number of conditions, many of which are not completely within our control.
The defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants and/or other conditions such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the Company.
In addition, in the event that there is a default, bankruptcy or maturity acceleration at a subsidiary that meets the applicable definition of materiality under the corporate debt agreements of The AES Corporation, there could be a cross-default to the Company’s recourse debt. At December 31, 2012 none of the defaults listed above results in a cross-default under the recourse debt of the Company.
RECOURSE DEBT
The following table summarizes the carrying amount and terms of recourse debt of the Company as of December 31, 2012 and 2011:
The table below summarizes the principal amounts due, net of unamortized discounts, under our recourse debt for the next five years and thereafter:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Recourse Debt Covenants and Guarantees
Certain of the Company’s obligations under the senior secured credit facility are guaranteed by its direct subsidiaries through which the Company owns its interests in the AES Shady Point, AES Hawaii, and AES Warrior Run. The Company’s obligations under the senior secured credit facility are, subject to certain exceptions, secured by:
(i) all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company; and
(ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.
The senior secured credit facility is subject to mandatory prepayment under certain circumstances, including the sale of a guarantor subsidiary. In such a situation, the net cash proceeds from the sale of a Guarantor or any of its subsidiaries must be applied pro rata to repay the term loan using 60% of net cash proceeds, reduced to 50% when and if the parent’s recourse debt to cash flow ratio is less than 5:1. The lenders have the option to waive their pro rata redemption.
The senior secured credit facility contains customary covenants and restrictions on the Company’s ability to engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative arrangements; and other financial reporting requirements.
The senior secured credit facility also contains financial covenants requiring the Company to maintain certain financial ratios including a cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum ratio of the Company’s adjusted operating cash flow to the Company’s interest charges related to recourse debt of 1.3× must be maintained at all times and a recourse debt to cash flow ratio, calculated quarterly, which provides that the ratio of the Company’s total recourse debt to the Company’s adjusted operating cash flow must not exceed a maximum of 7.5× at December 31, 2012.
The terms of the Company’s senior unsecured notes and senior secured credit facility contain certain covenants including, without limitation, limitation on the Company’s ability to incur liens or enter into sale and leaseback transactions.
TERM CONVERTIBLE TRUST SECURITIES
Between 1999 and 2000, AES Trust III, a wholly-owned special purpose business trust and a VIE, issued approximately 10.35 million of $50 par value Term Convertible Preferred Securities (“TECONS”) with a semi-annual coupon payment of $3.375 for total proceeds of $517 million and concurrently purchased $517 million of 6.75% Junior Subordinated Convertible Debentures due 2029 (the “6.75% Debentures”) issued by AES. The Company consolidates AES Trust III in its consolidated financial statements and classifies the TECONS as recourse debt on its Consolidated Balance Sheet. The Company’s obligations under the 6.75% Debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by the Company of the TECON Trusts’ obligations. As of December 31, 2012 and 2011, the sole assets of AES Trust III are the 6.75% Debentures.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
AES, at its option, can redeem the 6.75% Debentures which would result in the required redemption of the TECONS issued by AES Trust III, currently for $50 per TECON. The TECONS must be redeemed upon maturity of the 6.75% Debentures. The TECONS are convertible into the common stock of AES at each holder’s option prior to October 15, 2029 at the rate of 1.4216, representing a conversion price of $35.17 per share. The maximum number of shares of common stock AES would be required to issue should all holders decide to convert their securities would be 14.7 million shares.
Dividends on the TECONS are payable quarterly at an annual rate of 6.75%. The Trust is permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the TECONS would accumulate quarterly and accrue interest, and the Company may not declare or pay dividends on its common stock. AES has not exercised the option to defer any dividends at this time and all dividends due under the Trust have been paid.
13. COMMITMENTS
LEASES-The Company and its subsidiaries enter into long-term non-cancelable lease arrangements which, for accounting purposes, are classified as either operating lease or capital lease. Operating leases primarily include certain transmission lines, office rental and site leases. Operating lease rental expense for the years ended December 31, 2012, 2011 and 2010 was $58 million, $63 million and $56 million, respectively. Capital leases primarily include transmission lines at our subsidiaries in Brazil, vehicles, and office and other operating equipment. Capital leases are recognized in Property, Plant and Equipment within “Electric generation and distribution assets.” The gross value of the capital lease assets as of December 31, 2012 and 2011 was $94 million and $95 million, respectively. The table below sets forth the future minimum lease payments under operating and capital leases together with the present value of the net minimum lease payments under capital leases as of December 31, 2012 for 2013 through 2017 and thereafter:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
CONTRACTS-The Company’s operating subsidiaries enter into long-term contracts for construction projects, maintenance and service, transmission of electricity, operations services and purchase of electricity and fuel. In general, these contracts are subject to variable quantities or prices and are terminable in limited circumstances only. Electricity purchase contracts primarily include energy auction agreements at our Brazil subsidiaries with extended terms from 2013 through 2028. The table below sets forth the future minimum commitments under these contracts as of December 31, 2012 for 2013 through 2017 and thereafter. Actual purchases under these contracts for the years ended December 31, 2012, 2011 and 2010 are also presented:
14. CONTINGENCIES
Guarantees, Letters of Credit
In connection with certain project financing, acquisition, power purchase, and other agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, AES has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations primarily relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 14 years.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes the Parent Company’s contingent contractual obligations as of December 31, 2012. Amounts presented in the table below represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of businesses of $24 million.
As of December 31, 2012, the Company had $3 million of commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit discussed above. The Company expects to fund these net investment commitments in 2013. The exact payment schedules will be dictated by the construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.
During 2012, the Company paid letter of credit fees ranging from 0.250% to 3.250% per annum on the outstanding amounts of letters of credit.
Environmental
The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of December 31, 2012, the Company had recorded liabilities of $14 million for projected environmental remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information and analysis, the Company believes that it is reasonably possible that costs associated with such liabilities, or as yet unknown liabilities, may exceed current reserves in amounts that could be material but cannot be estimated as of December 31, 2012.
Litigation
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims of approximately $321 million and $363 million as of December 31, 2012 and 2011, respectively. These reserves are reported on the consolidated balance sheets within “accrued and other liabilities” and “other long-term liabilities.” A significant portion of the reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that these reserves will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.
The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s consolidated financial statements. However, where no reserve has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2012. The material contingencies where a loss is reasonably possible primarily include: claims under financing agreements; disputes with offtakers, suppliers and EPC contractors; alleged violation of monopoly laws and regulations; income tax and non-income tax assessments by tax authorities; and environmental matters. In aggregate, the Company estimates that the range of potential losses, where estimable, related to these material contingences to be in the range of $881 million to $1.6 billion. The amounts considered reasonably possible do not include amounts reserved, as discussed above. These material contingencies do not include income tax related contingencies which are considered part of our uncertain tax positions.
15. BENEFIT PLANS
Defined Contribution Plan
The Company sponsors one defined contribution plan (“the Plan”), qualified under section 401 of the Internal Revenue Code. All U.S. employees of the Company are eligible to participate in the Plan except for those employees who are covered by a collective bargaining agreement, unless such agreement specifically provides that the employee is considered an eligible employee under the Plan. The Plan provides matching contributions in AES common stock, other contributions at the discretion of the Compensation Committee of the Board of Directors in AES common stock and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company’s matching contributions. Participants vest in other company contributions ratably over a five-year period ending on the fifth anniversary of their hire date. For the year ended December 31, 2012, the Company’s contributions to the Plan were approximately $21 million, and for the years ended December 31, 2011 and 2010, contributions were $22 million per year.
Defined Benefit Plans
Certain of the Company’s subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Pension benefits are based on years of credited service, age of the participant and average earnings. Of the 31 active defined benefit plans as of December 31, 2012, 5 are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table reconciles the Company’s funded status, both domestic and foreign, as of December 31, 2012 and 2011:
(1) The Company assumed the pension plan for AES Eastern Energy on December 28, 2012 as part of the settlement of the bankruptcy proceedings. See Note 23-Discontinued Operations and Held for Sale Businesses for further information.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the funded status of the plans, both domestic and foreign, as of December 31, 2012 and 2011:
The following table summarizes the Company’s accumulated benefit obligation, both domestic and foreign, as of December 31, 2012 and 2011:
(1) $1.9 billion of the total net unfunded projected benefit obligation is due to Eletropaulo in Brazil.
The table below summarizes the significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost, both domestic and foreign, as of December 31, 2012 and 2011:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
(1) A U.S. subsidiary of the Company has a defined benefit obligation of $764 million and $679 million as of December 31, 2012 and 2011, respectively, and uses salary bands to determine future benefit costs rather than rates of compensation increases. Rates of compensation increases in the table above do not include amounts related to this specific defined benefit plan.
(2) Includes an inflation factor that is used to calculate future periodic benefit cost, but is not used to calculate the benefit obligation.
The Company establishes its estimated long-term return on plan assets considering various factors, which include the targeted asset allocation percentages, historic returns and expected future returns.
The measurement of pension obligations, costs and liabilities is dependent on a variety of assumptions. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions.
The assumptions used in developing the required estimates include the following key factors:
•
discount rates;
•
salary growth;
•
retirement rates;
•
inflation;
•
expected return on plan assets; and
•
mortality rates.
The effects of actual results differing from the Company’s assumptions are accumulated and amortized over future periods and, therefore, generally affect the Company’s recognized expense in such future periods.
Sensitivity of the Company’s pension funded status to the indicated increase or decrease in the discount rate and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be asymmetric and are specific to the base conditions at year-end 2012. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The funded status as of December 31, 2012 is affected by the assumptions as of that date. Pension expense for 2012 is affected by the December 31, 2011 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the table below (in millions):
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for the years ended December 31, 2012 through 2010:
The following table summarizes the amounts reflected in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet as of December 31, 2012, that have not yet been recognized as components of net periodic benefit cost and amounts expected to be reclassified to earnings in the next fiscal year:
The following table summarizes the Company’s target allocation for 2012 and pension plan asset allocation, both domestic and foreign, as of December 31, 2012 and 2011:
The U.S. plans seek to achieve the following long-term investment objectives:
•
maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
•
long-term rate of return in excess of the annualized inflation rate;
•
long-term rate of return, net of relevant fees, that meet or exceed the assumed actuarial rate; and
•
long-term competitive rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates.
The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to manage risk through portfolio diversification and takes into account, among other possible factors, the above-stated objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends. The following table summarizes the Company’s U.S. plan assets by category of investment and level within the fair value hierarchy as of December 31, 2012 and 2011:
(1) Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The investment strategy of the foreign plans seeks to maximize return on investment while minimizing risk. The assumed asset allocation has less exposure to equities in order to closely match market conditions and near term forecasts. The following table summarizes the Company’s foreign plan assets by category of investment and level within the fair value hierarchy as of December 31, 2012 and 2011:
(1) Plan assets of our Brazilian subsidiaries are invested in private equities and commercial real estate through the plan administrator in Brazil. The fair value of these assets is determined using the income approach through annual appraisals based on a discounted cash flow analysis.
(2) Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
(3) Loans to participants are stated at cost, which approximates fair value.
The following table presents a reconciliation of all plan assets measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31, 2012 and 2011:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes the scheduled cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign:
16. EQUITY
Accumulated Other Comprehensive Loss
The components of accumulated other comprehensive loss, net of tax, as of December 31, 2012 and 2011 were as follows:
Dividend
The Company paid a dividend of $0.04 per outstanding share to its common stockholders in November 2012.
On December 7, 2012, the Board of Directors of the Company declared a quarterly common stock dividend of $0.04 per share payable on February 15, 2013 to shareholders of record at the close of business on February 1, 2013.
Stock Repurchase Program
The Company’s Board of Directors recently increased the share buyback authorization by $300 million, all of which is available. Under the program, the Company may repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and it can be modified or terminated by the Company’s Board at any time.
During the year ended December 31, 2012, shares of common stock repurchased under this plan totaled 24,790,384 at a total cost of $301 million plus a nominal amount of commissions (average of $12.16 per share
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
including commissions), bringing the cumulative total purchases under the program to 58,715,189 shares at a total cost of $680 million, which includes a nominal amount of commissions (average of $11.58 per share including commissions).
The shares of stock repurchased have been classified as treasury stock and accounted for using the cost method. A total of 66,415,984 and 42,386,961 shares were held in treasury stock at December 31, 2012 and 2011, respectively. The Company has not retired any shares held in treasury during the years ended December 31, 2012, 2011 or 2010.
Equity Transactions with Noncontrolling Interests
On July 7, 2011, a subsidiary of the Company completed the acquisition of an additional 10% equity interest in AES-VCM Mong Duong Power Company Limited (“Mong Duong”), a 1,240 MW coal-fired power plant in development in the Quang Ninh province in Vietnam, from Vietnam National Coal and Mineral Industries Group, its minority shareholder. On July 8, 2011, through a subsidiary, the Company sold 30% and 19% equity interests in Mong Duong to PSC Energy Global Co., Ltd. (a wholly owned subsidiary of POSCO Corporation) and Stable Investment Corporation (a wholly owned subsidiary of China Investment Corporation, a related party), respectively, resulting in the Company retaining a 51% indirect equity interest in Mong Duong. As a result of these transactions, the Company did not lose control of Mong Duong, which continues to be accounted for as a consolidated subsidiary. A net gain of $19 million resulting from these transactions was recorded as an equity transaction in additional paid-in capital.
The following table summarizes the net income (loss) attributable to The AES Corporation and transfers (to) from noncontrolling interests for the years ended December 31, 2012 and 2011:
17. SEGMENT AND GEOGRAPHIC INFORMATION
During the fourth quarter of 2012, the Company completed the restructuring of its operational management and reporting process. The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally with further aggregation by geographic regions to provide better socio-political-economic understanding of our business. The management reporting structure is organized along six strategic business units (“SBUs”) - led by our Chief Operating Officer (“COO”), who in turn reports to our Chief Executive Officer (“CEO”). Upon the application of the accounting guidance for segment reporting, the Company has identified eight reportable segments based on the six strategic business units. All prior period results have been retrospectively revised to reflect the new segment reporting structure which includes:
•
US-Generation;
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
•
US-Utilities;
•
Andes-Generation;
•
Brazil-Generation;
•
Brazil-Utilities;
•
MCAC-Generation;
•
EMEA-Generation;
•
Asia-Generation
Corporate and Other-The Company’s EMEA and MCAC Utilities operating segments are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under the segment reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting; therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue or adjusted PTC. “Corporate and Other” also includes corporate overhead costs which are not directly associated with the operations of our eight reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.
During the fourth quarter 2012, the Company changed its primary segment performance measure from adjusted gross margin to adjusted pre-tax contribution (“Adjusted PTC”). Adjusted PTC, a non-GAAP measure, is defined by the Company as pre-tax income from continuing operations attributable to AES excluding unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, significant gains or losses due to dispositions and acquisitions of business interests, significant losses due to impairments and costs due to the early retirement of debt. The Company has concluded that Adjusted PTC best reflects the underlying business performance of the Company and is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and complexity, the Company has also concluded that Adjusted PTC is a more transparent measure that better assists the investor in determining which businesses have the greatest impact on the overall Company results.
Total revenue includes inter-segment revenue related to the transfer of electricity from generation plants to utilities within Brazil. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self-insurance activities which are reflected within segment adjusted PTC. All intra-segment activity has been eliminated with respect to revenue and adjusted PTC within the segment. Inter-segment activity has been eliminated within the total consolidated results. Asset information for businesses that were discontinued or classified as held for sale as of December 31, 2012 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The tables below present the breakdown of reportable segment balance sheet and income statement data as of and for the years ended December 31, 2012 through 2010:
(1) Adjusted pre-tax contribution in each segment before intersegment eliminations includes the effect of intercompany transactions with other segments except for interest and charges for certain management fees.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The table below presents information, by country, about the Company’s consolidated operations for each of the years ended December 31, 2012 through 2010 and as of December 31, 2012 and 2011, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
(1) Excludes revenue of $39 million, $374 million and $662 million for the years ended December 31, 2012, 2011 and 2010, respectively, and property, plant and equipment of $619 million as of December 31, 2011, related to Eastern Energy, Thames, Ironwood, and Red Oak which were reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets. Additionally property, plant and equipment excludes $25 million and $45 million as of December 31, 2012 and 2011, respectively, related to wind turbines which were reflected as assets held for sale in the accompanying Consolidated Balance Sheets.
(2)
Excludes revenue of $124 million and $118 million for the years ended December 31, 2011 and 2010, respectively, related to Brazil Telecom, which was reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
(3)
Excludes revenue of $102 million and $116 million for the years ended December 31, 2011 and 2010, respectively, related to our Argentina distribution businesses, which were reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(4)
Excludes revenue of $5 million, $17 million and $21 million for the years ended December 31, 2012, 2011 and 2010, respectively, related to carbon reduction projects, which were reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(5)
Our wind project in Bulgaria started operations in 2010 and Maritza started operations in June 2011.
(6)
Excludes property, plant and equipment of $620 million as of December 31, 2011, related to Cartagena, which was reflected as assets held for sale in the accompanying Consolidated Balance Sheet.
(7)
Excludes revenue of $18 million, $219 million and $287 million for the years ended December 31, 2012, 2011 and 2010, respectively, and property, plant and equipment of $5 million as of December 31, 2011, related to Borsod, Tiszapalkonya and Tisza II, which were reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
(8)
Excludes revenue of $129 million for the year ended December 31, 2010, related to Ras Laffan, which was reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(9) Excludes revenue of $299 million for the year ended December 31, 2010, related to Lal Pir and Pak Gen, which were reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(10) Excludes revenue of $62 million for the year ended December 31, 2010, related to Barka, which was reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(11)
Excludes revenue of $1 million for each of the years ended December 31, 2012 and 2011, related to alternative energy and carbon reduction projects, which were reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
18. SHARE-BASED COMPENSATION
STOCK OPTIONS-AES grants options to purchase shares of common stock under stock option plans to employees and non-employee directors. Under the terms of the plans, the Company may issue options to purchase shares of the Company’s common stock at a price equal to 100% of the market price at the date the option is granted. Stock options are generally granted based upon a percentage of an employee’s base salary. Stock options issued under these plans in 2012, 2011 and 2010 have a three-year vesting schedule and vest in one-third increments over the three-year period. The stock options have a contractual term of ten years. At December 31, 2012, approximately 16 million shares were remaining for award under the plans. In all circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock option in cash or other assets of AES.
The following table presents the weighted average fair value of each option grant and the underlying weighted average assumptions, as of the grant date, using the Black-Scholes option-pricing model:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The Company exclusively relies on implied volatility as the expected volatility to determine the fair value using the Black-Scholes option-pricing model. The implied volatility may be exclusively relied upon due to the following factors:
•
The Company utilizes a valuation model that is based on a constant volatility assumption to value its employee share options;
•
The implied volatility is derived from options to purchase AES common stock that are actively traded;
•
The market prices of both the traded options and the underlying shares are measured at a similar point in time and on a date reasonably close to the grant date of the employee share options;
•
The traded options have exercise prices that are both near-the-money and close to the exercise price of the employee share options; and
•
The remaining maturities of the traded options on which the estimate is based are at least one year.
The Company uses a simplified method to determine the expected term based on the average of the original contractual term and the pro rata vesting period. This simplified method is used for stock options granted during 2012, 2011 and 2010. This is appropriate given a lack of relevant stock option exercise data. This simplified method may be used as the Company’s stock options have the following characteristics:
•
The stock options are granted at-the-money;
•
Exercisability is conditional only on performing service through the vesting date;
•
If an employee terminates service prior to vesting, the employee forfeits the stock options;
•
If an employee terminates service after vesting, the employee has a limited time to exercise the stock option; and
•
The stock option is nonhedgeable and not transferable.
The Company does not discount the grant date fair values to estimate post-vesting restrictions. Post-vesting restrictions include black-out periods when the employee is not able to exercise stock options based on their potential knowledge of information prior to the release of that information to the public.
The following table summarizes the components of stock-based compensation related to employee stock options recognized in the Company’s financial statements:
No cash was used to settle stock options or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2012, 2011 and 2010. As of December 31, 2012, $3 million of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted average period of 1.8 years.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
A summary of the option activity for the year ended December 31, 2012 follows (number of options in thousands, dollars in millions except per option amounts):
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company’s closing stock price on the last trading day of 2012 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2012. The amount of the aggregate intrinsic value will change based on the fair market value of the Company’s stock.
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2012, AES has estimated a weighted average forfeiture rate of 13.66% for stock options granted in 2012. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $3 million on a straight-line basis over a three year period (approximately $1 million per year) related to stock options granted during the year ended December 31, 2012.
RESTRICTED STOCK
Restricted Stock Units-The Company issues restricted stock units (“RSUs”) under its long-term compensation plan. The RSUs are generally granted based upon a percentage of the participant’s base salary. The units have a three-year vesting schedule and vest in one-third increments over the three-year period. Units granted prior to 2011 are required to be held for an additional two years before they can be converted into shares, and thus become transferable. There is no such requirement for units granted in 2011 and afterwards. In all circumstances, restricted stock units granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unit in cash or other assets of AES.
For the years ended December 31, 2012, 2011, and 2010, RSUs issued had a grant date fair value equal to the closing price of the Company’s stock on the grant date. The Company does not discount the grant date fair values to reflect any post-vesting restrictions. RSUs granted to employees during the years ended December 31, 2012, 2011, and 2010 had grant date fair values per RSU of $13.54, $12.65 and $12.18, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes the components of the Company’s stock-based compensation related to its employee RSUs recognized in the Company’s consolidated financial statements:
(1) Amount represents fair market value on the date of conversion.
There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2012, 2011 and 2010. As of December 31, 2012, $14 million of total unrecognized compensation cost related to RSUs is expected to be recognized over a weighted average period of approximately 1.8 years. There were no modifications to RSU awards during the year ended December 31, 2012.
A summary of the activity of RSUs for the year ended December 31, 2012 follows (number of RSUs in thousands):
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2012, AES has estimated a weighted average forfeiture rate of 18.82% for RSUs granted in 2012. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $14 million on a straight-line basis over a three year period related to RSUs granted during the year ended December 31, 2012.
The table below summarizes the RSUs that vested and were converted during the years ended December 31, 2012, 2011 and 2010 (number of RSUs in thousands):
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Performance Stock Units-The Company issues performance stock units (“PSUs”) to officers under its long-term compensation plan. PSUs are restricted stock units of which 50% of the units awarded include a market condition and the remaining 50% include a performance condition. Vesting will occur if the applicable continued employment conditions are satisfied and (a) for the units subject to the market condition the Total Stockholder Return (“TSR”) on AES common stock exceeds the TSR of the Standard and Poor’s 500 Utilities Sector Index over the three-year measurement period beginning on January 1st of the grant year and ending on December 31st of the third year and (b) for the units subject to the performance condition if the Company’s actual Adjusted EBITDA meets the performance target over the three-year measurement period beginning on January 1, 2012 and ending on December 31, 2014. The market and performance condition determines the vesting and final share equivalent per PSU and can result in earning an award payout range of 0% to 200%, depending on the achievement. In all circumstances, PSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unit in cash or other assets of AES.
The effect of the market condition on PSUs issued to officers of the Company during 2012 is reflected in the award’s fair value on the grant date. The results of the valuation estimated the fair value at $19.75 per share, equating to 144% of the Company’s closing stock price on the date of grant. PSUs that included a market condition granted during the year ended December 31, 2012, 2011 and 2010 had a grant date fair value per RSU of $19.75, $17.68 and $11.57, respectively. The fair value of the PSUs with a performance condition had a grant date fair value of $13.70 equal to the closing price of the Company’s stock on the grant date. The Company believes that it is probable that the performance condition will be met; this will continue to be evaluated throughout the performance period. If the fair value of the market condition was not applied to PSUs issued to officers, the total grant date fair value of PSUs granted during the year ended December 31, 2012 would have decreased by $2 million.
Restricted stock units with a market condition were awarded to officers of the Company prior to 2011 contained only the market condition measuring the TSR on AES common stock. These units were required to be held for an additional two years subsequent to vesting before they could be converted into shares and become transferable. There is no such requirement for the shares granted during 2011 and afterwards.
The following table summarizes the components of the Company’s stock-based compensation related to its PSUs recognized in the Company’s consolidated financial statements:
(1) Amount represents fair market value on the date of conversion.
There was no cash used to settle PSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2012, 2011 and 2010. As of December 31, 2012, $6 million of total unrecognized compensation cost related to PSUs is expected to be recognized over a weighted average period of approximately 1.9 years. There were no modifications to PSU awards during the year ended December 31, 2012.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
A summary of the activity of PSUs for the year ended December 31, 2012 follows (number of PSUs in thousands):
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2012, AES has estimated a forfeiture rate of 13.81% for PSUs granted in 2012. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $8 million on a straight-line basis over a three year period (approximately $2.7 million per year) related to PSUs granted during the year ended December 31, 2012.
The table below summarizes the PSUs that vested and were converted during the years ended 2012, 2011 and 2010 (number of PSUs in thousands):
19. CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES
Our subsidiaries IPL and DPL had outstanding shares of cumulative preferred stock of $78 million at December 31, 2012 and 2011.
IPL had $60 million of cumulative preferred stock outstanding at December 31, 2012 and 2011, which represented five series of preferred stock. The total annual dividend requirements were approximately $3 million at December 31, 2012 and 2011. Certain series of the preferred stock were redeemable solely at the option of the issuer at prices between $100 and $118 per share. Holders of the preferred stock are entitled to elect a majority of IPL’s board of directors if IPL has not paid dividends to its preferred stockholders for four consecutive quarters. Based on the preferred stockholders’ ability to elect a majority of IPL’s board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock is considered temporary equity and presented in the mezzanine level of the Consolidated Balance Sheets in accordance with the relevant accounting guidance for noncontrolling interests and redeemable securities.
DPL had $18 million of cumulative preferred stock outstanding at December 31, 2012, which represented three series of preferred stock issued by DP&L, a wholly owned subsidiary of DPL. The total annual dividend
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
requirements were approximately $1 million at December 31, 2012. The DP&L preferred stock may be redeemed at DP&L’s option as determined by its board of directors at per-share redemption prices between $101 and $103 per share, plus cumulative preferred dividends. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the DP&L Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Based on the preferred stockholders’ ability to elect members of DP&L’s board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock is considered temporary equity and presented in the mezzanine level of the Consolidated Balance Sheets in accordance with the relevant accounting guidance for noncontrolling interests and redeemable securities.
20. OTHER INCOME AND EXPENSE
Other Income
Other income generally includes gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies, and other income from miscellaneous transactions. The components of other income are summarized as follows:
Other income of $105 million for the year ended December 31, 2012 included the receipt of insurance proceeds related to a claim in Panama for damage associated with the Esti tunnel, the release of a reserve recorded against inventory at Ballylumford and the receipt of dividends from a cost method investment at Gener. Other income also includes the sale of land adjacent to Deepwater and the associated water permits, water right sales at Gener and the gain on sale of assets at Eletropaulo.
Other income of $149 million for the year ended December 31, 2011 included a tax credit settlement from a favorable court decision in 2011 concerning reimbursement of excess non-income taxes paid from 1989 to 1992 at Eletropaulo and the reimbursement of income tax expense recognized related to an indemnity agreement between Los Mina and the Dominican Republic government. Other income also includes the gain on the sale of assets at Gener and Eletropaulo, the sale of Huntington Beach units 3 & 4 at Southland, the sale of land and minerals rights at IPL and insurance proceeds related to the claim in Panama that is described above.
Other income of $100 million for the year ended December 31, 2010 included the extinguishment of a swap liability owed by two of our Brazilian subsidiaries, resulting in the recognition of a $62 million gain. The net impact to the Company after taxes and non-controlling interest was $9 million. Other income also included a gain on sale of assets at Eletropaulo.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Other Expense
Other expense generally includes losses on asset sales, losses on extinguishment of debt, legal contingencies and losses from other miscellaneous transactions. The components of other expense are summarized as follows:
Other expense of $93 million for the year ended December 31, 2012 was primarily due to losses on the disposal of assets mainly at Eletropaulo and losses related to the early retirement of debt at the Parent Company and at Eletropaulo. Additionally, other expense included a tax penalty at Chivor and a reduction in the 2011 receivable expected from the indemnity agreement described above in other income at Los Mina.
Other expense of $153 million for the year ended December 31, 2011 included $68 million related to the loss on disposal of assets mainly at Eletropaulo and TermoAndes, $36 million related to the premium paid on early retirement of debt at Gener and $15 million related to the early retirement of senior notes due in 2011 at IPL.
Other expense of $232 million for the year ended December 31, 2010 included losses on disposal of assets totaling $84 million, mainly at Eletropaulo, Panama, and Gener, an $18 million loss on debt extinguishment at Andres and Itabo, and a $15 million loss at the Parent Company from the retirement of senior notes. Additionally, other expense included $72 million for a settlement agreement of gas transportation contracts at Gener as well as previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a non-controlling interest in our Wind generation business, which were written off upon the expiration of the letter of intent on June 30, 2010.
21. ASSET IMPAIRMENT EXPENSE
Asset impairment expense for the years ended December 31, 2012, 2011, and 2010 consisted of:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Wind Turbines and Projects- During the third quarter of 2012, the Company determined that all wind turbines held in storage met the held-for-sale criteria due to the ongoing receipt of offers from potential buyers and less viable internal deployment scenarios. Accordingly, the Company measured the turbines at fair value less cost to sell under the market approach. The turbines with a carrying amount of $45 million were written down to their fair value less cost to sell of $25 million, which resulted in an impairment expense of $20 million. These turbines continue to meet the held-for-sale criteria as of December 31, 2012. The turbines were previously evaluated for impairment in the third quarter of 2011 due to a reduction in wind turbine market pricing and advances in turbine technology. At that time, the Company had also concluded that it was more likely than not that certain non-refundable deposits it had made in prior years to a turbine manufacturer for the purchase of wind turbines were not recoverable due to the availability of more advanced and lower cost turbines in the market. As a result, the Company had recognized asset impairment expense of $116 million related to these turbines and deposits in the third quarter of 2011.
During 2012, the Company also determined that two early-stage wind development projects that were capitalizing certain project costs were no longer probable because of the Company’s shift in capital allocation for developing these projects. The Company assessed the value of the projects using the market approach and, after consultation with third party valuation firms and internal development staff, the fair value was determined to be zero. Asset impairment expense of $21 million was recognized during 2012 for these wind development projects. These wind turbines and projects are reported in the US Generation segment.
Kelanitissa-We continue to evaluate the recoverability of our long-lived assets at Kelanitissa, our diesel-fired generation plant in Sri Lanka, as a result of both the requirement to transfer the plant to the government at the end of our PPA and the expectation of lower future operating cash flows. During 2012, the Company recognized asset impairment expense of $19 million for the long-lived assets of Kelanitissa. Our evaluations during this period indicated that the long-lived assets were no longer recoverable and, accordingly, were written down to their estimated fair value of $10 million based on a discounted cash flow analysis. The long-lived assets had a carrying amount of $29 million prior to the recognition of asset impairment expense. Kelanitissa was previously evaluated for impairment in 2011 due to the reasons described above. These evaluations resulted in asset impairment expense of $42 million during the year ended December 31, 2011. Kelanitissa is reported in the Asia Generation segment.
St. Patrick-During the second quarter of 2012, the Company received approval from its Board of Directors for the sale of its wholly-owned subsidiary Ferme Eolienne Saint Patrick SAS (“St. Patrick”). Upon meeting the held for sale criteria long-lived assets with a carrying amount of $33 million were written down to their fair value of $22 million and an impairment expense of $11 million was recorded. The sale transaction subsequently closed on June 28, 2012. St. Patrick is reported in the EMEA generation segment.
Southland-In September 2010, a new environmental policy on the use of ocean water to cool generation facilities was issued in California that requires generation plants to comply with the policy by December 31, 2020 and would require significant capital expenditure or plants’ shutdown. The Company’s Huntington Beach gas-fired generation facility in California, which is part of AES’ Southland business, was impacted by the new policy. The Company performed an asset impairment test and determined the fair value of the asset group using a discounted cash flow analysis. The carrying value of the asset group of $288 million exceeded the fair value of $88 million resulting in the recognition of asset impairment expense of $200 million for the year ended December 31, 2010. Southland is reported in the US Generation segment.
Deepwater-In 2010, Deepwater, our 160 MW petcoke-fired merchant power plant located in Texas, experienced deteriorating market conditions due to increasing petcoke prices and diminishing power prices. As a
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
result, Deepwater incurred operating losses and was shut down from time to time to avoid negative operating margin. In the fourth quarter of 2010, management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was no longer recoverable. The fair value of Deepwater was determined using a discounted cash flow analysis and $79 million of impairment expense was recognized. Deepwater is reported in the US Generation segment.
22. INCOME TAXES
Income Tax Provision
The following table summarizes the expense for income taxes on continuing operations, for the years ended December 31, 2012, 2011 and 2010:
Effective and Statutory Rate Reconciliation
The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to the Company’s effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2012, 2011 and 2010:
The current income taxes receivable and payable are included in Other Current Assets and Accrued and Other Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The noncurrent income taxes
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
receivable and payable are included in Other Noncurrent Assets and Other Noncurrent Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The following table summarizes the income taxes receivable and payable as of December 31, 2012 and 2011:
Deferred Income Taxes-Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss and tax credit carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.
As of December 31, 2012, the Company had federal net operating loss carryforwards for tax purposes of approximately $2.2 billion expiring in years 2023 to 2032. Approximately $76 million of the net operating loss carryforward related to stock option deductions will be recognized in additional paid-in capital when realized. The Company also had federal general business tax credit carryforwards of approximately $18 million expiring primarily from 2020 to 2032, and federal alternative minimum tax credits of approximately $5 million that carry forward without expiration. The Company had state net operating loss carryforwards as of December 31, 2012 of approximately $5.8 billion expiring in years 2016 to 2032. As of December 31, 2012, the Company had foreign net operating loss carryforwards of approximately $3.3 billion that expire at various times beginning in 2013 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $23 million, $1 million of which expire in 2013 to 2015, $3 million of which expire in 2016 to 2023 and $19 million of which carryforward without expiration.
Valuation allowances increased $5 million during 2012 to $0.9 billion at December 31, 2012. This net increase was primarily the result of valuation allowance activity at certain U.S. state jurisdictions.
Valuation allowances decreased $376 million during 2011 to $0.9 billion at December 31, 2011. This net decrease was primarily the result of the release of a valuation allowance against certain foreign operating loss carryforwards which were written off in 2011 and a release of a valuation allowance at one of our Brazilian subsidiaries.
The Company believes that it is more likely than not that the net deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income. The Company continues to monitor the utilization of its deferred tax asset for its U.S. consolidated net operating loss carryforward. Although management believes it is more likely than not that this deferred tax asset will be realized through generation of sufficient taxable income prior to expiration of the loss carryforwards, such realization is not assured.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following table summarizes the deferred tax assets and liabilities, as of December 31, 2012 and 2011:
The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings in accordance with the relevant accounting guidance for income taxes. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.
Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The Company’s income tax benefits related to the tax status of these operations are estimated to be $81 million, $60 million and $60 million for the years ended December 31, 2012, 2011 and 2010, respectively. The per share effect of these benefits after noncontrolling interests was $0.10, $0.07 and $0.07 for the year ended December 31, 2012, 2011 and 2010, respectively.
The following table summarizes the income (loss) from continuing operations, before income taxes, net equity in earnings of affiliates and noncontrolling interests, for the years ended December 31, 2012, 2011 and 2010:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Uncertain Tax Positions
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid in one year. The Company’s policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
As of December 31, 2012 and 2011, the total amount of gross accrued income tax related interest included in the Consolidated Balance Sheets was $18 million and $15 million, respectively. The total amount of gross accrued income tax related penalties included in the Consolidated Balance Sheets as of December 31, 2012 and 2011 was $4 million and $4 million, respectively.
The total expense (benefit) for interest related to unrecognized tax benefits for the years ended December 31, 2012, 2011 and 2010 amounted to $3 million, $3 million and $(10) million, respectively. For the years ended December 31, 2012, 2011 and 2010, the total expense (benefit) for penalties related to unrecognized tax benefits amounted to $1 million, $0 million and $(1) million, respectively.
We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitations expires. Tax audits by their nature are often complex and can require several years to complete. The following is a summary of tax years potentially subject to examination in the significant tax and business jurisdictions in which we operate:
As of December 31, 2012, 2011 and 2010, the total amount of unrecognized tax benefits was $481 million, $471 million and $437 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2012, 2011 and 2010 is $450 million, $424 million and $412 million, respectively, of which $45 million, $47 million and $51 million, respectively, would be in the form of tax attributes that would warrant a full valuation allowance.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2012 is estimated to be between $90 million and $110 million.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2012, 2011 and 2010:
The Company and certain of its subsidiaries are currently under examination by the relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the amount of unrecognized tax benefit recorded. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe we have appropriately accrued for our uncertain tax benefits. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits and the range of anticipated increases or decreases in unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of current or future examinations may exceed our provision for current unrecognized tax benefits in amounts that could be material, but cannot be estimated as of December 31, 2012. Our effective tax rate and net income in any given future period could therefore be materially impacted.
23. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES
Discontinued operations include the results of the following businesses:
•
Tisza II (sold in December 2012);
•
Red Oak and Ironwood (sold in April 2012);
•
Argentina distribution businesses (sold in November 2011);
•
Eletropaulo Telecomunicacões Ltda. and AES Communications Rio de Janeiro S.A. (collectively, “Brazil Telecom”), our Brazil telecommunication businesses (sold in October 2011);
•
Carbon reduction projects (held for sale in December 2011);
•
Wind projects (abandoned in December 2011);
•
Eastern Energy in New York (held for sale in March 2011);
•
Borsod in Hungary (held for sale in March 2011);
•
Thames in Connecticut (disposed of in December 2011);
•
Barka in Oman (sold in August 2010);
•
Lal Pir and Pak Gen in Pakistan (sold in June 2010); and
•
Ras Laffan in Qatar (sold in October 2010).
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Information for businesses included in discontinued operations and the income (loss) on disposal and impairment of discontinued operations for the years ended December 31, 2012, 2011 and 2010 is provided in the tables below:
Gain (Loss) on Disposal of Discontinued Businesses
Tisza II-In December 2012, the Company completed the sale of its 100% ownership interest in Tisza II, a 900 MW gas/oil fired plant in Hungary. Net proceeds from the sale transaction were $14 million and the Company recognized a loss on disposal of $87 million, net of tax (including the realization of cumulative foreign currency translation loss of $73 million). In 2011 and 2010, the long-lived asset group of Tisza II was evaluated for impairment due to deteriorating economic and business conditions in Hungary, and was determined to be unrecoverable based on undiscounted cash flows. As a result, the Company had measured the asset group at fair value using discounted cash flows analysis and recognized asset impairment expense of $52 million and $85 million in 2011 and 2010, respectively, which is included in loss from operations of discontinued businesses above. Tisza II was reported in EMEA Generation segment.
Red Oak and Ironwood-In April 2012, the Company completed the sale of its 100%% interest in Red Oak, an 832 MW coal-fired plant in New Jersey, and Ironwood, a 710 MW coal-fired plant in Pennsylvania, for $228 million and recognized a gain of $73 million, net of tax. Both Red Oak and Ironwood were reported in the US Generation segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Argentina distribution businesses-On November 17, 2011, the Company completed the sale of its 90% equity interest in Edelap and Edes, two distribution companies in Argentina serving approximately 329,000 and 172,000 customers, respectively, and its 51% equity interest in Central Dique, a 68 MW gas and diesel generation plant (collectively, “Argentina distribution businesses”) in Argentina. Net proceeds from the sale were approximately $4 million. The Company recognized a loss on disposal of $338 million, net of tax (including the realization of cumulative foreign currency translation loss of $208 million). These businesses were previously reported in “Corporate and Other”.
Brazil Telecom-In October 2011, a subsidiary of the Company completed the sale of its ownership interest in two telecommunication companies in Brazil. The Company held approximately 46% ownership interest in these companies through the subsidiary. The subsidiary received net proceeds of approximately $893 million. The gain on sale was approximately $446 million, net of tax. These businesses were previously reported in the Brazil Utilities segment.
Carbon reduction projects-In December 2011, the Company’s board of directors approved plans to sell its 100% equity interests in its carbon reduction businesses in Asia and Latin America. The aggregate carrying amount of $49 million of these projects was written down as their estimated fair value was considered zero, resulting in a pre-tax impairment expense of $40 million, which is included in income from operations of discontinued businesses. The impairment expense recognized was limited to the carrying amounts of the individual assets within the asset group, where the fair value was greater than the carrying amount. When the disposal group met the held for sale criteria, the disposal group was measured at the lower of carrying amount or fair value less cost to sell. Carbon reduction projects were previously reported in “Corporate and Other”.
Wind projects-In the fourth quarter of 2011, the Company determined that it would no longer pursue certain development projects in Poland and the United Kingdom due to revisions in its growth strategy. As a result, the Company abandoned these projects and recognized the related project development rights, which were previously included in intangible assets, as a loss on disposal of discontinued operations of $22 million, net of tax. These wind projects were previously reported in EMEA generation reportable segment.
Eastern Energy-In March 2011, AES Eastern Energy (“AEE”) met the held for sale criteria and was reclassified from continuing operations to held for sale. AEE operated four coal-fired power plants: Cayuga, Greenidge, Somerset and Westover, representing generation capacity of 1,169 MW in the western New York power market. In 2010, AEE had recognized a pre-tax impairment expense of $827 million due to adverse market conditions. In December 2011, AEE along with certain of its affiliates filed for bankruptcy protection and was recorded as a cost method investment. In December 2012, the AEE bankruptcy proceedings were finalized and a gain of $30 million, net of tax, was recognized in gain on disposal of discontinued businesses. AEE was previously reported in the US Generation segment.
Borsod-In March 2011, Borsod, which holds two coal/biomass-fired generation plants in Hungary with generating capacity of 161 MW, met the held for sale criteria and was reclassified from continuing operations to held for sale. In November 2011, Borsod filed for liquidation and was recorded as a cost method investment. Borsod was previously reported in the EMEA Generation reportable segment.
Thames-In December 2011, Thames, a 208 MW coal-fired plant in Connecticut, met the discontinued operations criteria and its operating results were retrospectively reflected as discontinued operations. Thames had filed for liquidation in February 2011, and was recorded as a cost method investment with the historical operating results reflected in discontinued operations. Thames was previously reported in the US Generation reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Barka-On August 19, 2010, the Company completed the sale of its 35% ownership interest in Barka, a 456 MW combined cycle gas facility and water desalination plant in Oman, and its 100% interest in two Barka related service companies. Total consideration received in the transaction was approximately $170 million, of which $124 million was AES’ portion. The Company recognized a gain on disposal of $80 million, net of tax, during the year ended December 31, 2010. Barka was previously reported in the Asia Generation reportable segment.
Lal Pir and Pak Gen-On June 11, 2010, the Company completed the sale of its 55% ownership in Lal Pir and Pak Gen, two oil-fired facilities in Pakistan with respective generation capacities of 362 MW and 365 MW. Total consideration received in the transaction was approximately $117 million, of which $65 million was AES’ portion. The Company recognized a loss on disposal of $22 million, net of tax, during the year ended December 31, 2010. These businesses were previously reported in the Asia Generation reportable segment.
Ras Laffan-On October 20, 2010, the Company completed the sale of its 55% equity interest in Ras Laffan, a 756 MW combined cycle gas plant and a water desalination facility in Qatar, and the associated operations company for aggregate proceeds of approximately $234 million. The Company recognized a gain on disposal of $6 million, net of tax, during the year ended December 31, 2010. Ras Laffan was previously reported in the Asia Generation reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
24. ACQUISITIONS AND DISPOSITIONS
Acquisitions
DPL-On November 28, 2011, AES completed the acquisition of 100% of the common stock of DPL Inc. (“DPL”), the parent company of The Dayton Power and Light Company (“DP&L”), a utility based in Ohio, for approximately $3.5 billion, pursuant to the terms and conditions of a definitive agreement (the “Merger Agreement”) dated April 19, 2011. Upon completion of the acquisition, DPL became a wholly owned subsidiary of AES. DPL’s operating results for the period beginning November 28, 2011 have been included in the Consolidated Statement of Operations with no comparable amounts for 2010. DPL’s net assets acquired and liabilities assumed in the acquisition have been included in the Consolidated Balance Sheet as of December 31, 2011. The purchase price allocation was finalized in the third quarter of 2012 and the resulting adjustments to the preliminary purchase price allocation (recorded as of the acquisition date) have been retrospectively reflected as of December 31, 2011 in the accompanying Consolidated Balance Sheet. The effect of these adjustments on net income for the period November 28, 2011 through December 31, 2011 was not material. The preliminary purchase allocation, the measurement period adjustments, and the final purchase price allocation are presented in the table below:
(1) Represents net adjustments resulting from the refined information associated with certain contractual arrangements, growth and ancillary revenue assumptions. There was a related decrease of $25 million in the provisionally recognized deferred tax liabilities.
(2) Represents net adjustments to certain customer contracts of DPLER and other intangible assets resulting from the refined market and contractual information obtained during the measurement period. There was a related decrease of $7 million in the provisionally recognized deferred tax liabilities.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
(3) Represents net adjustments resulting from an assessment of overall deferred tax liabilities on regulated property, plant and equipment. There was a related increase of $21 million in the provisionally recognized deferred tax liabilities.
(4) Represents the net impact of adjustments to the purchase price allocation recognized during the measurement period, including a decrease of $12 million related to the unfavorable coal contract and an increase of $16 million as a result of the finalization of DPL Inc.’s standalone federal tax return.
(5) Primarily represents an increase of $29 million related to an unfavorable coal contract partially offset by a decrease of $13 million in income taxes payable as a result of the finalization of DPL Inc.’s standalone federal tax return.
(6) Represents the net impact of purchase price adjustments on goodwill during the measurement period.
Dispositions
Cartagena-On February 9, 2012, a subsidiary of the Company completed the sale of 80% of its interest in the wholly-owned holding company of AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain. The Company owned approximately 70.81% of AES Cartagena through this holding company structure, as well as 100% of a related operations and maintenance company. Net proceeds from the sale were approximately 172 million ($229 million) and during the first quarter of 2012, the Company recognized a pretax gain of $178 million on the transaction.
Under the terms of the sale agreement, the buyer, Electrabel International Holdings B.V. (“Electrabel”), a subsidiary of GDF SUEZ S.A. or “GDFS”, has an option to purchase the Company’s remaining 20% interest at a fixed price of 28 million ($37 million) during a five month period beginning March 2013. Of the total proceeds received, approximately $9 million was deferred and allocated to Electrabel’s option to purchase the Company’s remaining interest. In the fourth quarter of 2012, the Company received $9 million in dividends from its 20% ownership of AES Cartagena, of which $5 million was deferred and allocated to Electrabel’s option to purchase the Company’s remaining interest. Concurrent with the sale, GDFS settled the outstanding arbitration between the parties regarding certain emissions costs and other taxes that AES Cartagena sought to recover from GDFS as energy manager under the existing commercial arrangements. GDFS agreed to pay 71 million ($95 million) to AES Cartagena for such costs incurred by AES Cartagena for the 2008-2010 period and for 2011 through the date of sale close, of which 28 million ($38 million) was paid at closing. Due to the Company’s expected continuing ownership interest extending beyond one year from the completion of the sale of its 80% interest, the prior period operating results of AES Cartagena have not been reclassified as discontinued operations.
InnoVent and St. Patrick-On June 28, 2012, the Company closed the sale of its equity interest in InnoVent and controlling interest in St. Patrick. Net proceeds from the sale transactions were $42 million. The prior period operating results of St. Patrick were not deemed material for reclassification to discontinued operations. See Note 21-Impairment Expense and Note 9-Other Non-Operating Expense for further information.
China-On September 6, 2012 and December 31, 2012, the Company completed the sale of its interest in equity method investments in China. These investments included coal-fired, hydropower and wind generation facilities accounted for under the equity method of accounting. Net proceeds from the sale were approximately $133 million and the Company recognized a pretax gain of $27 million on the transaction, which is reflected as a gain on sale of investment. See Note 9-Other Non-Operating Expense for further information.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
25. EARNINGS PER SHARE
Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.
The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income from continuing operations. In the table below, income represents the numerator (in millions) and shares represent the denominator (in millions):
The calculation of diluted earnings per share excluded 7, 6 and 17 million options outstanding at December 31, 2012, 2011 and 2010, respectively, that could potentially dilute basic earnings per share in the future. These options were not included in the computation of diluted earnings per share because their exercise price exceeded the average market price during the related period.
The calculation of diluted earnings per share also excluded 1 million options outstanding at December 31, 2012, that could potentially dilute earnings per share in the future. These options were not included in the computation of diluted earnings per share for the year ended December 31, 2012 because their inclusion would be anti-dilutive given the loss from continuing operations in the period. Had the Company generated income from continuing operations in the year ended December 31, 2012, 1 million of potential common shares of common stock related to the options would have been included in diluted average shares outstanding.
The calculation of diluted earnings per share also excluded 1 million restricted stock units outstanding at December 31, 2012, that could potentially dilute basic earnings per share in the future. These restricted stock units were not included in the computation of diluted earnings per share because the average amount of compensation cost per share attributed to future service and not yet recognized exceeded the average market price during the related period and thus to include the restricted units would have been anti-dilutive. The calculation of diluted earnings per share also excluded 6 million restricted stock units outstanding at December 31, 2012, that could potentially dilute earnings per share in the future. These restricted units were not included in the computation of diluted earnings per share for the year ended December 31, 2012, because their impact would be anti-dilutive given the loss from continuing operations. Had the Company generated income from continuing operations in the year ended December 31, 2012, 4 million of potential common shares of common stock related to the restricted stock units would have been included in diluted average shares outstanding.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
For the years ended December 31, 2012, 2011 and 2010 all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive.
During the twelve months ended December 31, 2012, 1 million shares of common stock were issued under the Company’s profit sharing plan and 2 million shares of common stock were issued upon the exercise of stock options.
26. RISKS AND UNCERTAINTIES
AES is a global power producer in 28 countries on five continents. See additional discussion of the Company’s principal markets in Note 17-Segment and Geographic Information. Our principal lines of business are Generation and Utilities. The Generation line of business uses a wide range of technologies, including coal, gas, hydroelectric, and biomass as fuel to generate electricity. Our Utilities business is comprised of businesses that transmit, distribute, and in certain circumstances, generate power. In addition, the Company has operations in the renewables area. These efforts include projects primarily in wind and solar.
Operating and Economic Risks-The Company operates in several developing economies where economic downturns could have a significant impact on the overall macroeconomic conditions including the valuation of businesses. Deteriorating market conditions often expose the Company to the risk of decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities and foreign currency spot markets. Additionally, credit markets around the globe continue to tighten their standards, which could impact our ability to finance growth projects through access to capital markets. Currently, the Company has a below-investment grade rating from Standard & Poor’s of BB-. This may limit the ability of the Company to finance new and existing development projects to cash currently available on hand and through reinvestment of earnings. As of December 31, 2012, the Company had $2.0 billion of unrestricted cash and cash equivalents.
During 2012, approximately 79% of our revenue, and 38% of our revenue from discontinued businesses, was generated outside the United States and a significant portion of our international operations is conducted in developing countries. We continue to invest in projects in developing countries because the growth rates and the opportunity to implement operating improvements and achieve higher operating margins may be greater than those typically achievable in more developed countries. International operations, particularly the operation, financing and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:
•
economic, social and political instability in any particular country or region;
•
inability to economically hedge energy prices;
•
volatility in commodity prices;
•
adverse changes in currency exchange rates;
•
government restrictions on converting currencies or repatriating funds;
•
unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies;
•
high inflation and monetary fluctuations;
•
restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;
•
threatened or consummated expropriation or nationalization of our assets by foreign governments;
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
•
unwillingness of governments, government agencies, similar organizations or other counterparties to honor their commitments;
•
unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties, against such counterparties, whether such counterparties are governments or private parties;
•
inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;
•
adverse changes in government tax policy;
•
difficulties in enforcing our contractual rights or enforcing judgments or obtaining a just result in local jurisdictions; and
•
potentially adverse tax consequences of operating in multiple jurisdictions.
Any of these factors, individually or in combination with others, could materially and adversely affect our business, results of operations and financial condition. In addition, our Latin American operations experience volatility in revenue and earnings which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability, indexation of certain PPAs to fuel prices, and currency fluctuations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.
Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any inability to obtain reasonable increases in tariffs or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet publicly announced projections or analysts’ expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our Utilities businesses where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:
•
changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs;
•
changes in the definition or determination of controllable or noncontrollable costs;
•
adverse changes in tax law;
•
changes in the definition of events which may or may not qualify as changes in economic equilibrium;
•
changes in the timing of tariff increases;
•
other changes in the regulatory determinations under the relevant concessions; or
•
changes in environmental regulations, including regulations relating to GHG emissions in any of our businesses.
Any of the above events may result in lower margins for the affected businesses, which can adversely affect our results of operations.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
Foreign Currency Risks-AES operates businesses in many foreign countries and such operations may be impacted by significant fluctuations in foreign currency exchange rates. The Company’s financial position and results of operations have been significantly affected by fluctuations in the value of the Brazilian real, the Argentine peso, the Dominican Republic peso, the Euro, the Chilean peso, the Colombian peso, the Philippine peso, the Kazakhstan Tenge, and the Cameroonian Franc relative to the U.S. Dollar.
Concentrations-The Company does not have any significant concentration of customers and the sources of fuel supply. Although the Company operates in primarily two lines of business, its operations are very diversified geographically. Several of the Company’s generation businesses rely on PPAs with one or a limited number of customers for the majority of, and in some case all of, the relevant business’ output over the term of the PPAs. However, no single customer accounted for 10% or more of total revenue in 2012, 2011 or 2010.
The cash flows and results of operations of our businesses are dependent on the credit quality of their customers and the continued ability of their customers and suppliers to meet their obligations under PPAs and fuel supply agreements. If a substantial portion of the Company’s long-term PPAs and/or fuel supply were modified or terminated, the Company would be adversely affected to the extent that it was unable to replace such contracts at equally favorable terms.
27. RELATED PARTY TRANSACTIONS
Certain of our businesses in Panama, the Dominican Republic, Kazakhstan and Cameroon are partially owned by governments either directly or through state-owned institutions. In the ordinary course of business, these businesses enter into energy purchase and sale transactions, and transmission agreements with other state-owned institutions which are controlled by such governments. At two of our generation businesses in Mexico, the offtakers exercise significant influence, but not control, through representation on these businesses’ Board of Directors. These offtakers are also required to hold a nominal ownership interest in such businesses. In Chile, we provide capacity and energy under contractual arrangements to our investments which are accounted for under the equity method of accounting. Additionally, the Company provides certain support and management services to several of its affiliates under various agreements. The Company’s Consolidated Statements of Operations included the following transactions with related parties for the years indicated:
The following table summarizes the balances receivable from and payable to related parties included in the Company’s Consolidated Balance Sheets as of December 31, 2012 and 2011:
During 2011, the Company sold 19% of its interest in Mong Duong to Stable Investment Corporation, a subsidiary of China Investment Corporation. Terrific Investment Corporation, also a subsidiary of China Investment Corporation, owns approximately 15% of the Company’s outstanding shares of common stock and has representation on the Company’s Board of Directors.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
28. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data
The following tables summarize the unaudited quarterly statements of operations for the Company for 2012 and 2011. Amounts have been restated to reflect discontinued operations in all periods presented and reflect all adjustments necessary in the opinion of management for a fair statement of the results for interim periods.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
(1) Includes pretax impairment expense of $10 million, $18 million, $1.89 billion and $(31) million, for the first, second, third and fourth quarters of 2012, respectively. See Note 21-Impairment Expense and Note 10-Goodwill and Other Intangible Assets for further discussion.
(2) DPL was acquired on November 28, 2011 and its results of operations have been included in AES’ consolidated results of operations from the date of acquisition. See Note 24-Acquisitions and Dispositions for further discussion.
(3) Includes pretax impairment expense of $33 million, $147 million and $10 million, for the second, third and fourth quarters of 2011, respectively. See Note 21-Impairment Expense and Note 10-Goodwill and Other Intangible Assets for further discussion.
29. SUBSEQUENT EVENTS
Beaver Valley PPA termination-On January 1, 2013, Beaver Valley, a wholly-owned 125 MW coal-fired plant in Pennsylvania, entered into an agreement to terminate its PPA with the offtaker in exchange for a lump sum payment of $60 million which was received on January 9, 2013. The termination was effective January 8, 2013. Beaver Valley also terminated its fuel supply agreement. Under the PPA termination agreement, annual capacity agreements between the off-taker and PJM Interconnection, LLC (a regional transmission organization)
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2012, 2011, AND 2010
for 2013-2016 period have been assigned to Beaver Valley. As of December 31, 2012, Beaver Valley had long-lived assets of $47 million, which may incur asset impairment expense in future periods due to the elimination of payments under the terminated PPA.
Masinloc refinancing-On January 23, 2013, Masinloc, a 660 MW coal-fired power plant in the Philippines, completed the refinancing of its $500 million senior debt facility with a consortium of local banks. The refinancing allowed us to improve interest rates, extend the term of the financing and relax certain restrictive covenants. As a result, the Company expects to recognize a loss on extinguishment of debt in the range of $39 million to $43 million in first quarter of 2013 primarily related to prepayment penalties.
Ukraine Utilities sale-On January 29, 2013, the Company agreed to sell its two power distribution businesses in Ukraine to VS Energy International for $113 million subject to customary working capital adjustments. Under the agreement, the Company will sell its 89.1% equity interest in AES Kyivoblenergo, which serves 881,000 customers in the Kiev region, and its 84.6% percent equity interest in AES Rivneoblenergo, which serves 412,000 customers in the Rivne region. As of December 31, 2012, these businesses had a carrying amount of approximately $131 million (including a cumulative foreign currency translation loss of $34 million). The Company expects to recognize an impairment loss in the range of $20 million to $26 million, net of transaction costs, upon meeting the held for sale criteria in the first quarter of 2013. The transaction is expected to close by the second quarter of 2013 and is subject to regulatory approval.
Bulgaria political and economic conditions-In February 2013, following protests over Bulgaria’s electricity prices and other economic issues, the Prime Minister announced plans to reduce electricity tariffs by 8% from March 1, 2013, subject to the approval of the Bulgaria’s State Commission for Energy and Water Regulation. The announcement did not specify how this reduction was to be structured or financed. Following the announcement, the Prime Minister and his government resigned. It is not certain whether the new government will implement the tariff reduction. The ultimate impact of actions by the new government of Bulgaria, if any, are unknown, however it is possible that these developments may result in indicators of impairment of the Company’s long-lived assets in Bulgaria. As of December 31, 2012, the Company had long-lived assets in Bulgaria of $1.8 billion and net equity was approximately $517 million. Revenue and adjusted pre-tax contribution for the year ended December 31, 2012 totaled approximately $369 million and $102 million, respectively.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosures.
The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2012, our disclosure controls and procedures were effective.
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•
provide reasonable assurance that unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements are prevented or detected timely.
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations (“COSO”). Based on this assessment management, believes that the Company maintained effective internal control over financial reporting as of December 31, 2012.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which appears herein.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of The AES Corporation:
We have audited The AES Corporation’s internal control over financial reporting as of December 31, 2012 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The AES Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, The AES Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of The AES Corporation as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012 of The AES Corporation and our report dated February 26, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
McLean, Virginia
February 26, 2013
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following information is incorporated by reference from the Registrant’s Proxy Statement for the Registrant’s 2013 Annual Meeting of Stock Holders which the Registrant expects will be filed on or around March 4, 2013 (the “2013 Proxy Statement”):
•
information regarding the directors required by this item found under the heading Board of Directors;
•
information regarding AES’s Code of Ethics found under the heading AES Code of Business Conduct and Corporate Governance Guidelines;
•
information regarding compliance with Section 16 of the Exchange Act required by this item found under the heading Governance Matters-Section 16(a) Beneficial Ownership Reporting Compliance; and
•
information regarding AES’s Financial Audit Committee found under the heading The Committees of the Board-Financial Audit Committee (the “Audit Committee”).
Certain information regarding executive officers required by this Item is set forth as a supplementary item in Part I hereof (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). The other information required by this Item, to the extent not included above, will be contained in our 2013 Proxy Statement and is herein incorporated by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The following information is contained in the 2013 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the heading Compensation Discussion and Analysis and the Compensation Committee Report on Executive Compensation under the heading Report of the Compensation Committee.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
(a) Security Ownership of Certain Beneficial Owners.
See the information contained under the caption “Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers” of the Proxy Statement for the 2013 Annual Meeting of Shareholders of the Registrant, which information is incorporated herein by reference.
(b) Security Ownership of Directors and Executive Officers.
See the information contained under the caption “Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers” of the Proxy Statement for the 2013 Annual Meeting of Shareholders of the Registrant, which information is incorporated herein by reference.
(c) Changes in Control.
None.
(d) Securities Authorized for Issuance under Equity Compensation Plans.
The following table provides information about shares of AES common stock that may be issued under AES’ equity compensation plans, as of December 31, 2012:
Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2012)
(1) The following equity compensation plans have been approved by the Company’s Stockholders:
(A) The LTC Plan was adopted in 2003 and provided for 17,000,000 shares authorized for issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES’s stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an additional 9,000,000 shares was approved by AES’s stockholders, bringing the total authorized shares to 38,000,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $15.21 (excluding PSU and RSU awards), with 16,245,113 shares available for future issuance.
(B) The AES Corporation 2001 Stock Option Plan adopted in 2001 provided for 15,000,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $3.19. In conjunction with the 2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 5,405,235 shares is not included in Column (c) above.
(C) The AES Corporation 2001 Plan for outside directors adopted in 2001 provided for 2,750,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $11.21. In conjunction with the 2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 2,035,543 shares is not included in Column (c) above.
(D) The AES Corporation Second Amended and Restated Deferred Compensation Plan for directors provided for 2,000,000 shares authorized for issuance. Column (b) excludes the Director stock units granted thereunder. In conjunction with the 2010 amendment to the 2003 Long Term Compensation Plan, ongoing award issuance from this plan was discontinued in 2010 as Director stock units will be issued from the 2003 Long Term Compensation Plan. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 105,341 shares is not included in Column (c) above.
(E) The AES Corporation Incentive Stock Option Plan adopted in 1991 provided for 57,500,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $35.44. This plan terminated on June 1, 2001, such that no additional grants may be granted under the plan after that date. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance in light of this plan’s termination and thus 24,354,930 shares are not included in Column (c) above.
(2) Includes 6,806,948 (of which 3,027,981 are vested and 3,629,523 are unvested) shares underlying PSU and RSU awards (assuming performance at a maximum level), 1,162,552 shares underlying Director stock unit awards, and 7,873,241 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 15,842,741 shares.
(3) The AES Corporation 2001 Non-Officer Stock Option Plan provided for 12,000,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan shown in Column (b) is $4.05. In conjunction with the 2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 7,107,448 shares is not included in Column (c) above. This plan is described in the narrative below.
The AES Corporation 2001 Non-Officer Stock Option Plan (the “2001 Plan”) was adopted by the Board on October 18, 2001, and became effective October 25, 2001. The 2001 Plan did not require approval of AES’s stockholders under the SEC or NYSE rules and/or regulations at that time. All employees that are not officers, directors or beneficial owners of more than 10% of AES’s common stock are eligible to participate in the 2001 Plan. The total aggregate number of shares for which Options can be granted pursuant to the 2001 Plan is 12 million. As of December 31, 2012, 4 employees held Options under the 2001 Plan. The exercise price of each Option awarded under the 2001 Plan is equal to the fair market value of AES’s common stock on the grant date of the Option. Unless otherwise provided by the Compensation Committee of the Board, upon the death or disability of an employee, or a change of control (as defined therein), all Options granted under the 2001 Plan will become fully vested and exercisable. Unless otherwise provided by the Compensation Committee of the Board, in the event that the employee’s employment with the Company terminates for any reason other than death or disability, all Options held by such employee will automatically expire on the earlier of (a) the date the Option would have expired had the employee continued in such employment, and (b) 180 days after the date that such employee’s employment ceases. The 2001 Plan expired on October 25, 2011.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information regarding related party transactions required by this item is included in the 2013 Proxy Statement found under the headings Transactions with Related Persons, Proposal I: Election of Directors and The Committees of the Board and are incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information concerning principal accountant fees and services included in the 2013 Proxy Statement contained under the heading Information Regarding The Independent Registered Public Accounting Firm’s Fees, Services and Independence and is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements.
(b) Exhibits.
(c) Schedules
Schedule I-Condensed Financial Information of Registrant
Schedule II-Valuation and Qualifying Accounts
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
THE AES CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule I-Condensed Financial Information of Registrant
S-2
Schedule II-Valuation and Qualifying Accounts
S-9
Schedules other than those listed above are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.
See Notes to Schedule I
S-1
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
BALANCE SHEETS
See Notes to Schedule I
S-2
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF OPERATIONS
See Notes to Schedule I
S-3
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
See Notes to Schedule I
S-4
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF CASH FLOWS
See Notes to Schedule I
S-5
THE AES CORPORATION
SCHEDULE I
NOTES TO SCHEDULE I
1. Application of Significant Accounting Principles
The Schedule I Condensed Financial Information of the Parent includes the accounts of The AES Corporation (the “Parent Company”) and certain holding companies.
Accounting for Subsidiaries and Affiliates-The Parent Company has accounted for the earnings of its subsidiaries on the equity method in the financial information.
Income Taxes-Positions taken on the Parent Company’s income tax return which satisfy a more-likely-than-not threshold will be recognized in the financial statements. The income tax expense or benefit computed for the Parent Company reflects the tax assets and liabilities on a stand-alone basis and the effect of filing a consolidated U.S. income tax return with certain other affiliated companies.
Accounts and Notes Receivable from Subsidiaries-Amounts have been shown in current or long-term assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions precedent in the subsidiary loan agreements.
Correction of an Error-Certain amounts due to or from subsidiaries were not properly eliminated in the preparation of the Schedule I Condensed Financial Information of Parent for the year ended December 31, 2011 included in the Company’s 2011 Form 10-K. As a result, the December 31, 2011 balance sheet information of accounts and notes receivable from subsidiaries, investments in and advances to subsidiaries and affiliates, and current and long-term accounts and notes payable to subsidiaries were overstated. Accounts and notes receivable from subsidiaries was previously reported as $871 million and has been restated to $602 million. Investment in and advances to subsidiaries and affiliates was previously reported as $12,088 million and has been restated to $11,352 million. Accounts and notes payable to subsidiaries was previously reported as $317 million and has been restated to $48 million. Accounts and notes payable to subsidiaries was previously reported as $1,007 million and has been restated to $254 million.
Net cash provided by operating activities previously reported on the statement of cash flows for the year ended December 31, 2011 was previously reported as $1,569 million and has now been restated to $719 million. Net cash used in investing activities was previously reported as $2,747 million and has now been restated to $2,638 million. Net cash provided by financing activities previously reported as $773 million was restated to $1,512 million.
Interest income and interest expense previously reported on the statement of operations for the year ended December 31, 2011 were each reduced by approximately $50 million as a result of these adjustments. There was no impact to Parent Company net income.
There was no impact to the Schedule 1 Condensed Financial Information of Parent for the twelve months ended December 31, 2010 or the statement of comprehensive income for the year ended December 31, 2011 as a result of these adjustments. Further, there was no impact to the Company’s consolidated financial statements for 2012, 2011 or 2010 as a result of these adjustments.
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Selected Balance Sheet Data:
Selected Operations Data:
2. Senior Notes and Junior Subordinated Notes and Debentures Payable
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FUTURE MATURITIES OF DEBT-Recourse debt as of December 31, 2012 is scheduled to reach maturity as set forth in the table below:
3. Dividends from Subsidiaries and Affiliates
Cash dividends received from consolidated subsidiaries and from affiliates accounted for by the equity method were as follows:
4. Guarantees and Letters of Credit
GUARANTEES-In connection with certain of its project financing, acquisition, and power purchase agreements, the Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter of credit and other obligations discussed below, were limited as of December 31, 2012, by the terms of the agreements, to an aggregate of approximately $568 million representing 19 agreements with individual exposures ranging from less than $1 million up to $237 million.
LETTERS OF CREDIT-At December 31, 2012, the Company had $5 million in letters of credit outstanding under the senior unsecured credit facility representing 6 agreements with individual exposures ranging from less than $1 million and up to $2 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. At December 31, 2012, the Company had $215 million in cash collateralized letters of credit outstanding representing 9 agreements with individual exposures ranging from less than $1 million up to $189 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. During 2012, the Company paid letter of credit fees ranging from 0.250% to 3.250% per annum on the outstanding amounts.
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THE AES CORPORATION
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(IN MILLIONS)
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