Form 10-KItem 1B — should not be construed as exhaustive.
57
| | Item 1B — | Unresolved Staff Comments |
None. 58
Listed below are descriptions of NRG’s interests in facilities, operationsand/or projects owned as of December 31, 2009. The MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company’s ownership position excluding capacity from inactive/mothballed units as of December 31, 2009. The following table summarizes NRG’s power production and cogeneration facilities by region: Listed below are descriptions of NRG’s interests in facilities, operationsand/or projects owned as of December 31, 2008. The MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company’s ownership position excluding capacity from inactive/mothballed units as of December 31, 2008. The following table summarizes NRG’s power production and cogeneration facilities by region:
| | | | | | | | | | | | | | | | | | | | Net
| | | | | | Power
| | | | | Generation
| | | Primary
| Name and Location of Facility | | Market | | % Owned | | | Capacity (MW) | | | Fuel-type | | Texas Region: | | | | | | | | | | | | | W. A. Parish, Thompsons, Texas | | ERCOT | | | 100.0 | | | | 2,475 | | | Coal | Limestone, Jewett, Texas | | ERCOT | | | 100.0 | | | | 1,690 | | | Lignite/Coal | South Texas Project, Bay City, Texas(a) | | ERCOT | | | 44.0 | | | | 1,175 | | | Nuclear | Cedar Bayou, Baytown, Texas | | ERCOT | | | 100.0 | | | | 1,495 | | | Natural Gas | T. H. Wharton, Houston, Texas | | ERCOT | | | 100.0 | | | | 1,025 | | | Natural Gas | W. A. Parish, Thompsons, Texas | | ERCOT | | | 100.0 | | | | 1,190 | | | Natural Gas | S. R. Bertron, Deer Park, Texas | | ERCOT | | | 100.0 | | | | 840 | | | Natural Gas | Greens Bayou, Houston, Texas | | ERCOT | | | 100.0 | | | | 760 | | | Natural Gas | San Jacinto, LaPorte, Texas | | ERCOT | | | 100.0 | | | | 165 | | | Natural Gas | Elbow Creek Wind Farm, Howard County, Texas | | ERCOT | | | 100.0 | | | | 120 | | | Wind | Sherbino Wind Farm, Pecos County, Texas | | ERCOT | | | 50.0 | | | | 75 | | | Wind | Northeast Region: | | | | | | | | | | | | | Oswego, New York | | NYISO | | | 100.0 | | | | 1,635 | | | Oil | Arthur Kill, Staten Island, New York | | NYISO | | | 100.0 | | | | 865 | | | Natural Gas | Middletown, Connecticut | | ISO-NE | | | 100.0 | | | | 770 | | | Oil | Indian River, Millsboro, Delaware | | PJM | | | 100.0 | | | | 740 | | | Coal | Astoria Gas Turbines, Queens, New York | | NYISO | | | 100.0 | | | | 550 | | | Natural Gas | Dunkirk, New York | | NYISO | | | 100.0 | | | | 530 | | | Coal | Huntley, Tonawanda, New York | | NYISO | | | 100.0 | | | | 380 | | | Coal | Montville, Uncasville, Connecticut | | ISO-NE | | | 100.0 | | | | 500 | | | Oil | Norwalk Harbor, So. Norwalk, Connecticut | | ISO-NE | | | 100.0 | | | | 340 | | | Oil | Devon, Milford, Connecticut | | ISO-NE | | | 100.0 | | | | 140 | | | Natural Gas | Vienna, Maryland | | PJM | | | 100.0 | | | | 170 | | | Oil | Somerset, Massachusetts | | ISO-NE | | | 100.0 | | | | 125 | | | Coal | Connecticut Jet Power, Connecticut (four sites) | | ISO-NE | | | 100.0 | | | | 145 | | | Oil/Natural Gas | Conemaugh, New Florence, Pennsylvania | | PJM | | | 3.7 | | | | 65 | | | Coal | Keystone, Shelocta, Pennsylvania | | PJM | | | 3.7 | | | | 65 | | | Coal |
58
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net
| | | | | | | | Net
| | | | | Power
| | | | Generation
| | Primary
| | Power
| | | | Generation
| | Primary
| Name and Location of Facility | | Market | | % Owned | | Capacity (MW) | | Fuel-type | | Market | | % Owned | | Capacity (MW) | | Fuel-type | | | Texas Region: | | | | | | | | | | | | | | W. A. Parish, Thompsons, Texas | | | ERCOT | | | 100.0 | | | | 2,490 | | | Coal | Limestone, Jewett, Texas | | | ERCOT | | | 100.0 | | | | 1,690 | | | Lignite/Coal | South Texas Project, Bay City, Texas(a) | | | ERCOT | | | 44.0 | | | | 1,175 | | | Nuclear | Cedar Bayou, Baytown, Texas | | | ERCOT | | | 100.0 | | | | 1,495 | | | Natural Gas | Cedar Bayou 4, Baytown, Texas | | | ERCOT | | | 50.0 | | | | 260 | | | Natural Gas | T. H. Wharton, Houston, Texas | | | ERCOT | | | 100.0 | | | | 1,025 | | | Natural Gas | W. A. Parish, Thompsons, Texas | | | ERCOT | | | 100.0 | | | | 1,175 | | | Natural Gas | S. R. Bertron, Deer Park, Texas | | | ERCOT | | | 100.0 | | | | 765 | | | Natural Gas | Greens Bayou, Houston, Texas | | | ERCOT | | | 100.0 | | | | 760 | | | Natural Gas | San Jacinto, LaPorte, Texas | | | ERCOT | | | 100.0 | | | | 160 | | | Natural Gas | Elbow Creek Wind Farm, Howard County, Texas | | | ERCOT | | | 100.0 | | | | 120 | | | Wind | Langford Wind Farm, Christoval, Texas | | | ERCOT | | | 100.0 | | | | 150 | | | Wind | Sherbino Wind Farm, Pecos County, Texas | | | ERCOT | | | 50.0 | | | | 75 | | | Wind | Northeast Region: | | | | | | | | | | | | | | Oswego, New York | | | NYISO | | | 100.0 | | | | 1,635 | | | Oil | Arthur Kill, Staten Island, New York | | | NYISO | | | 100.0 | | | | 865 | | | Natural Gas | Middletown, Connecticut | | | ISO-NE | | | 100.0 | | | | 770 | | | Oil | Indian River, Millsboro, Delaware | | | PJM | | | 100.0 | | | | 740 | | | Coal | Astoria Gas Turbines, Queens, New York | | | NYISO | | | 100.0 | | | | 550 | | | Natural Gas | Dunkirk, New York | | | NYISO | | | 100.0 | | | | 530 | | | Coal | Huntley, Tonawanda, New York | | | NYISO | | | 100.0 | | | | 380 | | | Coal | Montville, Uncasville, Connecticut | | | ISO-NE | | | 100.0 | | | | 500 | | | Oil | Norwalk Harbor, So. Norwalk, Connecticut | | | ISO-NE | | | 100.0 | | | | 340 | | | Oil | Devon, Milford, Connecticut | | | ISO-NE | | | 100.0 | | | | 135 | | | Natural Gas | Vienna, Maryland | | | PJM | | | 100.0 | | | | 170 | | | Oil | Somerset, Massachusetts | | | ISO-NE | | | 100.0 | | | | 125 | | | Coal | Connecticut Jet Power, Connecticut (four sites) | | | ISO-NE | | | 100.0 | | | | 145 | | | Oil/Natural Gas | Conemaugh, New Florence, Pennsylvania | | | PJM | | | 3.7 | | | | 65 | | | Coal | Keystone, Shelocta, Pennsylvania | | | PJM | | | 3.7 | | | | 65 | | | Coal | South Central Region: | | | | | | | | | | | | | | | | | | | | | | | | | Big Cajun II, New Roads, Louisiana(b) | | SERC-Entergy | | | 86.0 | | | | 1,490 | | | Coal | | SERC-Entergy | | | 86.0 | | | | 1,495 | | | Coal | Bayou Cove, Jennings, Louisiana | | SERC-Entergy | | | 100.0 | | | | 300 | | | Natural Gas | | SERC-Entergy | | | 100.0 | | | | 300 | | | Natural Gas | Big Cajun I, Jarreau, Louisiana | | SERC-Entergy | | | 100.0 | | | | 210 | | | Natural Gas | | Big Cajun I, Jarreau, Louisiana | | SERC-Entergy | | | 100.0 | | | | 220 | | | Natural Gas/Oil | | SERC-Entergy | | | 100.0 | | | | 430 | | | Natural Gas/Oil | Rockford I, Illinois | | PJM | | | 100.0 | | | | 300 | | | Natural Gas | | PJM | | | 100.0 | | | | 300 | | | Natural Gas | Rockford II, Illinois | | PJM | | | 100.0 | | | | 150 | | | Natural Gas | | PJM | | | 100.0 | | | | 155 | | | Natural Gas | Sterlington, Louisiana | | SERC-Entergy | | | 100.0 | | | | 175 | | | Natural Gas | | SERC-Entergy | | | 100.0 | | | | 175 | | | Natural Gas | West Region: | | | | | | | | | | | | | | | | | | | | | | | | | Blythe, Blythe, California | | | CAISO | | | 100.0 | | | | 20 | | | Solar | Encina, Carlsbad, California | | CAISO | | | 100.0 | | | | 965 | | | Natural Gas | | CAISO | | | 100.0 | | | | 965 | | | Natural Gas | El Segundo Power, California | | CAISO | | | 100.0 | | | | 670 | | | Natural Gas | | CAISO | | | 100.0 | | | | 670 | | | Natural Gas | Long Beach, California | | CAISO | | | 100.0 | | | | 260 | | | Natural Gas | | CAISO | | | 100.0 | | | | 260 | | | Natural Gas | San Diego Combustion Turbines, California (three sites) | | CAISO | | | 100.0 | | | | 190 | | | Natural Gas | | CAISO | | | 100.0 | | | | 190 | | | Natural Gas | Saguaro Power Co., Henderson, Nevada | | WECC | | | 50.0 | | | | 45 | | | Natural Gas | | WECC | | | 50.0 | | | | 45 | | | Natural Gas | International Region: | | | | | | | | | | | | | | | | | | | | | | | | | Gladstone Power Station, Queensland, Australia | | Enertrade/Boyne Smelter | | | 37.5 | | | | 605 | | | Coal | | Enertrade/Boyne Smelter | | | 37.5 | | | | 605 | | | Coal | Schkopau Power Station, Germany | | Vattenfall Europe | | | 41.9 | | | | 400 | | | Lignite | | Vattenfall Europe | | | 41.9 | | | | 400 | | | Lignite | MIBRAG, Germany(c) | | Schkopau, Lippendorf & ENVIA | | | 50.0 | | | | 75 | | | Lignite | |
| | | (a) | | For the nature of NRG’s interest and various limitations on the Company’s interest, please read Item 1 — Business — Texas — Generation Facilities section | | (b) | | | | (a) | For the nature of NRG’s interest and various limitations on the Company’s interest, please read Item 1 — Business — Texas — Generation Facilities section | | (b) | Units 1 and 2 owned 100.0%, Unit 3 owned 58.0% | | (c) | | Primarily a coal mining facility |
59
The following table summarizes NRG’s thermal facilities as of December 31, 2009: | | | | | | | | | | | | | %
| | | | | | | | Ownership
| | | | Name and Location of Facility | | Thermal Energy Purchaser | | Interest | | | Generating Capacity | | NRG Energy Center Minneapolis, Minnesota | | Approx. 100 steam customers and 50 chilled water customers | | | 100.0 | | | Steam: 1,143 MMBtu/hr. (335 MWt) Chilled Water: 40,630 tons (143 MWt) | NRG Energy Center San Francisco, California | | Approx. 170 steam customers | | | 100.0 | | | Steam: 454 MMBtu/Hr. (133 MWt) | NRG Energy Center Harrisburg, Pennsylvania | | Approx. 210 steam customers and 3 chilled water customers | | | 100.0 | | | Steam: 440 MMBtu/hr. (129 MWt) Chilled water: 2,400 tons (8 MWt) | NRG Energy Center Pittsburgh, Pennsylvania | | Approx. 25 steam and 25 chilled water customers | | | 100.0 | | | Steam: 296 MMBtu/hr. (87 MWt) Chilled water: 12,920 tons (45 MWt) | NRG Energy Center San Diego, California | | Approx. 20 chilled water customers | | | 100.0 | | | Chilled water: 7,425 tons (26 MWt) | Camas Power Boiler Camas, Washington | | Georgia-Pacific Corp. | | | 100.0 | | | Steam: 200 MMBtu/hr. (59 MWt) | NRG Energy Center Dover, Delaware | | Kraft Foods Inc. and Procter & Gamble Company | | | 100.0 | | | Steam: 190 MMBtu/hr. (56 MWt) | Paxton Creek Cogeneration, Harrisburg, Pennsylvania | | PJM | | | 100.0 | | | 12 MW -- Natural Gas | Dover Cogeneration, Delaware | | PJM | | | 100.0 | | | 103 MW -- Natural Gas/Coal |
Other Properties In addition, NRG owns several real property and facilities relating to its generation assets, other vacant real property unrelated to the Company’s generation assets, interest in a construction project, and properties not used for operational purposes. NRG believes it has satisfactory title to its plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in the Company’s opinion, would not have a material adverse effect on the use or value of its portfolio. NRG leases its corporate offices at 211 Carnegie Center, Princeton, New Jersey, its Reliant Energy offices and call centers, and various other office space. In addition, NRG is constructing office space under a newly signed lease, to combine the Company’s Texas region administration offices and Reliant Energy’s offices. | | Item 3 — | Legal Proceedings |
City of San Antonio, Texas, acting by and through the City Public Service Board of San Antonio, a Texas municipal utility v. Toshiba Corporation; NRG Energy, Inc.; Nuclear Innovation North America, LLC; NINA Texas 3 LLC; and NINA Texas 4 LLC (as amended), 37th Judicial District Court, Bexar County, TX, Case #2009CL19492(filed December 6, 2009) —The original December 6, 2009, complaint against two Nuclear Innovation North America, or NINA, entities asked the court to declare the rights, obligations, and remedies of the parties pursuant to the 1997 and 2007 agreements between the parties should CPS unilaterally withdraw from the proposed South Texas Project Units 3 and 4, or the STP Units 3 and 4 Project. On December 23, 2009, CPS amended its original December 6 complaint adding NRG, Toshiba Corporation, and NINA LLC as defendants and not only continued to request that the Court declare the rights, obligations, and remedies of the parties under the two operative governing agreements, but also sought $32 billion in damages. CPS amended its complaint again on December 28, 2009. On January 6, 2010, CPS amended its complaint for the third time. In addition to requesting immediate injunctive relief, the amended complaint alleges that NRG, Toshiba, and NINA have been involved in a conspiracy to defraud CPS, that they purposefully misled CPS in inducing it to be a partner in the STP Units 3 and 4 Project, that they maliciously interfered with CPS contracts and business relationships, and that they willfully disparaged CPS. It sought declarations that: (i) owner consensus is required for all development decisions; (ii) there is a right to voluntary withdrawal, after which no further obligations accrue but undiluted ownership continues; (iii) both the partition waiver and forfeiture provisions are unenforceable against CPS under Texas law if they did apply; and (iv) CPS is not currently in breach. In addition, CPS sought relief among the following alternatives: partition by sale; an order forcing NRG and NINA to buy CPS undiluted share at an independent valuation; an order requiring NRG to compensate CPS $350 million investment and fair value for the site; an order granting CPS twelve months 60
following withdrawal to sell its stake in the project; or an order that no further development take place without consensus of all project owners. The case was removed and remanded to and from federal court on three separate occasions. On January 19, 2010, CPS dismissed Toshiba from the lawsuit. The parties agreed to a January 25, 2010, phased trial wherein all other claims would be reserved for an undetermined future phase II date and a trial would go forward in phase I only on CPS’ request for declaratory relief to determine the respective rights, obligations, and remedies of the parties under the two operative governing agreements should CPS withdraw from the STP Units 3 and 4 Project. On January 25,2010, the parties argued the NINA entities and NRG’s Motion for Summary Judgment which was denied on January 26, 2010. After atwo-day trial, the court issued its ruling on January 29, 2010, making a number of findings. It ruled that as of January 29, CPS and NINA were each 50% equity owners as tenants in common under Texas law in the STP Units 3 and 4 Project. The court found that while a withdrawing party does not forfeit its 50% interest upon a withdrawal, the governing agreements are silent as to whether that withdrawing party can recoup its sunk costs upon withdrawal. Finally, the court noted that for CPS to remain a 50% equity owner, it must pay all appropriate costs. Failure to do so, the court determined, would result in a complete loss of CPS’ equity share. On February 17, 2010, an agreement in principle was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project through a settlement of all pending litigation between the parties. As part of that agreement, all litigation would be dismissed with prejudice, including all Phase II claims, thereby ending this matter. For further discussion, see Item 1,Nuclear Development.The parties continue to negotiate terms regarding final documentation of the agreement in principle. Public Utilities Commission of the State of California v. Long-Term Sellers of Long-Term Contracts to the California Department of Water Resources,FERC DocketNo. EL02-60 et al.— This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC’s review of the contracts at issue, the FERC could not rely on theMobile-Sierrastandard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP’s appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008 the Supreme Court ruled: (i) that theMobile-Sierra public interest standard of review applied to contracts made under a seller’s market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that theMobile-Sierrapresumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit’s decision agreeing that the case should be remanded to the FERC to clarify the FERC’s 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008 decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether theMobile-Sierradoctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court’s June 26, 2008 decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand, and on January 28, 2009, WCP and the other seller-defendants filed their reply. 61
At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG’s financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy’s 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy. On January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding involving theMobile-Sierradoctrine that will affect the standard of review applied to the CDWR contract on remand before the FERC. InNRG Power Marketing v. Maine Public Utilities Commission, the Supreme Court held by an 8 to 1 margin that theMobile-Sierrapresumption regarding the reasonableness of contract rates does not depend on the identity of the complainant who seeks a FERC investigation/refund. The Supreme Court proceeding arose following an appeal by the Attorneys General of the State of Connecticut and of the Commonwealth of Massachusetts regarding the settlement establishing the New England Forward Capacity Market. The settlement, filed with the FERC on March 7, 2006, provides for interim capacity transition payments for all generators in New England for the period from December 1, 2006, through May 31, 2010, and for the Forward Capacity Market auction rates thereafter. The Court of Appeals for the DC Circuit, or DC Circuit, had rejected all substantive challenges to the settlement, but had sustained one procedural argument relating to the applicability of theMobile-Sierradoctrine to third parties. The Supreme Court reversed the DC Circuit on this point, and remanded the case for further consideration of whether the transition payments and auction rates qualify as contract rates. United States of America v. Louisiana Generating, LLC., U.S.D.C Middle District of Louisiana,Civil ActionNo. 09-100-RET-CN (filed February 11, 2009) —The U.S. Department of Justice acting at the request of the U.S. EPA commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990’s, several years prior to NRG’s acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the BACT to control emissions of nitrogen oxidesand/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA’s Prevention of Significant Deterioration program; (vi) award to the Department of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009. On April 27, 2009, Louisiana Generating, LLC made several filings. It filed an objection in the Cajun Electric Cooperative Power, Inc.’s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. It also filed a complaint in the same bankruptcy proceeding in the same court seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric; and (iii) Cajun Electricand/or the Bankruptcy Trustee are exclusively liable for the violations alleged in the February 11, 2009 lawsuit to the extent that such claims are determined to have merit. On June 8, 2009, the parties filed a joint status report setting forth their views of the case and proposing a trial schedule. On June 18, 2009, Louisiana Generating, LLC filed a motion to bifurcate the Department of Justice lawsuit into separate liability and remedy phases, and on June 30, 2009, the Department of Justice filed its opposition. On August 24, 2009, Louisiana Generating, LLC filed a motion to dismiss this lawsuit, and on September 25, 2009, the 62
Department of Justice filed its opposition to the motion to dismiss. A new federal bankruptcy judge was appointed on October 9, 2009. On February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a motion to intervene in the above lawsuit and a complaint against Louisiana Generating LLC for alleged violations of Louisiana’s PSD regulations and Louisiana’s Title V operating permit program. LDEQ seeks similar relief to that requested by the Department of Justice. Specifically, LDEQ seeks injunctive relief to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2 pursuant to the requirements of PSD and the Louisiana Title V operating permits program; (iv) conduct audits to determine if any additional modifications have occurred which would require it to meet the requirements of PSD and report the Results of the audit to the LDEQ and EPA; (v) order the surrender of emission allowances or credits; (vi) take other appropriate actions to remedy, mitigate and offset the harm to public health and the environment caused by violations of the CAA; (vii) assess civil penalties; and (viii) award to the LDEQ its costs in prosecuting the litigation. On February 19, 2010, the district court granted LDEQ’s motion to intervene. Hohl Industrial Services, Inc, v. Dunkirk Power LLC, et al; New York State Supreme Court, County of Chautauqua; Index No, Kl-2009-1510 (original complaint filed August 28, 2009, cross claims filed by CBEEC on February 17, 2010) —In 2005, NRG entered into a Consent Decree with the New York State Department of Environmental Conservation whereby it agreed to reduce certain emissions generated by its Huntley and Dunkirk power plants. Pursuant to the Consent Decree, on November 21, 2007, Clyde Bergemann EEC, or CBEEC, and NRG entered into a firm fixed price contract for the supply of equipment, material and services for six fabric filters for NRG’s Dunkirk Electric Power Generating Station. Subsequent to contracting with NRG, CBEEC subcontracted with Hohl Industrial Services, Inc., or Hohl, to perform steel erection and equipment installation at Dunkirk. On August 28, 2009, Hohl filed its original complaint against NRG, its subsidiary Dunkirk Power LLC, or Dunkirk Power, and CBEEC among others for claims of breach of contract, quantum meruit, unjust enrichment and foreclosure of mechanics’ liens. As part of CBEEC’s contractual obligation to NRG, CBEEC agreed to defend, under a reservation of rights, NRG’s interest in this lawsuit. CBEEC filed an answer to the above complaint on behalf of itself, NRG and Dunkirk Power on October 5, 2009. On December 16, 2009, CBEEC filed a Motion for Summary Judgment on behalf of itself, NRG, and Dunkirk Power, which has yet to be decided. On February 1, 2010, NRG and Dunkirk Power filed a Motion for Leave to file an Amended Answer with Cross-Claims against CBEEC. NRG asserted breach of contract claims seeking liquidated damages for the delays caused by CBEEC. NRG also retained its own counsel to represent its interest in the cross-claims and reserved its rights to seek reimbursement from CBEEC. On February 17, 2010, CBEEC filed an Amended Answer with Affirmative Defenses, Counterclaims and Cross-Claims against NRG. CBEEC is seeking approximately $30 million alleging breach of contract, quantum meruit, unjust enrichment, and foreclosure of two mechanic’s liens, as a result of alleged delays caused by NRG and Dunkirk Power. A court ordered hearing and settlement conference is scheduled for February 23, 2010. Excess Mitigation Credits— From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers’ monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI Energy Inc., or RRI, totaled $385 million for RERS’s “Price to Beat” Customers. It is unclear what the actual number may be. “Price to Beat” was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT’s order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with 63
the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower court’s decision ruling that CenterPoint Energy’s stranded cost recovery should exclude only EMCs credited to RERS for its “Price to Beat” customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009. In November 2008, CenterPoint Energy and RRI, on behalf of itself and affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy is ultimately not allowed to include in its stranded cost calculation those EMCs previously credited to RERS. Regardless of the outcome of the Texas Supreme Court proceeding, NRG believes that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack legal merit. No such claim has been filed. Additional Litigation —In addition to the foregoing, NRG is party to other litigation or legal proceedings. The Company believes that it has valid defenses to the legal proceedings and investigations described above and intends to defend them vigorously. However, litigation is inherently subject to many uncertainties. There can be no assurance that additional litigation will not be filed against the Company or its subsidiaries in the future asserting similar or different legal theories and seeking similar or different types of damages and relief. Unless specified above, the Company is unable to predict the outcome these legal proceedings and investigations may have or reasonably estimate the scope or amount of any associated costs and potential liabilities. An unfavorable outcome in one or more of these proceedings could have a material impact on the Company’s consolidated financial position, results of operations or cash flows. The Company also has indemnity rights for some of these proceedings to reimburse the Company for certain legal expenses and to offset certain amounts deemed to be owed in the event of an unfavorable litigation outcome. PART II | | Item 4 — | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Market Information and Holders NRG’s authorized capital stock consists of 500,000,000 shares of NRG common stock and 10,000,000 shares of preferred stock. A total of 16,000,000 shares of the Company’s common stock are available for issuance under NRG’s Long-Term Incentive Plan. NRG has also filed with the Secretary of State of Delaware a Certificate of Designation for the 3.625% Convertible Perpetual Preferred Stock. NRG’s common stock is listed on the New York Stock Exchange and has been assigned the symbol: NRG. The high and low sales prices, as well as the closing price for the Company’s common stock on a per share basis for 2009 and 2008 are set forth below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fourth
| | | Third
| | | Second
| | | First
| | | Fourth
| | | Third
| | | Second
| | | First
| | Common Stock
| | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | Price | | 2009 | | | 2009 | | | 2009 | | | 2009 | | | 2008 | | | 2008 | | | 2008 | | | 2008 | | | High | | $ | 29.18 | | | $ | 29.26 | | | $ | 25.96 | | | $ | 25.38 | | | $ | 25.40 | | | $ | 43.95 | | | $ | 45.78 | | | $ | 43.96 | | Low | | | 22.82 | | | | 21.94 | | | | 16.50 | | | | 15.19 | | | | 14.39 | | | | 22.20 | | | | 38.36 | | | | 34.56 | | Closing | | $ | 23.61 | | | $ | 28.19 | | | $ | 25.96 | | | $ | 17.60 | | | $ | 23.33 | | | $ | 24.75 | | | $ | 42.90 | | | $ | 38.99 | |
NRG had 253,995,308 shares outstanding as of December 31, 2009, and as of February 17, 2010, there were 261,898,178 shares outstanding. As of February 17, 2010, there were 70,000 common stockholders of record. Dividends NRG has not declared or paid dividends on its common stock. To the extent NRG declares such a dividend, the amount available for dividends is currently limited by the Company’s senior secured credit agreements and high yield note indentures. 64
Repurchase of equity securities NRG’s repurchases of equity securities for the year ended December 31, 2009, were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Total Number
| | | | | | | | | | | | | of Shares
| | | Dollar Value of
| | | | | | | | | | Purchased as
| | | Shares that may be
| | | | | | | | | | Part of Publicly
| | | Purchased Under the
| | | | Total Number of
| | | Average Price
| | | Announced Plans
| | | 2009 Capital
| | For the Year Ended December 31, 2009 | | Shares Purchased | | | Paid per Share | | | or Programs | | | Allocation Plan | | | First quarter | | | — | | | $ | — | | | | — | | | $ | 330,000,000 | | Second quarter | | | — | | | | — | | | | — | | | | 330,000,000 | | Third quarter | | | 8,919,100 | | | | 28.01 | | | | 8,919,100 | | | | 250,002,565 | | Fourth quarter | | | 10,386,400 | | | | 24.05 | | | | 10,386,400 | | | | — | | | | | | | | | | | | | | | | | | | Total for 2009 | | | 19,305,500 | | | $ | 25.88 | | | | 19,305,500 | | | $ | — | | | | | | | | | | | | | | | | | | |
The Company’s Capital Allocation Plan included the completion of the 2008 Capital Allocation Plan with the planned purchase of $30 million of common stock as well as the purchase of an additional $300 million in common stock under the previously announced 2009 Capital Allocation Plan. In July 2009, as part of the Company’s 2009 Capital Allocation Program, NRG’s Board of Directors approved an increase to the Company’s previously authorized common share repurchases under its capital allocation plan from the existing $330 million to $500 million. The Company’s repurchases during the quarters ended September 30, 2009, and December 31, 2009, were $250 million and $250 million, respectively. The Company’s share repurchases are subject to market prices, financial restrictions under the Company’s debt facilities, and as permitted by securities laws. Securities Authorized for Issuance under Equity Compensation Plans | | | | | | | | | | | | | | | | | | | | | (c)
| | | | | | | | | | Number of Securities
| | | | (a)
| | | | | | Remaining Available
| | | | Number of Securities
| | | (b)
| | | for Future Issuance
| | | | to be Issued Upon
| | | Weighted-Average Exercise
| | | Under Equity Compensation
| | | | Exercise of
| | | Price of Outstanding
| | | Plans (Excluding
| | | | Outstanding Options,
| | | Options, Warrants and
| | | Securities Reflected
| | Plan Category | | Warrants and Rights | | | Rights | | | in Column (a)) | | | Equity compensation plans approved by security holders | | | 7,947,003 | | | $ | 25.07 | | | | 5,129,593 | | Equity compensation plans not approved by security holders | | | — | | | | N/A | | | | — | | | | | | | | | | | | | | | Total | | | 7,947,003 | | | $ | 25.07 | | | | 5,129,593 | | | | | | | | | | | | | | |
| | | (a) | | Consists of NRG Energy, Inc.’s Long-Term Incentive Plan, or the LTIP, and NRG Energy, Inc.’s Employee Stock Purchase Plan, or the ESPP. The LTIP became effective upon the Company’s emergence from bankruptcy. The LTIP was subsequently approved by the Company’s stockholders on August 4, 2004 and was amended on April 28, 2006 to increase the number of shares available for issuance to 16,000,000, on a post-split basis, and again on December 8, 2006 to make technical and administrative changes. The LTIP provides for grants of stock options, stock appreciation rights, restricted stock, performance units, deferred stock units and dividend equivalent rights. NRG’s directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the LTIP. The purpose of the LTIP is to promote the Company’s long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company’s success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the LTIP. There were 5,129,593 and 6,798,074 shares of common stock remaining available for grants of awards under NRG’s LTIP as of December 31, 2008: | | | | | | | | | | | | | %
| | | | | | | | Ownership
| | | | Name and Location of Facility
| | Thermal Energy Purchaser | | Interest | | | Generating Capacity | | NRG Energy Center Minneapolis, Minnesota | | Approx. 100 steam customers and 50 chilled water customers | | | 100.0 | | | Steam: 1,143 MMBtu/hr. (335 MWt) Chilled Water: 40,630 tons (143 MWt) | NRG Energy Center San Francisco, California | | Approx. 170 steam customers | | | 100.0 | | | Steam: 454 MMBtu/Hr. (133 MWt) | NRG Energy Center Harrisburg, Pennsylvania | | Approx. 210 steam customers and 3 chilled water customers | | | 100.0 | | | Steam: 440 MMBtu/hr. (129 MWt) Chilled water: 2,400 tons (8 MWt) | NRG Energy Center Pittsburgh, Pennsylvania | | Approx. 25 steam and 25 chilled water customers | | | 100.0 | | | Steam: 296 MMBtu/hr. (87 MWt) Chilled water: 12,920 tons (45 MWt) | NRG Energy Center San Diego, California | | Approx. 20 chilled water customers | | | 100.0 | | | Chilled water: 7,425 tons (26 MWt) | Camas Power Boiler Camas, Washington | | Georgia-Pacific Corp. | | | 100.0 | | | Steam: 200 MMBtu/hr. (59 MWt) | NRG Energy Center Dover, Delaware | | Kraft Foods Inc. and Procter & Gamble Company | | | 100.0 | | | Steam: 190 MMBtu/hr. (56 MWt) | Paxton Creek Cogeneration, Harrisburg, Pennsylvania | | PJM | | | 100.0 | | | 12 MW — Natural Gas | Dover Cogeneration, Delaware | | PJM | | | 100.0 | | | 104 MW — Natural Gas/Coal |
Other Properties
In addition, NRG owns several real property2009 and facilities relating to its generation assets, other vacant real property unrelated to the Company’s generation assets, interest in a construction project, and properties not used for operational purposes. NRG believes it has satisfactory title to its plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in the Company’s opinion, would not have a material adverse effect on the use or value of its portfolio.
NRG leases its corporate offices at 211 Carnegie Center, Princeton, New Jersey and various other office space.
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| | Item 3 — | Legal Proceedings |
Exelon Corporation and Exelon Xchange Corporation v. Howard E. Cosgrove et al., Court of Chancery of the State of Delaware, CaseNo. 4155-VCL(filed November 11, 2008)— On November 11, 2008, Exelon Corporation, or Exelon, and its wholly-owned subsidiary, Exelon Xchange, filed a complaint against NRG and NRG’s Board of Directors.respectively. The complaint alleges, among other things, that NRG’s Board of Directors failed to give due consideration and to take appropriate action in response to the acquisition proposal announced by Exelon on October 19, 2008, in which Exelon offered to acquire all of the outstanding shares of NRG common stock at an exchange ratio of 0.485 Exelon shares for each NRG common share. The complaint seeks, among other things, declaratory and injunctive relief: (1) declaring that NRG’s Board of Directors has breached its fiduciary duties to the NRG stockholders by rejecting and refusing to consider Exelon’s acquisition proposal and by failing to exempt the proposed transaction from application of Section 203 of the Delaware General Corporation Law; (2) compelling NRG’s Board of Directors to approve Exelon’s acquisition proposal for purposes of Section 203 of the Delaware General Corporations Law; (3) declaring that the adoption of any measure that would have the effect of impeding or interfering with Exelon’s acquisition proposal constitutes a breach of NRG’s Board of Directors fiduciary duties; and (4) enjoining the defendants from adopting any measures that would have the effect of impeding or interfering with Exelon’s acquisition proposal. On November 14, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss Exelon’s complaint on the grounds that it fails to state a claim upon which relief can be granted. On January 28, 2009, NRG and NRG’s Board of Directors filed their brief in support of their motion to dismiss.
Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System, on Behalf of Themselves and All Others Similarly Situated v. David Crane, et al., Court of Chancery of the State of Delaware, CaseNo. 4193-VCL(filed November 25, 2008; served December 11, 2008)— The complaint alleges, among other things, that NRG’s Board of Directors failed to give due consideration and to take appropriate action in response to the acquisition proposal announced by Exelon on October 19, 2008, in which Exelon offered to acquire all of the outstanding shares of NRG common stock at an exchange ratio of 0.485 Exelon shares for each NRG common share. The complaint seeks, among other things, declaratory and injunctive relief: (1) declaring that the action is a class action and certifying plaintiff as class plaintiff and plaintiff’s counsel as class counsel; (2) declaring that NRG’s Board of Directors has breached its fiduciary duties to the NRG stockholders by rejecting and refusing to consider Exelon’s acquisition proposal; (3) entering a mandatory injunction requiring NRG to exempt Exelon’s offer from Section 203 of the Delaware General Corporation Law; and (4) to the extent injunctive relief is not granted, awarding compensatory damages in favor of the Plaintiffs and other members of the class. On December 23, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss the complaint on the grounds that it fails to state a claim upon which relief can be granted. On January 28, 2009, NRG and NRG’s Board of Directors filed their brief in support of their motion to dismiss.
Evelyn Greenberg, on Behalf of Herself and All Others Similarly Situated v. David Crane, et al.,(filed October 20, 2008);Joel A. Gerber and Raphael Nach & Jaqueline Nach Co-Trustee The Nach Family Trust U/A, Individually and on behalf of All Others Similarly Situated v. NRG Energy, Inc., et al.(filed November 10, 2008); Walter H. Stansbury Individually and on behalf of All Others Similarly Situated v. NRG Energy, Inc., et al.,(filed October 24, 2008),Superior Court of New Jersey-Law Division, Mercer County, DocketNo. MER-C-137-08— Plaintiffs filed three separate complaints against NRG and NRG’s Board of Directors alleging, among other things, that NRG’s Board of Directors breached its fiduciary duties to NRG stockholders by failing to take action regarding the acquisition proposal announced by Exelon on October 19, 2008, in which Exelon offered to acquire all of the outstanding shares of NRG common stock at an exchange ratio of 0.485 Exelon shares for each NRG common share. On January 6, 2009, the three cases were consolidated and transferred to the Law Division of the Mercer County Superior Court. On January 21, 2009, the plaintiffs filed an Amended Consolidated Complaint in which they allege a single count of breach of fiduciary duty against NRG’s Board of Directors and seek injunctive relief: (1) declaring that the action is a class action and certifying plaintiffs as class plaintiffs and counsel as class counsel; (2) declaring that defendants breached their fiduciary duties by summarily rejecting the Exelon offer; (3) ordering defendants to negotiate with respect to the Exelon offer or with respect to another transaction to maximize shareholder value; (4) ordering defendants to exempt Exelon’s offer from Section 203 of the Delaware General Corporation Law; (5) awarding compensatory damages including interest; (6) awarding plaintiffs costs and fees; and (7) granting other relief the Court deems proper. A response is due on or before February 20, 2009.
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Public Utilities Commission of the State of California et al. v. Federal Energy Regulatory Commission,Nos.03-74246 and03-74207, FERC Nos. EL02-60-000, EL02-60, and EL02-62(filed December 19, 2006)— This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the caseESPP was appealed to the US Court of Appeals for the Ninth Circuit, or Ninth Circuit, where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC’s review of the contracts at issue, the FERC could not rely on theMobil-Sierrastandard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the US Supreme Court. WCP’s appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled (1) that theMobil-Sierrapublic interest standard of review applied to contracts made under a seller’s market-based rate authority; (2) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (3) that theMobil-Sierrapresumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the US Supreme Court affirmed the Ninth Circuit’s decision, agreeing that the case should be remanded to FERC to clarify FERC’s 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the US Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008, decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the US Supreme Court did not address in its June 26, 2008, decision; whether theMobil-Sierradoctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in the case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the US Supreme Court’s June 26, 2008 decision. On December 15, 2008, WCP and the other seller-defendants filed with FERC a Motion of Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand, and on January 28, 2009, WCP and the other seller-defendants filed their reply.
At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG’s financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy’s 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.
Additional Litigation —In addition to the foregoing, NRG is party to other litigation or legal proceedings. The Company believes that it has valid defenses to the legal proceedings and investigations described above and intends to defend them vigorously. However, litigation is inherently subject to many uncertainties. There can be no assurance that additional litigation will not be filed against the Company or its subsidiaries in the future asserting similar or different legal theories and seeking similar or different types of damages and relief. Unless specified above, the Company is unable to predict the outcome these legal proceedings and investigations may have or reasonably estimate the scope or amount of any associated costs and potential liabilities. An unfavorable outcome in one or more of these proceedings could have a material impact on the Company’s consolidated financial position, results of operations or cash flows. The Company also has indemnity rights for some of these proceedings to reimburse the Company for certain legal expenses and to offset certain amounts deemed to be owed in the event of an unfavorable litigation outcome.
62
Disputed Claims Reserve —As part of NRG’s plan of reorganization, NRG funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, as such claims are resolved, the claimants are paid from the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the reserves is held by an escrow agent to complete the distribution and settlement process. Since NRG has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from the balance sheet. Similarly, NRG removed the obligations relevant to the claims from the balance sheet when the common stock was issued and cash contributed.
On April 3, 2006, the Company made a supplemental distribution to creditors under the Company’s Chapter 11 bankruptcy plan, totaling $25 million in cash and 5,082,000 shares of common stock. On December 18, 2008, NRG filed with the US Bankruptcy Courts for the Southern District of New York a Closing Report and an Application for Final Decree Closing the Chapter 11 Case for NRG Energy, Inc. et al and on December 29, 2008, the court entered the Final Decree. As of December 21, 2008, the reserve held $9,776,880 in cash and 1,282,783 shares of common stock. On December 21, 2008, the Company issued an instruction letter to The Bank of New York Mellon to distribute all remaining cash and stock in the Disputed Claims Reserve to NRG’s creditors. On January 12, 2009, The Bank of New York Mellon commenced the distribution of all remaining cash and stock in the Disputed Claim Reserve to the Company’s creditors pursuant to NRG’s Chapter 11 bankruptcy plan.
| | Item 4 — | Submission of Matters to a Vote of Security Holders |
None.
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PART II
| | Item 5 — | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Market Information and Holders
NRG’s authorized capital stock consists of 500,000,000 shares of NRG common stock and 10,000,000 shares of preferred stock. A total of 16,000,000 shares of the Company’s common stock are available for issuance under NRG’s Long-Term Incentive Plan. NRG has also filed with the Secretary of State of Delaware a Certificate of Designation for each of the following shares of the Company’s preferred stock: (i) 4% Convertible Perpetual Preferred Stock, (ii) 3.625% Convertible Perpetual Preferred Stock, and (iii) 5.75% Mandatory Convertible Preferred Stock.
NRG’s common stock is listed on the New York Stock Exchange and has been assigned the symbol: NRG. NRG has submitted to the New York Stock Exchange its annual certificate from its Chief Executive Officer certifying that he is not aware of any violation by the Company of New York Stock Exchange corporate governance listing standards. The high and low sales prices, as well as the closing price for the Company’s common stock on a per share basis for 2008 and 2007 (after giving retroactive effect to the two-for-one stock split effective May 25, 2007) are set forth below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fourth
| | | Third
| | | Second
| | | First
| | | Fourth
| | | Third
| | | Second
| | | First
| | Common Stock
| | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | | Quarter
| | Price | | 2008 | | | 2008 | | | 2008 | | | 2008 | | | 2007 | | | 2007 | | | 2007 | | | 2007 | | | High | | $ | 25.40 | | | $ | 43.95 | | | $ | 45.78 | | | $ | 43.96 | | | $ | 47.19 | | | $ | 45.08 | | | $ | 45.93 | | | $ | 37.10 | | Low | | | 14.39 | | | | 22.20 | | | | 38.36 | | | | 34.56 | | | | 38.79 | | | | 34.76 | | | | 35.98 | | | | 27.22 | | Closing | | $ | 23.33 | | | $ | 24.75 | | | $ | 42.90 | | | $ | 38.99 | | | $ | 43.34 | | | $ | 42.29 | | | $ | 41.57 | | | $ | 36.02 | |
NRG had 234,356,717 shares outstanding as of December 31, 2008, and as of February 9, 2009, there were 236,232,031 shares outstanding. As of February 9, 2009, there were approximately 72,000 common stockholders of record.
Dividends
NRG has not declared or paid dividends on its common stock. To the extent NRG declares such a dividend, the amount available for dividends is currently limitedapproved by the Company’s senior secured credit agreements and high yield note indentures.
Repurchase of equity securities
NRG’s repurchases of equity securitiesstockholders on May 14, 2008. There were 500,000 shares reserved from the Company’s treasury shares for the year ended December 31, 2008, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | Total Number
| | | | | | | | | | | | | of Shares
| | | | | | | | | | | | | Purchased as
| | | Dollar Value of
| | | | | | | | | | Part of Publicly
| | | Shares that may be
| | | | Total Number of
| | | Average Price
| | | Announced Plans
| | | Purchased Under the
| | For the Year Ended December 31, 2008 | | Shares Purchased | | | Paid per Share | | | or Programs | | | Plans or Programs | | | First quarter | | | 1,281,600 | | | $ | 42.73 | | | | 1,281,600 | | | $ | 160,008,401 | | Second quarter | | | — | | | | — | | | | — | | | | 160,008,401 | | Third quarter | | | 3,410,283 | | | | 38.06 | | | | 3,410,283 | | | | 30,226,541 | | Fourth quarter | | | — | | | | — | | | | — | | | | 30,226,541 | | | | | | | | | | | | | | | | | | | Total for 2008 | | | 4,691,883 | | | $ | 39.33 | | | | 4,691,883 | | | $ | 30,226,541 | | | | | | | | | | | | | | | | | | |
In December 2007, the Company initiated its 2008 Capital Allocation Plan, discussed in Item 15 — Note 13,Capital Structure,with the repurchase of 2,037,700 shares of NRG common stock during that month for approximately $85 million. In February 2008, the Company’s Board of Directors authorized an additional $200 million in common share repurchases that would raise the total 2008 Capital Allocation Plan to approximately
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$300 million. In the first quarter 2008, the Company repurchased 1,281,600 shares of NRG common stock for approximately $55 million. In the third quarter 2008, the Company repurchased an additional 3,410,283 of NRG common stock in the open market for approximately $130 million.ESPP. As of December 31, 2008, NRG had repurchased a total of 6,729,5832009, there were 418,468 shares of NRG commontreasury stock at a cost of approximately $270 million as part of its 2008 Capital Allocation Plan. On October 30, 2008, the Company announced its 2009 Capital Allocation Plan to purchase an additional $300 million in common stock. Share repurchasereserved for issuance under the Capital Allocation Plans may be made from time to time at market prices as permitted by securities laws and other requirements, are subject to market conditions and other factors, and may be discontinued at any time.
Securities Authorized for Issuance under Equity Compensation Plans
| | | | | | | | | | | | | | | | | | | | | (c)
| | | | | | | (b)
| | | Number of Securities
| | | | (a)
| | | Weighted-Average Exercise
| | | Remaining Available
| | | | Number of Securities
| | | Price of Outstanding
| | | for Future Issuance
| | | | to be Issued Upon
| | | Options, Warrants and
| | | Under Compensation
| | | | Exercise of
| | | Rights (Excluding
| | | Plans (Excluding
| | | | Outstanding Options,
| | | Securities Reflected in
| | | Securities Reflected
| | Plan Category | | Warrants and Rights | | | Column (a) | | | in Column (a)) | | | Equity compensation plans approved by security holders | | | 6,650,080 | | | $ | 25.84 | | | | 6,798,074 | (a) | Equity compensation plans not approved by security holders | | | — | | | | N/A | | | | — | | | | | | | | | | | | | | | Total | | | 6,650,080 | | | $ | 25.84 | | | | 6,798,074 | | | | | | | | | | | | | | |
| | | (a) | | Consists of NRG Energy, Inc.’s Long-Term Incentive Plan, or the LTIP, and NRG Energy, Inc.’s Employee Stock Purchase Plan, or the ESPP. The LTIP became effective upon the Company’s emergence from bankruptcy. The LTIP was subsequently approved by the Company’s stockholders on August 4, 2004 and was amended on April 28, 2006 to increase the number of shares available for issuance to 16,000,000, on a post-split basis, and again on December 8, 2006 to make technical and administrative changes. The LTIP provides for grants of stock options, stock appreciation rights, restricted stock, performance units, deferred stock units and dividend equivalent rights. NRG’s directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the LTIP. The purpose of the LTIP is to promote the Company’s long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company’s success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the LTIP. There were 6,798,074 and 7,941,758 shares of common stock remaining available for grants of awards under NRG’s LTIP as of December 31, 2008 and 2007, respectively. The ESPP was approved by the Company’s stockholders on May 14, 2008. There were 500,000 shares reserved from the Company’s treasury shares for the ESPP. There were 500,000 shares remaining under the ESPP as of December 31, 2008. In January 2009, 41,706ESPP. In January 2010, 54,845 shares were issued to employees accounts from the treasury stock reserve for the ESPP. |
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Stock Performance Graph The performance graph below compares NRG’s cumulative total shareholder return on the Company’s common stock for the period January 2,December 31, 2004, through December 31, 20082009, with the cumulative total return of the Standard & Poor’s 500 Composite Stock Price Index, or S&P 500, and the Philadelphia Utility Sector Index, or UTY. Upon the Company’s emergence from bankruptcy on December 5, 2003 until March 24, 2004 NRG’s common stock traded on the Over-The-Counter Bulletin Board. On March 25, 2004, NRG’s common stock commenced tradingtrades on the New York Stock Exchange under the symbol “NRG”. The performance graph shown below is being provided as furnished and compares each period assuming that $100 was invested on January 2,December 31, 2004, in each of the common stock of NRG, the stocks included in the S&P 500 and the stocks included in the UTY, and that all dividends were reinvested. Comparison of Cumulative Total Return | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dec-2004 | | Dec-2005 | | Dec-2006 | | Dec-2007 | | Dec-2008 | | Dec-2009 | | | | Jan-2004 | | | | Dec-2004 | | | | Dec-2005 | | | | Dec-2006 | | | | Dec-2007 | | | | Dec-2008 | | NRG Energy, Inc. | | | $ | 100.00 | | | | $ | 160.58 | | | | $ | 209.89 | | | | $ | 249.49 | | | | $ | 386.10 | | | | $ | 207.84 | | | $ | 100.00 | | | $ | 130.71 | | | $ | 155.37 | | | $ | 240.44 | | | $ | 129.43 | | | $ | 130.98 | | S&P 500 | | | | 100.00 | | | | | 111.22 | | | | | 116.68 | | | | | 135.11 | | | | | 142.53 | | | | | 89.80 | | | | 100.00 | | | | 104.91 | | | | 121.48 | | | | 128.16 | | | | 80.74 | | | | 102.11 | | UTY | | | $ | 100.00 | | | | $ | 126.23 | | | | $ | 149.50 | | | | $ | 179.67 | | | | $ | 213.76 | | | | $ | 155.45 | | | $ | 100.00 | | | $ | 118.43 | | | $ | 142.34 | | | $ | 169.34 | | | $ | 123.15 | | | $ | 135.51 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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| | Item 65 — | Selected Financial Data |
The following table presents NRG’s historical selected financial data. The data included in the following table has been restated to reflect the assets, liabilities and results of operations of certain projects that have met the criteria for treatment as discontinued operations as well as the retroactive effect of thetwo-for-one stock split effective May 25, 2007. For additional information refer to Item 1514 — Note 3,4,Discontinued Operations Business Acquisition and DispositionDispositions, to the Consolidated Financial Statements. This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item 1514 and Item 7,6,Management’s Discussion and Analysis of Financial Condition and Results of Operations. | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2008 | | | 2007 | | | 2006 | | | 2005 | | | 2004 | | | | (In millions unless otherwise noted) | | | Statement of income data: | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 6,885 | | | $ | 5,989 | | | $ | 5,585 | | | $ | 2,400 | | | $ | 2,080 | | Total operating costs and expenses | | | 5,156 | | | | 5,060 | | | | 4,720 | | | | 2,290 | | | | 1,848 | | Income from continuing operations, net | | | 1,016 | | | | 569 | | | | 543 | | | | 68 | | | | 157 | | Income from discontinued operations, net | | | 172 | | | | 17 | | | | 78 | | | | 16 | | | | 29 | | Net income | | | 1,188 | | | | 586 | | | | 621 | | | | 84 | | | | 186 | | Common share data: | | | | | | | | | | | | | | | | | | | | | Basic shares outstanding — average | | | 235 | | | | 240 | | | | 258 | | | | 169 | | | | 199 | | Diluted shares outstanding — average | | | 275 | | | | 288 | | | | 301 | | | | 171 | | | | 201 | | Shares outstanding — end of year | | | 234 | | | | 237 | | | | 245 | | | | 161 | | | | 174 | | Per share data: | | | | | | | | | | | | | | | | | | | | | Income from continuing operations — basic | | | 4.09 | | | | 2.14 | | | | 1.90 | | | | 0.28 | | | | 0.78 | | Income from continuing operations — diluted | | | 3.66 | | | | 1.95 | | | | 1.78 | | | | 0.28 | | | | 0.78 | | Net income — basic | | | 4.82 | | | | 2.21 | | | | 2.21 | | | | 0.38 | | | | 0.93 | | Net income — diluted | | | 4.29 | | | | 2.01 | | | | 2.04 | | | | 0.38 | | | | 0.93 | | Book value | | | 26.69 | | | | 19.48 | | | | 19.48 | | | | 11.31 | | | | 13.14 | | Business metrics: | | | | | | | | | | | | | | | | | | | | | Cash flow from operations | | $ | 1,434 | | | $ | 1,517 | | | $ | 408 | | | $ | 68 | | | $ | 645 | | Liquidity position | | | 4,124 | (a) | | | 2,715 | | | | 2,227 | | | | 758 | | | | 1,600 | | Ratio of earnings to fixed charges | | | 3.62 | | | | 2.28 | | | | 2.38 | | | | 1.57 | | | | 1.93 | | Ratio of earnings to fixed charges and preference dividends | | | 3.17 | | | | 2.02 | | | | 2.09 | | | | 1.32 | | | | 1.92 | | Return on equity | | | 16.71 | % | | | 10.65 | % | | | 10.98 | % | | | 3.77 | % | | | 6.91 | % | Ratio of debt to total capitalization | | | 47.57 | % | | | 55.70 | % | | | 57.38 | % | | | 44.91 | % | | | 44.57 | % | Balance sheet data: | | | | | | | | | | | | | | | | | | | | | Current assets | | $ | 8,492 | | | $ | 3,562 | | | $ | 3,083 | | | $ | 2,197 | | | $ | 2,119 | | Current liabilities | | | 6,581 | | | | 2,277 | | | | 2,032 | | | | 1,357 | | | | 1,090 | | Property, plant and equipment, net | | | 11,545 | | | | 11,320 | | | | 11,546 | | | | 2,559 | | | | 2,639 | | Total assets | | | 24,808 | | | | 19,274 | | | | 19,436 | | | | 7,467 | | | | 7,906 | | Long-term debt, including current maturities and capital leases | | | 8,168 | | | | 8,361 | | | | 8,726 | | | | 2,456 | | | | 3,220 | | Total stockholders’ equity | | $ | 7,109 | | | $ | 5,504 | | | $ | 5,658 | | | $ | 2,231 | | | $ | 2,692 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | | | | | | | (In millions unless otherwise noted) | | | Statement of income data: | | | | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 8,952 | | | $ | 6,885 | | | $ | 5,989 | | | $ | 5,585 | | | $ | 2,400 | | | | | | Total operating costs and expenses | | | 7,283 | | | | 5,119 | | | | 5,073 | | | | 4,724 | | | | 2,290 | | | | | | Income from continuing operations, net | | | 941 | | | | 1,053 | | | | 556 | | | | 539 | | | | 68 | | | | | | Income from discontinued operations, net | | | — | | | | 172 | | | | 17 | | | | 78 | | | | 16 | | | | | | Net income attributable to NRG Energy, Inc. | | | 942 | | | | 1,225 | | | | 573 | | | | 617 | | | | 84 | | | | | | Common share data: | | | | | | | | | | | | | | | | | | | | | | | | | Basic shares outstanding — average | | | 246 | | | | 235 | | | | 240 | | | | 258 | | | | 169 | | | | | | Diluted shares outstanding — average | | | 271 | | | | 275 | | | | 288 | | | | 301 | | | | 171 | | | | | | Shares outstanding — end of year | | | 254 | | | | 234 | | | | 237 | | | | 245 | | | | 161 | | | | | | Per share data: | | | | | | | | | | | | | | | | | | | | | | | | | Income attributable to NRG from continuing operations — basic | | | 3.70 | | | | 4.25 | | | | 2.09 | | | | 1.89 | | | | 0.28 | | | | | | Income attributable to NRG from continuing operations — diluted | | | 3.44 | | | | 3.80 | | | | 1.90 | | | | 1.76 | | | | 0.28 | | | | | | Net income attributable to NRG — basic | | | 3.70 | | | | 4.98 | | | | 2.16 | | | | 2.19 | | | | 0.38 | | | | | | Net income attributable to NRG — diluted | | | 3.44 | | | | 4.43 | | | | 1.96 | | | | 2.02 | | | | 0.38 | | | | | | Book value | | | 29.72 | | | | 26.75 | | | | 19.55 | | | | 19.60 | | | | 11.31 | | | | | | Business metrics: | | | | | | | | | | | | | | | | | | | | | | | | | Cash flow from operations | | $ | 2,106 | | | $ | 1,479 | | | $ | 1,517 | | | $ | 408 | | | $ | 68 | | | | | | Liquidity position (a) | | | 3,971 | | | | 4,124 | | | | 2,715 | | | | 2,227 | | | | 758 | | | | | | Ratio of earnings to fixed charges | | | 3.27 | | | | 3.65 | | | | 2.24 | | | | 2.36 | | | | 1.57 | | | | | | Ratio of earnings to fixed charges and preference dividends | | | 3.04 | | | | 3.19 | | | | 1.99 | | | | 2.08 | | | | 1.32 | | | | | | Return on equity | | | 12.24 | % | | | 17.20 | % | | | 10.38 | % | | | 10.85 | % | | | 3.77 | % | | | | | Ratio of debt to total capitalization | | | 43.49 | % | | | 47.50 | % | | | 55.58 | % | | | 57.18 | % | | | 44.91 | % | | | | | Balance sheet data: | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | $ | 6,208 | | | $ | 8,492 | | | $ | 3,562 | | | $ | 3,083 | | | $ | 2,197 | | | | | | Current liabilities | | | 3,762 | | | | 6,581 | | | | 2,277 | | | | 2,032 | | | | 1,357 | | | | | | Property, plant and equipment, net | | | 11,564 | | | | 11,545 | | | | 11,320 | | | | 11,546 | | | | 2,559 | | | | | | Total assets | | | 23,378 | | | | 24,808 | | | | 19,274 | | | | 19,436 | | | | 7,467 | | | | | | Long-term debt, including current maturities and capital leases | | | 8,418 | | | | 8,161 | | | | 8,346 | | | | 8,698 | | | | 2,456 | | | | | | Total stockholders’ equity | | $ | 7,697 | | | $ | 7,123 | | | $ | 5,519 | | | $ | 5,686 | | | $ | 2,231 | | | | | |
N/A — Not applicable | | | (a) | | Includes FundsLiquidity position is determined as disclosed in Item 6, Liquidity and Capital Resources, Liquidity Position. It includes funds deposited by counterparties of $177 million and $754 million as of December 31, 2009 and 2008, respectively, which represents cash held as collateral from hedge counterparties in support of energy risk management activities and for which itactivities. It is the Company’s intention as of December 31, 2008 to limit the use of these funds.funds for repayment of the related current liability for collateral received in support of energy risk management activities. |
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The following table provides the details of NRG’s operating revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | 2005 | | 2004 | | | 2009 | | 2008 | | 2007 | | 2006 | | 2005 | | | | (In millions) | | | (In millions) | | | Energy | | $ | 4,519 | | | $ | 4,265 | | | $ | 3,155 | | | $ | 1,840 | | | $ | 1,181 | | | $ | 3,031 | | | $ | 4,519 | | | $ | 4,265 | | | $ | 3,155 | | | $ | 1,840 | | Capacity | | | 1,359 | | | | 1,196 | | | | 1,516 | | | | 563 | | | | 612 | | | | 1,030 | | | | 1,359 | | | | 1,196 | | | | 1,516 | | | | 563 | | Retail revenue | | | | 4,440 | | | | — | | | | — | | | | — | | | | — | | Risk management activities | | | 418 | | | | 4 | | | | 124 | | | | (292 | ) | | | 61 | | | | 418 | | | | 418 | | | | 4 | | | | 124 | | | | (292) | | Contract amortization | | | 278 | | | | 242 | | | | 628 | | | | 9 | | | | (6 | ) | | | (179 | ) | | | 278 | | | | 242 | | | | 628 | | | | 9 | | Thermal | | | 114 | | | | 125 | | | | 124 | | | | 124 | | | | 112 | | | | 100 | | | | 114 | | | | 125 | | | | 124 | | | | 124 | | Hedge Reset | | | — | | | | — | | | | (129 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (129 | ) | | | — | | Other | | | 197 | | | | 157 | | | | 167 | | | | 156 | | | | 120 | | | | 112 | | | | 197 | | | | 157 | | | | 167 | | | | 156 | | | | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 6,885 | | | $ | 5,989 | | | $ | 5,585 | | | $ | 2,400 | | | $ | 2,080 | | | $ | 8,952 | | | $ | 6,885 | | | $ | 5,989 | | | $ | 5,585 | | | $ | 2,400 | | | | | | | | | | | | | | | | | | | | | | | | |
Energy revenue consists of revenues received from third parties for sales in the day-ahead and real-time markets, as well as bilateral sales. Beginning in 2006, energy revenues also included revenues from the settlement of financial instruments that qualify for cash flow hedge accounting treatment. Capacity revenue consists of revenues received from a third party at either the market or negotiated contract rates for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Capacity revenues also included revenues from the settlement of financial instruments that qualify for cash flow hedge accounting treatment. In addition, capacity revenue includes revenue received under tolling arrangements, which entitle third parties to dispatch NRG’s facilities and assume title to the electrical generation produced from that facility. Retail revenue, representing operating revenue of Reliant Energy, consists of revenues from retail electric sales to residential, small business, commercial, industrial and governmental/institutional customers, as well as revenues from the sale of excess supply into various markets in Texas. Risk management activities includes fair value changes of economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges and trading activities. It also includes the settlement of all derivative transactions that do not qualify for cash flow hedge accounting treatment. Prior to 2006, risk management activities included the settlement of financial instruments that qualified for cash flow hedge accounting treatment. Thermal revenue consists of revenues received from the sale of steam, hot and chilled water generally produced at a central district energy plant and sold to commercial, governmental and residential buildings for space heating, domestic hot water heating and air conditioning. It also includes the sale of high-pressure steam produced and delivered to industrial customers that is used as part of an industrial process. Contract amortization revenues consists of acquired power contracts, gas swaps, and certain power sales agreements assumed at Fresh Start and Texas Genco purchase accounting dates related to the sale of electric capacity and energy in future periods, which are amortized into revenue over the term of the underlying contracts based on actual generation or contracted volumes. Also included is amortization of the intangible asset for net in-market C&I contracts that was established in connection with the acquisition of Reliant Energy. Hedge Reset is the impact from the net settlement of long-term power contracts and gas swaps by negotiating prices to current market. This transaction was completed in November 2006. See also Item 15 — Note 5,Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements for a further discussion. Other revenue primarily consists of operations and maintenance fees, or O&M fees, construction management services, or CMA fees, sale of natural gas and emission allowances, and revenue from ancillary services. O&M fees consist of revenues received from providing certain unconsolidated affiliates with services under long-term operating agreements. CMA fees are earned where NRG provides certain management and oversight of construction projects pursuant to negotiated agreements such as for the GenConn and Cedar Bayou 4 construction projects. Ancillary services are comprised of the sale of energy-related products associated with the generation of electrical energy such as spinning reserves, reactive power and other similar products. 68
| | Item 76 — | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
In this discussion and analysis, the Company discusses and explains theits financial condition and the results of operations, for NRG for the year ended December 31, 2008 that will include the points below:including: | | | | • | Factors which affect NRG’s business; | | | • | NRG’s earnings and costs in the periods presented; | | | • | Changes in earnings and costs between periods; | | | • | Impact of these factors on NRG’s overall financial condition; | | | • | A discussion of new and ongoing initiatives that may affect NRG’s future results of operations and financial condition; | | | • | Expected future expenditures for capital projects; and | | | • | Expected sources of cash for future operations and capital expenditures. |
As you read this discussion and analysis, refer to NRG’s Consolidated Statements of Operations, which presents the results of the Company’s operations for the years ended December 31, 2009, 2008 2007 and 2006.2007. The Company analyzes and explains the differences between the periods in the specific line items of NRG’s Consolidated Statements of Operations. This discussion and analysis has been organized as follows: | | | | • | Business strategy; | | | • | BusinessExecutive Summary, including introduction and overview, business strategy, and the business environment in which NRG operates including how regulation, weather, and other factors affect the business; | | | • | Significant events that are important to understanding the results of operations and financial condition; | | | • | Results of operations includingbeginning with an overview of the Company’s results, followed by a more detailed review of those results by operating segment; | | | • | Financial condition addressing its credit ratings, liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; and | | | • | Critical accounting policies which are most important to both the portrayal of the Company’s financial condition and results of operations, and which require management’s most difficult, subjective or complex judgment. |
Executive Summary Overview NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the United States.U.S., as well as a major retail electricity franchise in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the regional markets in the United StatesU.S. and select international markets, where its generating assets are located.and the supply of electricity and energy services to retail electricity customers in the Texas market. As of December 31, 2008,2009, NRG had a total global generation portfolio of 189187 active operating fossil fuel and nuclear generation units, at 4844 power generation plants, with an aggregate generation capacity of approximately 24,00524,115 MW, and approximately 550400 MW under construction which includes partners’partner interests of 275200 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in twooperating renewable facilities with an aggregate generation capacity of 365 MW, consisting of three wind farms representing an aggregate generation capacity of 270345 MW which(which includes partner interestsinterest of 75 MW) and a solar facility with an aggregate generation capacity of 20 MW. Within the US,U.S., NRG has one of the largestlarge and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,92523,110 MW of fossil fuel and nuclear generation capacity in 177179 active generating units at 43 plants and ownership interests in two wind farms representing 195 MW of wind generation capacity. These42 plants. The Company’s power generation facilities are primarily locatedmost heavily concentrated in Texas (approximately 11,01011,340 MW, including the 195345 MW from the twothree wind farms), the Northeast (approximately 7,0207,015 MW), South Central (approximately 2,8452,855 MW), and West (approximately 2,130 MW)2,150 MW, including 20 MW from a solar farm) regions of the US, andU.S., with approximately 115 MW of additional generation capacity from the Company’s thermal assets. In addition, through certain foreign subsidiaries, NRG has investments in power generation projects located in Australia and Germany with approximately 1,005 MW of generation capacity. 69
NRG’s principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and windrenewable facilities, representing approximately 45%46%, 33%32%, 16%, 5% and 1% of the Company’s total domestic generation capacity, respectively. In addition, 15%9% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option. NRG’s domestic generation facilities consist of intermittent, baseload, intermediate and peaking power generation facilities, the ranking of which is referred to as the Merit Order, and include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s revenues and provides a stable source of cash flow. In addition, NRG’s generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability. On May 1, 2009, NRG acquired Reliant Energy, which is the second largest electricity provider to Mass customers in Texas. Reliant Energy is also the largest electricity and energy services provider, based on load, to C&I customers in Texas. Based on metered locations, as of December 31, 2009, Reliant Energy had approximately 1.5 million Mass customers and approximately 0.1 million C&I customers. Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service. NRG’s Business Strategy NRG’s business strategy is designedintended to enhancemaximize shareholder value through production and the Company’s position as a leading wholesalesale of safe, reliable and affordable power generation companyto its customers and in the US. NRG will continue to utilize its asset base as a platform for growth and development and as a source of cash flow generation which can be usedmarkets served by the Company, while aggressively pursuing sustainable energy solutions for the return of capital to debt and equity holders. future. The Company’s strategy is focused on: (i) top decile operating performance of its existing operating assets and enhanced operating performance of the Company’s commercial operations and hedging program; (ii) repowering of power generation assets at existing sites and development of new power generation projects; (iii) empowering retail customers with distinctive products and (iii) investmentservices that transform how they use, manage and value energy; (iv) engaging in a proactive capital allocation plan focused on achieving the regular return of capital to stockholders within the dictates of prudent balance sheet management; and (v) pursuit of selective acquisitions, joint ventures, divestitures and investments in energy-related new businesses and new technologies where such investments create lowin order to no carbon. enhance the Company’s asset mix and competitive position in the its core markets, as well as increasing demand for sustainable energy lifestyles and combating climate change. This strategy is supported by the Company’s five major initiatives (FORNRG,RepoweringNRG, econrg, Future NRG and NRG Global Giving) which are designed to enhance the Company’s competitive advantages in these strategic areas and allowenable the Company to surmountconvert the challenges faced by the power industry in the coming years.years into opportunities for financial growth. This strategy is being implemented by focusing on the following principles: Operational Performance— The Company is focused on increasing value from its existing assets. Through theFORNRG 2.0 initiative, NRG will continue its companywide effort to focus on extracting value from its portfolio by improving plant performance, reducing costs and harnessing the Company’s advantages of scale in the procurement of fuels and other commodities, parts and services, and in doing so improving the Company’s return on invested capital, or ROIC.FORNRG is a companywide effort designed to increase ROIC through operational performance improvements to the Company’s asset fleet, along with a range of initiatives at plants and at corporate offices to reduce costs, or in some cases, monetize or reduce excess working capital and other assets. TheFORNRG accomplishments include both recurring and one-time improvements measured from a prior base year. For plant operations, the program measures cumulative current year benefits using current gross margins multiplied by the change in baseline levels of certain key performance indicators. The plant performance benefits include both positive and negative results for plant reliability, capacity, heat rate and station service. In addition to theFORNRG initiative, the Company seeks to maximize profitability and manage cash flow volatility through the Company’s commercial operations strategy. The Company will continue to executestrategy by leveraging its: (i) expertise in marketing power and ancillary services; (ii) its knowledge of markets; (iii) its balanced financial structure; and (iv) its diverse portfolio of power generation assets in the execution of asset-based risk management, hedging, marketing and trading strategies within well-defined risk and liquidity guidelines in order to manage the value of the Company’s physical and contractual assets.guidelines. The Company’s marketing and hedging philosophy is centered on generating stable returns from its portfolio of baseload power generation assets while preserving an ability to capitalize on strong spot market conditions and to capture the extrinsic value of the Company’s intermediate and peaking facilities and portions of its baseload fleet. 70
The Company also seeks to achieve synergies between the Company’s retail and wholesale business in Texas through its complementary generation portfolio in the Texas region, thereby creating the potential for a more stable, reliable and competitive business that benefits Texas consumers. By backing Reliant Energy’s load-serving requirements with NRG’s generation and risk management practices, the need to sell and buy power from other financial institutions and intermediaries that trade in the ERCOT market may be reduced, resulting in reduced transaction costs, credit exposures, and collateral postings. In addition, with Reliant Energy’s base of retail customers, NRG believesnow has a customer interface with the scale that it can successfully execute this strategy by leveraging its (i) expertise in marketing poweris important to the successful deployment of consumer facing energy technologies and ancillary services, (ii) its knowledge of markets, (iii) its balanced financial structure and (iv) its diverse portfolio of power generation assets.services. Finally, NRG remains focused on cash flow and maintaining appropriate levels of liquidity, debt and equity in order to ensure continued access, through all economic and financial cycles, to capital for investment, to enhance risk-adjusted returns and to provide flexibility in executing NRG’s business strategy, during business downturns, including a regular return of capital to its shareholders. NRG will continue to focus on maintaining operationaldebt and financial controls designed to ensure that the Company’s financial position remains strong.equity holders.
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Development— NRG is favorably positioned to pursue growth opportunities through expansion of its existing generating capacity and development of new generating capacity at its existing facilities.facilities, as well as “clean” coal and the retrofit of post-combustion carbon capture technologies. Primarily through theRepoweringNRG and econrg initiatives, NRG intends to invest in its existing assets through plant improvements, repowerings, brownfield development and site expansions to meet anticipated requirements for additional capacity in NRG’s core markets. Through theRepoweringNRGinitiative, NRG will continue to develop, construct and operate new and enhanced power generation facilities at its existing sites,markets, with an emphasis on new baseload capacity that is supported by long-term power sales agreements and financed with limited or non-recourse project financing.financing, and the demonstration and deployment of “green” technologies.RepoweringNRG is a comprehensive portfolio redevelopment program designed to develop, construct and operate new multi-fuel, multi-technology, highly efficient and environmentally responsible generation capacity over the next decade. Through this initiative,in locations where the Company anticipates retiring certain existing units and adding new generation to meet growing demand in the Company’s core markets, with an emphasis on new capacitymarkets. econrg represents NRG’s commitment to environmentally responsible power generation by addressing the challenges of climate change, clean air and water, and conservation of our natural resources while taking advantage of business opportunities that is expectedmay inure to be supported by long-term hedging programs, including PPAs, and financed with limited or non-recourse project financing.NRG. NRG expects that these efforts will provide onesome or moreall of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; an improved ability to dispatch economically across the regional general portfolio; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have near zero greenhouse gas, or GHG emissions or can be equipped to capture and sequester GHG emissions. In addition, several of the Company’s originalRepoweringNRG projects or projects commenced under that initiative since its inception may qualify for financial support under the infrastructure financing component of the American Recovery and Reinvestment Act as well as other government incentive packages. NRG has several applications pending or contemplated. New Businesses and New Technology— NRG is focused on the development and investment in energy-related new businesses and new technologies, including low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, and photovoltaic, as well as other endeavors where the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company, including low or no GHG emitting energy generating sources, such as nuclear,smart meters, electric vehicle ecosystems, and distributed “clean” solutions. The Company has made a series of recent advancements in these initiatives, including: (i) the acquisition of Bluewater Wind, an offshore wind development company; (ii) the acquisition of Blythe Solar, the largest photovoltaic solar thermal, photovoltaic, “clean” coal and gas,power facility in California; (iii) the commercial operation of the Langford Wind Farm, the Company’s third wind farm to be brought online; (iv) a partnership between Reliant Energy and the employmentCity of post-combustion carbon capture technologies. In 2008,Houston and a partnership between Reliant Energy and Nissan to make Houston, Texas a launch city for the Company began to increase its focus on ways to invest in or supportuse of electric vehicles; and (v) the developmentuse of new energy-related businesses and technologies that could advance its multi-fuel, multi-technology growth strategy and look“smart” meters for new ways to reduce carbon emissions from its overall fleet, and we expect to continue to do so in the future.Reliant Energy customers. Furthermore, the Company, supported by the econrg initiative, intends to capitalize on the high growth opportunities presented by government-mandated renewable portfolio standards, tax incentives and loan guaranties for renewable energy projects, and new technologies and expected future carbon regulation. A primary focus of this strategy is supported by theeconrginitiative whereby NRG is pursuing investments in new generating facilities and technologies that will be highly efficient and will employ no and low carbon technologies to limit CO2 emissions and other air emissions. econrg represents NRG’s commitment to environmentally responsible power generation by addressing the challenges of climate change, clean air and water, and conservation of our natural resources while taking advantage of business opportunities that may inure to NRG as a result of our demonstration and deployment of “green” technologies. Within NRG, econrg builds upon a foundation in environmental compliance and embraces environmental initiatives for the benefit of our communities, employees and shareholders, such as encouraging investment in new environmental technologies, pursuing activities that preserve and protect the environment and encouraging changes in the daily lives of the Company’s employees. Company-Wide Initiatives— In addition, the Company’s overall strategy is also supported byFuture NRGandNRG Global Givinginitiatives. Future NRG is the Company’s workforce planning and development initiative and represents NRG’s strong commitment to planning for future staffing requirements to meet the on-going needs of the Company’s current operations in addition to the Company’sRepoweringNRGand initiatives. Future NRG encompasses analyzing the demographics, skill set and size of the Company’s workforce in addition to the organizational structure with a focus on succession planning, training, development, staffing and recruiting needs. Included under the Future NRG umbrella is NRG University, which provides leadership, managerial, supervisory and technical training programs and individual skill development courses. NRG Global Giving is designed to enhance respect for the community, which is one of NRG’s core values. OurThe Global Giving Program invests NRG’s resources to strengthen 71
the communities where we doNRG does business and seeks to make community investments in four focus areas: community and economic development, education, environment and human welfare. Finally, NRG will continue to pursue selective acquisitions, joint ventures and divestitures to enhance its asset mix and competitive position in the Company’s core markets. NRG intends to concentrate on opportunities that present attractive risk-adjusted returns. NRG will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures.
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Business Environment General Industry — Trends impacting the power industry includeinclude: (i) the continued constrainedfinancial credit and capital markets along with deepening recessionary environment,market availability; and (ii) increased regulatory and political scrutiny. The industry dynamics and external influences that will affect the Company and the power generation industry in 20092010 and for the medium term include: Financial Credit Market Availability and Domestic Recession —A sharp economic downturn in the US and overseas during 2008 was prompted by a combination of factors: tight credit markets, speculation and fear regarding the health of the US and global financial systems, and weaker economic activity including a global economic recession. Power generation companies are capital intensive and, as such, rely on the credit markets for liquidity and for the financing of power generation investments. In addition, economic recessions historically result in lower power demand, power prices, and fuel prices. NRG has a diversified liquidity program, with $3.4 billion in total liquidity, excluding funds deposited by counterparties, and a first and second lien structure that enables significant strategic hedging while reducing requirements for the posting of cash or letters of credit as collateral. NRG expects to continue to manage commodity price volatility through its strategic hedging program, under which the Company expects to hedge revenues and fuel costs. This program should provide the Company with the flexibility to enter into hedges opportunistically, such as when gas prices are increasing, while at the same time protecting NRG against longer-term volatility in the commodity markets. The Company believes that an economic recession is unlikely to have material impact on the Company’s cash generation in the near term due to the hedged position of its portfolio. NRG transacts with a diversified pool of counterparties and actively manages our exposure to any single counterparty. See also Part II, Item 7 — Liquidity and Capital Resources, and Part II, Item 7a — Quantitative and Qualitative Disclosures about Market Risk for a further discussion.
Consolidation — Over the long-term, industry consolidation is expected to occur, with mergers and acquisitions activity in the power generation sector likely to involve utility-merchant or merchant-merchant combinations. There may also be interest by foreign power companies, particularly European utilities, in the American power generation sector. Financial Credit Market Availability — Power generation companies are capital intensive and, as such, rely on the credit markets for liquidity and for the financing of power generation investments. In addition, economic recessions historically result in lower power demand, power prices, and fuel prices. During 2009, the nation’s credit markets recovered to some extent although credit continued to be tight relative to years prior to 2008. As evidence of the markets’ improvement, in April 2009, GenConn Energy, a joint venture of NRG and the United Illuminating Company, closed on a $534 million project financing and NRG was able to issue $700 million of bonds in June 2009, with a10-year maturity at a yield to maturity of 8.75%. In addition, NRG had arranged a Credit Sleeve Reimbursement Agreement, or CSRA, with Merrill Lynch to support Reliant Energy after closing the acquisition. NRG has a diversified liquidity program, with $3.8 billion in total liquidity as of December 31, 2009, excluding funds deposited by counterparties, and a first and second lien structure that enables significant strategic hedging while reducing requirements for the posting of cash or letters of credit as collateral. NRG transacts with a diversified pool of counterparties and actively manages the Company’s exposure to any single counterparty. See Part II, Item 6 —Liquidity and Capital Resources, and Part II, Item 6a —Quantitative and Qualitative Disclosures about Market Riskfor a further discussion. The addition of Reliant Energy to NRG’s existing generation business may provide opportunities to match generation to load directly which should reduce hedging and credit costs that both businesses would incur if hedged separately. Reliant Energy, which expects to lock in its wholesale supply in order to secure its margin as load is contracted, should also benefit from having better access to nonstandard and longer term products necessary to meet load. NRG expects to continue hedging its wholesale production consistent with its prior practice, but now will benefit from having an additional outlet for its range of generation products. Climate Change — There isThe U.S. signed the Copenhagen Accord, or the Accord, which sets the stage for a marked shift towards federal actionworldwide approach to address climate change underthis global issue. Under the Obama administration, whichAccord, the U.S. has made clear its intentioncommitted to make climate change policy a priority for the US through legislation, regulation, and global leadership. President Obama reiterated this commitment in his inaugural address. Congressman Waxman, who sees aggressive action17% reduction from 2005 emission levels of GHGs by 2020. While Congress was unable to come to agreement on climate change aslegislation in 2009, the subject continues to be a major priority, was elected chairtopic for consideration in 2010. Lack of legislation will prolong the uncertainty of the House Energynature and Commerce Committeetiming of GHG requirements and announced that a climate change bill would be delivered out of committee before Memorial Day.their resulting impact on NRG. RegionalClimate change efforts have gained momentum as well.continued outside of the legislature. The RGGIcap-and-trade program, in which NRG’s emissions of CO2 cap-and-tradewere 8 million tonnes in 2009, ended its first year with low allowance prices, nearing the reserve floor. This trend is expected to continue in the short term while the region works through the recession and increased use of renewable energy. California continues to develop their program for electric generating units went into effect2012 implementation. In addition to regional efforts, the U.S. EPA moved forward with a finding that GHGs do pose a threat to public health and welfare and light duty tailpipe regulations. These efforts will ultimately trigger the application of existing GHG permitting requirements for new and modified stationary sources like power plants, although the effective date and specifics of implementation lack clarity. The impact to NRG is dependent on January 1, 2009. California, the Western Climate Initiative,timing and implementation of PSD/NSR and Title V permit requirements with regard to GHGs and any future actions taken by the Midwest GHG Accord continue to develop market based programs in their respective jurisdictions.U.S. EPA.
Since fossil fueled power plants, particularly coal-fired plants, are a significant source of GHG emissions both in the US and globally, it is almost certain that future GHG legislative and regulatory actions will encompass power plants as well as other GHG emitting stationary sources. In 2008,2009, in the course of producing approximately 8071 million MWh of electricity, NRG’s power plants emitted 6859 million tonnes of CO2, of which 6153 million tonnes were emitted in the US, 4U.S., 3 million tonnes in Germany and 3 million tonnes in Australia. NRG emissions subject to RGGI were 12 million tonnes in 2008. Federal,The impact from legislation or federal, regional or state or regional regulation of GHG emissions could have a material impact on the Company’s financial performance. The actual impactGHGs on the Company’s financial performance will depend on a number of factors, including the overall level of GHG reductions
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required under any such regulations, the degree to which offsets may be used for compliance and their price and availability of offsets, and the extent to which NRG would be entitled to receive GHGCO2 emissions allowances without having to purchase them in an auction or on the open market. Thereafter, under any such legislation or regulation, the impact on NRG would depend on the Company’s level of success in developing and deploying low and no carbon technologies such as those being pursued as part of theRepoweringNRG. Additionally, NRG’s current contracts with its South Central region’s cooperative customers allows for the recovery of emission-based costs. Environmental Regulatory Landscape — A number of regulations that could significantly impact the power generation industry are in development or under review by the U.S. EPA: CAIR, MACT, NAAQS revisions, coal combustion wastes, once-through cooling, and GHG regulations. While most of these regulations have been considered for some time, they are expected to gain clarity in 2010 through 2011. The timing and stringency of these regulations will provide a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. The Company has included capital to meet anticipated CAIR Phase I and II, MACT standards for mercury, and the installation of “Best Technology Available” under the 316(b) Rule in the current estimated environmental capital expenditure. While the Company cannot predict the impact of future regulations and would likely face additional investments over time, these expenditures, combined with the Company’s multifold strategy, which includes (a) shapingalready existing air quality controls; use of Powder River Basin coal; closed cycle cooling; and dry ash handling systems, position NRG well to meet more stringent requirements. Public Policy Support and Government Financial Incentives — The economic crisis, a changing public policy withenvironment, and the objective being constructivecurrent political climate have led to a shift away from utility investment in traditional fossil-fueled coal and effectivenatural gas-fired capacity and towards investment in non-traditional capacity, including renewable technologies, demand-side resources and nuclear. Generous public support, in the form of tax credits, loan guarantees, depreciation tax benefits, renewable energy credits, or RECs, and various other state and local incentives, are now available to builders of renewable electric generation. State Renewable Portfolio Standards, or RPS, requirements are now “on the books” in 28 states requiring load-serving entities to eventually source large percentages of their supply requirements from renewable sources or by purchasing REC credits, and federal GHG regulatoryrequirements may follow. Designers of capacity markets in the Northeast region have attempted to improve the position of demand side resources relative to peaking capacity by holding these resources to a less stringent deliverability standard. Finally, the threat of carbon policy and (b) pursuing itsRepoweringNRG and econrg programs. The Company’s multifold strategy is discussedhas had a “chilling” effect on new fossil generation supply additions, while encouraging all zero-carbon sources. These developments are likely to increase the role of renewable energy in greater detailthe next energy commodity cycle, driving changes in Item 1,Businessunder Carbon Update.wholesale market dynamics as renewable market share rises.
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Infrastructure Development — In responsethe recent recessionary environment, the U.S. has experienced a contraction in demand, led primarily by reduced industrial demand in the manufacturing, chemical and petrochemical industries. As a result of lower demand and a proliferation of new natural gas supply from shale gas reserves, near term gas and power markets have experienced lower prices thus causing delays and cancellations of new generation supply and transmission investments. The Company expects recovery from the recession could lead to record peakdemand recovery and a trending back toward normalized growth rates spurring the need for additional generation supply. The potential for future federal carbon legislation and more restrictive environmental regulations could cause a rebalancing of the generation sector with older less efficient coal plants risking retirement and new infrastructure capital being deployed into low carbon technology in the form of baseload nuclear, renewable energy projects, and high efficiency (quick start) natural gas units. Government sponsored subsidies in the form of cash grants, investment tax credits and loan guarantees along with improved environmental policy clarity will continue to be crucial to help finance additional generation investment. Natural Gas Market — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Natural gas prices are driven by many variables including demand tightening reserve margins,from industrial, residential; and volatileelectric sectors; productivity across natural gas supply basins; fixed and variable costs of natural gas production; changes in pipeline infrastructure, and the financial and hedging profile of natural gas consumers and producers. In 2009, domestic natural gas supply increased, while demand decreased in the wake of the recession, leading to a fall in natural gas prices experiencedwhen compared to 2008. The increase in recent years,natural gas supply was due to increased production from unconventional resources, particularly the power generation industry has added significant capacity for both transmissionshale basins, and generation. In addition to traditional gas-fired capacity, muchfrom the low variable costs of extraction from these resources. The Company expects rebalancing of the newnatural gas market to 73
continue, and a price recovery could be driven by supply cuts as producer hedges roll-off and variable costs rise above market prices. | | | | | | | | | | | | | | | | | Average Natural Gas Price ($/MMbtu) | | | 2009 | | | 2008 | | | 2007 | | | | | Henry Hub | | $ | 3.92 | | | $ | 8.85 | | | $ | 6.94 | | | |
Electricity Prices — The price of electricity is a key determinant of the profitability of the Company’s generation would be from non-fossil fuel sources, including nuclearportfolio. In 2009, prices for electricity were lower than in 2008, affected by both lower prices for natural gas and renewable sources.lower electric demand due largely to the recession. As general economic conditions improve, NRG expects to see a similar recovery in electric demand. The Energy Policy Actfollowing table summarizes average on-peak power prices for each of 2005 created financial incentivesthe major markets in which NRG operates for non-traditional baseload generation, such as advance nuclearthe years ended December 31, 2009, 2008 and “clean” coal technologies in order to reduce reliance on the more traditional pulverized coal technologies. During 2007, 18 gigawatts of previously announced pulverized coal generation projects were canceled due to increasing public and political concern regarding carbon emissions limiting the pace of development. During 2008, the credit market crisis severely constrained the industry’s ability to finance power projects. Despite the challenges presented by financing availability and carbon legislation constraints, NRG believes the long-term demand for power generation will continue to require new generation.2007. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Average on Peak Power Price ($/MWh) | Region | | | | 2009 | | | | 2008 | | | | 2007 | | | Texas | | $ | | | | | 35.43 | | | $ | | | | | 86.23 | | | $ | | | | | 60.98 | | | | Northeast | | | | | | | 46.14 | | | | | | | | 91.68 | | | | | | | | 76.37 | | | | South Central | | | | | | | 33.58 | | | | | | | | 71.25 | | | | | | | | 59.63 | | | | West | | $ | | | | | 40.10 | | | $ | | | | | 82.20 | | | $ | | | | | 66.46 | | | |
Competition Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. NRG competes on the basis of the location of its plants and owningownership of multiple plants in itsvarious regions, which increases the stability and reliability of its energy supply. Wholesale power generation is basically a local business that is currently highly fragmented relative to other commodity industries and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature, and identity of the companies NRG competes againstwith depending on the market. The deregulated retail energy business in ERCOT is a competitive business. In general, competition in the retail energy business is on the basis of price, service, brand image, product offerings, and market perceptions of creditworthiness. Reliant Energy sells electricity pursuant to fixed price or indexed products, and customers elect terms of service typically ranging from one month to five years. Reliant Energy’s rates are market-based rates, and not subject to traditionalcost-of-service regulation by the PUCT. Non-affiliated transmission and distribution service companies provide, on a non-discriminatory basis, the wires and metering services necessary to access customers. Weather Weather conditions in the different regions of the USU.S. influence the financial results of NRG’s businesses. Weather conditions can affect the supply and demand for electricity and fuels. Changes in energy supply and demand may impact the price of these energy commodities in both the spot and forward markets, which may affect the Company’s results in any given period. Typically, demand for and the price of electricity is higher in the summer and the winter seasons, when temperatures are more extreme. The demand for and price of natural gas and oil are higher in the winter. However, all regions of North America typically do not experience extreme weather conditions at the same time, thus NRG is typically not exposed to the effects of extreme weather in all parts of its business at once. Other Factors A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for NRG’s business. These factors include: | | | | • | seasonal daily and hourly changes in demand; | | | • | extreme peak demands; | | | • | available supply resources; | | | • | transportation and transmission availability and reliability within and between regions; |
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| | | | • | location of NRG’s generating facilities relative to the location of its load-serving opportunities; | | | • | procedures used to maintain the integrity of the physical electricity system during extreme conditions; and | | | • | changes in the nature and extent of federal and state regulations. |
These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in: | | | | • | weather conditions; | | | • | market liquidity; | | | • | capability and reliability of the physical electricity and gas systems; |
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| | | | • | local transportation systems; and | | | • | the nature and extent of electricity deregulation. |
Environmental Matters, Regulatory Matters and Legal Proceedings NRG discusses details of its other environmental matters in Item 1514 — Note 23,24,Environmental Matters, to itsthe Consolidated Financial Statements and Item 1,Business — Environmental Matters,section. NRG discusses details of its regulatory matters in Item 1514 — Note 22,23,Regulatory Matters, to itsthe Consolidated Financial Statements and Item 1,Business — Environmental Matters,section. NRG discusses details of its legal proceedings in Item 1514 — Note 21,22,Commitments and Contingencies, to itsthese Consolidated Financial Statements. Some of this information is about costs that may be material to the Company’s financial results. NINA — On December 30, 2009, NINA had received an estimate from TANE, the prime contractor, containing the overnight estimate of the EPC Cost. The estimate was approximately $11.5 billion for STP Units 3 and 4 with an opportunity to reduce cost subject to certain specification changes. Based on the estimate provided by TANE and the Company’s internal assessments, NINA continues to believe that NRG’s stated target of $9.8 billion or $3,229/kW based on 3,000 MW gross output is achievable. Cost reductions will be achieved through a combination of specification changes and the re-alignment of risks and responsibilities among key project stakeholders. Owners’ Costs for the project, on an escalated basis, are estimated to total approximately $2.1 billion during the construction period. This is primarily comprised of the costs for NRG’s agent STPNOC, owners’ contingency and the initial fuel load. Financing Costs are estimated to be approximately $1.5 billion during the construction period, and are comprised of the variables described above. On February 17, 2010, an agreement in principle was reached with CPS for NINA to acquire a controlling interest in the project to construct STP Units 3 and 4 through a settlement of the litigation between the parties. As part of the agreement, NINA would increase its ownership in the STP Units 3 and 4 project from 50% to 92.375% and would assume full management control of the project. NINA would also pay $80 million to CPS, subject to receipt of a conditional DOE loan guarantee. The first $40 million would be promptly paid after receipt of the guarantee and the other half six months later. An additional $10 million would be donated by NRG over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership in San Antonio. As part of the agreement with CPS, all litigation would be dismissed with prejudice. The parties continue to negotiate terms regarding final documentation of the agreement in principle. The agreement would enable the STP Unit 3 and 4 project expansion to move forward and allow NINA to continuing pursuing its application for a conditional loan guarantee from the DOE. If NINA is not successful in reaching a final agreement with CPS, obtaining a conditional loan guarantee, or selling down its interest in STP Units 3 and 4, there could be negative implications for the project that may result in a reassessment of the probability of success of the project and an impairment of the value of the capitalized assets for STP Units 3 and 4. An impairment would result in a permanentwrite-down of the $299 million ofconstruction-in-progress capitalized through December 31, 2009, plus any amounts capitalized through the impairment date. 75
Impact of inflation on NRG’s results Unless discussed specifically in the relevant segment, for the years ended December 31, 2009, 2008 2007 and 2006,2007, the impact of inflation and changing prices (due to changes in exchange rates) on NRG’s revenues and income from continuing operations was immaterial. Capital Allocation Program NRG’s capital allocation philosophy includes reinvestment in its core facilities, maintenance of prudent debt levels and interest coverage, the regular return of capital to shareholders and investment in repowering opportunities. Each of these components are described further as follows: | | | | • | Reinvestment in existing assets — Opportunities to invest in the existing business, including maintenance and environmental capital expenditures that improve operational performance, ensure compliance with environmental laws and regulations, and expansion projects. | | | • | Management of debt levels — The Company uses several metrics to measure the efficiency of its capital structure and debt balances, including the Company’s targeted net debt to total capital ratio range of 45% to 60% and certain cash flow and interest coverage ratios. The Company intends in the normal course of business to continue to manage its debt levels towards the lower end of the range and may, from time to time, pay down its debt balances for a variety of reasons. | | | • | Return of capital to shareholders — The Company’s debt instruments include restrictions on the amount of capital that can be returned to shareholders. The Company has in the past returned capital to shareholders while maintaining compliance with existing debt agreements and indentures. The Company expects to regularly return capital to shareholders through opportunistic share repurchases, while exploring other prospects to increase its flexibility under restrictive debt covenants. | | | • | Repowering, econrg and new build opportunities — The Company intends to pursue repowering initiatives that enhance and diversify its portfolio and provide a targeted economic return to the Company. |
On October 30, 2008, the Company announced its 2009 Capital Allocation Plan to purchase an additional $300 million in common stock, subject to restrictions under the US securities laws. As part of the 20092010 program, the Company will invest over $511approximately $474 million in maintenance and environmental capital expenditures in the existing assets in 2009 and $256$707 million in investment in projects underRepoweringNRG that are currently under construction or for which there exists current obligations. Finally, in addition to scheduled debt amortization payment, in the first quarter 20092010 the Company will offer its first lien lenders $197$430 million of its 20082009 excess cash flow (as defined in the Senior Credit Facility). of which the Company made a prepayment of $200 million in December 2009.
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Significant events during the year ended December 31, 20082009 Results of Operations and Financial Condition | | | | • | Mark-to-market gainsAcquisition of Reliant Energy— The Company’s risk management activities recognized $414On May 1, 2009, NRG acquired Reliant Energy, which consisted of the entire Texas electric retail business operation of RRI, for cash consideration of $360 million, net of cash acquired. During the eight months ended December 31, 2009, Reliant Energy added $4.4 billion in mark-to-market gains driven by lower energy prices dueretail revenue and $3.5 billion in cost of sales to the downward trend in natural gas prices duringCompany’s results. In addition, NRG incurred non-recurring acquisition-related transaction and integration costs which totaled $54 million for the second half 2008. High price volatility in energy related commodities during 2008 drove the extreme volatility reported in NRG interim results of operations and consolidated balance sheets during the second and third quarters of 2008, due to the commodities’ impact on the fair value of our derivative contracts.eight months ended December 31, 2009. | | | • | Liquidity PositionLower energy revenue— The Company’s total liquidity rose $1.4Energy revenues decreased $1.5 billion as the declininga result of reduced energy prices as well as lower generation. The reduced energy prices were caused by lower average natural gas prices increased funds depositedof approximately 56%. The reduction in generation was driven by counterparties by $754 million. Cash balances grew by $362 million sinceweakened demand for power due to the end of 2007 as $1.4 billion of cash provided by operating activities exceeded cash used for all phases of the Company’s Capital Allocation Program, including $899 million of capital expenditures, $185 million in treasury share payments and a $214 million net debt reduction.recessionary economy. | | | • | Higher energy prices— Energy revenues rose 6% as a result of strong operating performance at the power plants which allowed the Company to sell generation at higher energy prices especially in the second quarter 2008. | | | • | HigherLower capacity revenuesrevenue— Capacity revenues rose $163revenue decreased $329 million as a result of a greaterlower portion of Texas baseload contracts havingin the Texas region containing a capacity component. | | | • | Sale of ITISAHigher selling, general and administrative— On April 28, 2008, NRG completedThe Company’s total selling, general and administrative expense increased in 2009 by $231 million. For the sale of its interest in a 156 MW hydroelectric power plant to Brookfield Renewable Power Inc. The Company recognized a $164eight months ended December 31, 2009, Reliant Energy selling, general and administrative expense totaled $203 million, after tax gain on the sale and received $300including $61 million of cash proceeds. See Item 15 — Note 3,Discontinued Operations,Business Acquisition and Dispositions,for a further discussionbad debt expense. Also included in 2009 results was the non-recurring cost of the activitiesExelon’s exchange offer and proxy contest efforts of ITISA that have been classified as discontinued operations. | | | • | Reduced development costs— As of January 1, 2008, the company began to capitalize the STP units 3 and 4 costs following the docketing of the COLA which resulted in decline of development costs of $52$31 million. | | | • | Lower other incomeLiquidity position— Interest income decreasedThe Company’s total liquidity, excluding collateral received, rose $430 million in 2009. Cash balances grew by $25$810 million since the end of 2008 as $2.1 billion of cash provided by operating activities exceeded cash used including $734 million of capital expenditures, $644 million in debt payments, $500 million in treasury share payments, and $427 million in business acquisitions offset by the resultproceeds from the sale of lower market interest rates on cash deposits. In addition,MIBRAG of $284 million and the Company recorded an impairment chargeproceeds from the issuance of $23 million to restructure distressed investments in commercial paper.debt of $892 million. | | | • | Lower interest expensePurchase of treasury shares— Interest expense decreased $69 million asDuring 2009, the resultCompany repurchased 19,305,500 shares of common stock under its capital allocation plan for a total of $500 million. | | | • | Preferred Stock conversion — On March 16, 2009, all of the outstanding shares of the Company’s 5.75% Preferred Stock were converted into common stock for $447 million. During 2009, a total of 265,870 shares of Company’s 4% Preferred Stock were converted into common stock for $257 million. | | | • | Sale of MIBRAG — In 2009, the Company sold its 50% ownership interest savingsin MIBRAG, to a consortium of Severoćeské doly Chomutov, a member of the CEZ Group, and J&T Group. For its share, NRG received proceeds of $284 million, net of transaction costs and realized a $128 million gain on sale of the $531equity method investment. |
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| | | | • | Issuance of 2019 Senior Notes — In June 2009, NRG completed the issuance of $700 million debt repayments beginningaggregate principal amount of 8.5% Senior Notes due 2019, or 2019 Senior Notes. The Company used a portion of the net proceeds of $678 million to facilitate the early termination of NRG’s obligations pursuant to the CSRA Amendment, which became effective October 5, 2009. | | | • | Merrill Lynch Credit Sleeve Facility — On May 1, 2009, NRG arranged with Merrill Lynch to provide continuing credit support to Reliant Energy after closing the acquisition. In connection with entering into a transitional credit sleeve facility, or CSRA, NRG contributed $200 million of cash to Reliant Energy. In conjunction with the CSRA, NRG Power Marketing LLC, or PML, and Reliant Energy Power Supply LLC, or REPS, modified or novated certain transactions with counterparties to transfer PML’sin-the-money transactions to REPS and moved $522 million of cash collateral held by NRG to Merrill Lynch, thereby reducing Merrill Lynch’s actual and contingent collateral supporting Reliant Energyout-of-money positions. Effective October 5, 2009, the Company then executed the CSRA Amendment. In connection with this transaction, the Company posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued $206 million of letters of credit, and received $45 million of counterparty collateral. In addition, Merrill Lynch returned $250 million of previously posted cash collateral, and released liens on $322 million of unrestricted cash held by Reliant Energy. Upon execution of the CSRA Amendment, the Company was required to post collateral for any net liability derivatives, and other static margin associated with supply for Reliant Energy. | | | • | GenConn LLC related financings — In April 2009, NRG Connecticut Peaking LLC., a wholly-owned subsidiary of NRG, executed an equity bridge loan facility, or EBL, in the amount of $121.5 million from a syndicate of banks. The purpose of the EBL is to fund the Company’s proportionate share of the project construction costs required to be contributed into GenConn. Also in April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a7-year term loan facility, and also entered into a5-year revolving working capital loan and letter of credit facility. The aggregate credit amount secured is $291 million, including $48 million for the revolving facility. In August 2009, GenConn began to draw under the secured financing to cover costs related to the Devon project and as of December 2007 accompanied by a reduction of variable interest rates on long-term debt.31, 2009, has drawn $48 million. |
Other | | | | • | NINA— In March 2008, NRG formed NINA, an NRG subsidiary focused on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned STP units 3 and 4 that NRG is developing on a 50/50 basis with CPS Energy. TANE will serve as the prime contractor on all of NINA’s projects, and has partnered with NRG on the NINA venture, and received a 12% equity ownership in NINA in exchange for a $300 million investment in NINA in six annual installments of $50 million, the first of which was received during 2008 and the last three of which are subject to certain conditions. On February 12,24, 2009, the Company announced that NINA completed negotiations for theexecuted an EPC agreement with TANE to build the STP expansion. Concurrent with the execution of the EPC agreement, NINA will enterentered into a $500 million credit facility with Toshiba to finance the cost of long-lead materials for STP Units 3 and 4. |
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| | • | Cedar Bayou Generating Station — In June 2009, NRG and Optim Energy, LLC, or Optim Energy, completed construction and began commercial operation of a new natural gas-fueled combined cycle generating plant at NRG’s Cedar Bayou Generating Station in Chambers County, Texas. NRG and Optim Energy have a 50/50 undivided interest basis in the 520 MW generating plant. NRG is the operator of the plant and Optim Energy is acting as energy manager for Cedar Bayou unit 4. Cedar Bayou unit 4 is providing the Company a net capacity of 260 MW given NRG’s 50% ownership. | | | • | Langford Wind Project — In December 2009, NRG completed its Langford project, a wholly-owned 150 MW wind farm located in Tom Green, Irion, and Schleicher Counties, Texas. The Company funded and developed this wind farm which consists of 100 General Electric 1.5 MW wind turbines. The project is eligible for a cash grant from the Department of Treasury and NRG has filed an application for an $84 million grant. | | | • | Acquisition and completion of Blythe Solar — On November 20, 2009, NRG acquired through its wholly-owned subsidiary NRG Solar LLC, FSE Blythe 1, LLC, or Blythe Solar, from First Solar, Inc. On December 18, 2009, construction was completed and commercial operation began for the 20 MW utility-scale photovoltaic, or PV, solar facility located in Riverside County in southeastern California. The project is eligible for a cash grant from the Department of Treasury and NRG will file an application for an $18 million grant. | | | • | Unsolicited Exelon Proposal— On October 19, 2008, the Company received an unsolicited proposal from Exelon Corporation to acquire all of the outstanding shares of the Company and on November 12, 2008, Exelon announced a tender offer for all of the Company’s outstanding common stock. On January 7,NRG’s Board of |
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| | | | | Directors, after carefully reviewing the proposal, unanimously concluded that the proposal was not in the best interests of the stockholders and recommended that NRG stockholders not tender their shares. In addition, on June 17, 2009, Exelon extendedfiled a Definitive Proxy Statement with the tender offer to February 25,SEC presenting their proposals for the Company’s 2009 Annual Meeting of Stockholders. NRG’s Board of Directors recommended a vote against each of their proposals. On July 2, 2009, Exelon revised their unsolicited proposal and indicated that further extensions may follow. NRG’s Board of Directors, after carefully reviewing the proposal, unanimously concluded that the proposal was not in the best interests of the stockholders and has recommended that NRG stockholders not tender their shares. In addition, on January 30,On July 21, 2009, Exelon announced a proposed slatestockholders voted to re-elect all of ninethe Company’s director nominees for election to the NRG Board atof Directors and rejected Exelon’s proposals. On July 21, 2009, Exelon Corporation announced that in light of the vote results, effective immediately, it terminated its offer to acquire all of the outstanding shares of NRG. The total defense costs associated with Exelon’s unsolicited proposal was approximately $39 million for the period October 1, 2008, through December 31, 2009, Annual Meeting of Stockholders, together with a proposal to increasewhich $31 million was for the numberyear ended December 31, 2009. |
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Consolidated Results of Operations 2009 compared to 2008 The following table provides selected financial information for NRG Energy, Inc., for the years ended December 31, 2009, and 2008: | | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2009 | | | 2008 | | | Change% | | | | (In millions except otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 3,031 | | | $ | 4,519 | | | | (33 | )% | Capacity revenue | | | 1,030 | | | | 1,359 | | | | (24 | ) | Retail revenue | | | 4,440 | | | | — | | | | N/A | | Risk management activities | | | 418 | | | | 418 | | | | — | | Contract amortization | | | (179 | ) | | | 278 | | | | (164 | ) | Thermal revenue | | | 100 | | | | 114 | | | | (12 | ) | Other revenues | | | 112 | | | | 197 | | | | (43 | ) | | | | | | | | | | | | | | Total operating revenues | | | 8,952 | | | | 6,885 | | | | 30 | | | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of sales | | | 4,524 | | | | 2,641 | | | | 71 | | Risk management activities | | | (338 | ) | | | — | | | | N/A | | Other cost of operations | | | 1,137 | | | | 957 | | | | 19 | | | | | | | | | | | | | | | Total cost of operations | | | 5,323 | | | | 3,598 | | | | 48 | | | | | | | | | | | | | | | Depreciation and amortization | | | 818 | | | | 649 | | | | 26 | | Selling, general and administrative | | | 550 | | | | 319 | | | | 72 | | Acquisition-related transaction and integration costs | | | 54 | | | | — | | | | N/A | | Development costs | | | 48 | | | | 46 | | | | 4 | | | | | | | | | | | | | | | Total operating costs and expenses | | | 6,793 | | | | 4,612 | | | | 47 | | | | | | | | | | | | | | | Operating Income | | | 2,159 | | | | 2,273 | | | | (5 | ) | | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | Equity in earnings of unconsolidated affiliates | | | 41 | | | | 59 | | | | (31 | ) | Gains on sales of equity method investments | | | 128 | | | | — | | | | N/A | | Other (loss)/income, net | | | (5 | ) | | | 17 | | | | (129 | ) | Refinancing expenses | | | (20 | ) | | | — | | | | N/A | | Interest expense | | | (634 | ) | | | (583 | ) | | | 9 | | | | | | | | | | | | | | | Total other expenses | | | (490 | ) | | | (507 | ) | | | (3 | ) | | | | | | | | | | | | | | Income from Continuing Operations before income tax expense | | | 1,669 | | | | 1,766 | | | | (5 | ) | Income tax expense | | | 728 | | | | 713 | | | | 2 | | | | | | | | | | | | | | | Income from Continuing Operations | | | 941 | | | | 1,053 | | | | (9 | ) | Income from discontinued operations, net of income tax expense | | | — | | | | 172 | | | | (100 | ) | | | | | | | | | | | | | | Net Income | | $ | 941 | | | $ | 1,225 | | | | (23 | ) | Less: Net loss attributable to noncontrolling interest | | | (1 | ) | | | — | | | | N/A | | | | | | | | | | | | | | | Net income attributable to NRG Energy, Inc. | | $ | 942 | | | $ | 1,225 | | | | (23 | ) | | | | | | | | | | | | | | Business Metrics | | | | | | | | | | | | | Average natural gas price — Henry Hub ($/MMbtu) | | | 3.92 | | | | 8.85 | | | | (56 | )% |
N/A — Not applicable 79
The table below represents the results of NRG excluding the impact of Reliant Energy during the year ended December 31, 2009: | | | | | | | | | | | | | | | | | | | | | | | Year ended December 31, | | | | 2009 | | | 2008 | | | | | | | | | | Total excluding
| | | | | | | | | | Consolidated | | | Reliant Energy | | | Reliant Energy | | | Consolidated | | | Change% | | | | (In millions) | | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | Energy revenue | | $ | 3,031 | | | $ | — | | | $ | 3,031 | | | $ | 4,519 | | | | (33 | )% | Capacity revenue | | | 1,030 | | | | — | | | | 1,030 | | | | 1,359 | | | | (24 | ) | Retail revenue | | | 4,440 | | | | 4,440 | | | | — | | | | — | | | | N/A | | Risk management activities | | | 418 | | | | — | | | | 418 | | | | 418 | | | | — | | Contract amortization | | | (179 | ) | | | (258 | ) | | | 79 | | | | 278 | | | | (72 | ) | Thermal revenue | | | 100 | | | | — | | | | 100 | | | | 114 | | | | (12 | ) | Other revenues | | | 112 | | | | — | | | | 112 | | | | 197 | | | | (43 | ) | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | | 8,952 | | | | 4,182 | | | | 4,770 | | | | 6,885 | | | | (31 | ) | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | Cost of sales | | | 4,524 | | | | 3,003 | | | | 1,521 | | | | 2,641 | | | | (42 | ) | Risk management activities | | | (338 | ) | | | (315 | ) | | | (23 | ) | | | — | | | | N/A | | Other operating costs | | | 1,137 | | | | 153 | | | | 984 | | | | 957 | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | Total cost of operations | | | 5,323 | | | | 2,841 | | | | 2,482 | | | | 3,598 | | | | (31 | ) | Depreciation and amortization | | | 818 | | | | 137 | | | | 681 | | | | 649 | | | | 5 | | Selling, general and administrative | | | 550 | | | | 203 | | | | 347 | | | | 319 | | | | 9 | | Acquisition-related transaction and integration costs | | | 54 | | | | — | | | | 54 | | | | — | | | | N/A | | Development costs | | | 48 | | | | — | | | | 48 | | | | 46 | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | Total operating costs and expenses | | | 6,793 | | | | 3,181 | | | | 3,612 | | | | 4,612 | | | | (22 | ) | | | | | | | | | | | | | | | | | | | | | | Operating Income | | $ | 2,159 | | | $ | 1,001 | | | $ | 1,158 | | | $ | 2,273 | | | | (49 | )% | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues Operating revenues, excluding risk management activities, increased $2.1 billion during the year ended December 31, 2009, compared to the same period in 2008. | | | | • | Retail revenue— the acquisition of NRG directors from 12 to 19.Reliant Energy contributed $4.4 billion of retail revenue during the eight months ended December 31, 2009. Retail revenue includes Mass revenues of $2.6 billion, C&I revenues of $1.6 billion, and supply management revenues of $251 million. | | | • | Sherbino Wind FarmEnergy revenue— On October 22,decreased $1.5 billion during the year ended December 31, 2009, compared to the same period in 2008: |
| | | | ○ | Texas— decreased by $431 million, with $253 million of the decrease driven by lower average realized energy prices, $116 million of the decrease driven by a reduction in generation, and a $62 million decrease in margin on MWh sold from purchased energy. The average realized energy price decreased by 9%, driven by a 45% decrease in merchant prices, offset by a 23% increase in contract prices. Lower merchant prices were driven by the combination of lower gas prices in 2009 and unusually high pricing events that occurred in 2008 NRGthat did not repeat in 2009. Generation decreased by 4% driven by a 9% decrease in coal plant generation. This decrease in generation was offset by a 12% increase in gas plant generation primarily from Cedar Bayou 4 gas plant, and its 50/50 joint venture partner, BP, announcedgeneration from Elbow Creek and Langford wind farms, none of which were in operation in 2008. Coal plant generation was adversely affected by lower energy prices driven by a 56% decrease in average natural gas prices in combination with increased wind generation which shifted the completioncoal unit’s position in the bid stack, negatively affecting coal plant generation. |
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| | | | ○ | Northeast— decreased by $575 million, with $295 million of its 150 MW Sherbino wind farm. Since NRG hasthe decrease driven by lower energy prices and $334 million of the decrease attributable to a 50 percent ownership, Sherbino will providereduction in generation offset by a $54 million increase from higher net contract revenue. Merchant energy prices were lower by an average of 40%. The lower energy prices reduced the CompanyCompany’s net cost incurred to meet obligations under load serving contracts in the PJM market. Generation decreased by 31%, with a 31% decrease in coal generation and a 31% decrease in oil and gas generation. Weakened demand for power combined with lower gas prices resulted in reduced merchant energy prices. Lower merchant energy prices combined with higher costs of production from the introduction of RGGI resulted in increased hours where the coal plants were uneconomical to dispatch. The decline in oil and gas generation is attributable to fewer reliability run hours at Norwalk plant and higher maintenance work at Arthur Kill. | | | ○ | South Central— decreased by $118 million due to a $80 million decline in contract revenue, a $2 million decrease in merchant energy revenues and a $36 million decrease in margin on MWh sold from purchased energy. The contract revenue decrease was attributed to a 10% decrease in sales volumes and a $5.15 per MWh lower average realized price. The decline in contract energy price was driven by a $16 million decrease in fuel cost pass-through to the cooperatives reflecting an overall decline in natural gas prices. Also contributing to the decline in contract revenue was $60 million due to the expiration of a contract with a regional utility. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in a $2 million decline in revenue. Increased use of the region’s tolled facility provided additional energy to the merchant market. | | | ○ | Intercompany energy revenue— intercompany sales of $349 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation. |
| | | | • | Capacity revenue— decreased $329 million during the year ended December 31, 2009, compared to the same period in 2008: |
| | | | ○ | Texas— decreased by $300 million due to a lower proportion of baseload contracts which contain a capacity component. | | | ○ | Northeast— decreased by $8 million due to lower capacity prices in the NYISO. | | | ○ | South Central— increased by $36 million resulting primarily from a new capacity agreement. | | | ○ | Intercompany capacity revenue— intercompany capacity revenue of $47 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation. |
| | | | • | Contract amortization revenue— decreased by $457 million in the year ended December 31, 2009, as compared to the same period in 2008. The decrease resulted from a reduction of $198 million in revenue from the Texas Genco acquisition due to the lower volume of contracted energy. Also reducing contract amortization revenue was the amortization expense of net capacityin-market C&I contracts related to the Reliant Energy acquisition of 75 MW.$258 million. | | | • | Elbow Creek Wind FarmOther revenues— On December 29,decreased by $85 million driven by $51 million in lower ancillary revenue, $51 million in lower emissions revenue, and a $18 million decrease in fuels trading. Lower ancillary revenue was driven by a lesser load on the power grid as opposed to 2008 NRG, through Padoma, announcedand lower ancillary prices. Lower emissions revenue was driven by lower carbon financial instrument sales and a loss on emission allowance sales. These decreases were offset by the completionrecognition of its Elbow Creek project, a wholly-owned 120 MW wind farm$31 million non-cash gain related to settlement of a pre-existingin-the-money contract with Reliant Energy at the time of acquisition. Other revenue also included $3 million in Howard County near Big Spring, Texas. The Company fundedintercompany ancillary services in 2009 by the Company’s Texas region and developed this wind farm which consists of 53 Siemens wind turbine generators, each capable of generating up to 2.3 MW of power.Reliant Energy that were eliminated in consolidation. |
Cost of Operations Cost of operations, excluding risk management activities, increased $2.1 billion during the year ended December 31, 2009, compared to the same period in 2008 and increased as a percentage of revenues to 66% for 2009 as compared to 56% for 2008.
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| | | | • | Cost of sales— increased $1.9 billion during the year ended December 31, 2009, compared to the same period in 2008, and increased as a percentage of revenues to 53% for 2009 as compared to 41% for 2008 due to: |
| | | | ○ | Retail— Reliant Energy incurred $3 billion of cost of energy during the eight months ended December 31, 2009, which included $399 million of intercompany supply costs. | | | ○ | Texas— cost of energy decreased $305 million due to lower natural gas, coal, purchased energy and ancillary services costs. |
| | | | — | Fuel expense— Natural gas costs decreased $281 million, reflecting a 56% decline in average natural gas per MMBtu prices offset by a 12% increase in gas-fired generation. Coal costs increased by $5 million driven by a $44 million increase from higher coal prices and a $9 million increase in higher transportation costs. These increases were offset by a $28 million decrease from lower coal volume resulting from reduced generation and a $15 million loss reserve related to a coal contract dispute in 2008. | | | — | Ancillary service expense— Ancillary service costs decreased $44 million due to a decrease in purchased ancillary service costs incurred to meet contract obligations. |
| | | | ○ | Northeast— cost of energy decreased $295 million due to a $187 million reduction in natural gas and oil costs and a $129 million reduction in coal costs. |
| | | | — | Fuel expense— Natural gas and oil costs decreased due to 31% lower generation and 56% lower average natural gas prices. |
| | | | — Coal costs— | decreased primarily due to 31% lower coal generation. |
| | | | — | RGGI expense— These decreases were offset by a $22 million increase in costs related to RGGI which became effective in 2009. |
| | | | ○ | South Central— cost of energy decreased $90 million due to a $58 million decrease in purchased energy reflecting lower fuel costs associated with the region’s tolled facility and lower market energy prices, a $15 million decrease in natural gas costs, an $11 million decrease in coal costs, and an $8 million decrease in transmission expense due to transmission line outages. The decrease in natural gas cost is attributable to a 30% decrease in owned gas generation and a 54% decrease in natural gas prices. The coal cost decreased due to a 6% decrease in generation offset by a 1% increase in price. | | | ○ | West— cost of energy decreased $6 million due to a 29% decline in average natural gas per MMBtu prices offset by an 8% increase in natural gas consumption and a $3 million increase in fuel oil expense resulting from a write-down to market of fuel oil inventory no longer used in the production of energy. | | | ○ | Intercompany cost of energy— intercompany purchases of $399 million by Reliant Energy from the Company’s Texas region were eliminated in consolidation. |
| | | | • | Other cost of operations— increased $180 million during the year ended December 31, 2009, compared to the same period in 2008. Reliant Energy incurred $153 million which includes $98 million for customer service operations and $55 million for gross receipt tax on revenue. Further, property taxes increased by $14 million due to reduction in eligibility related to Empire Zone tax credits in New York. Plant maintenance expenses were relatively flat during the period, however these expenses decreased in Northeast region by $22 million offset by an increase of $11 million in West region, a $6 million increase in South Central region and a $3 million increase in Texas region. In addition, NRG incurred a $12 million asset write-down due to the expected cancellation of the Indian River Unit 3 air pollution control equipment project and the consequent write-off of previously incurred construction costs. |
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Risk Management Activities Risk management activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total derivative gains increased by $338 million during the year ended December 31, 2009, compared to the same period in 2008. The breakdown of changes by region follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year ended December 31, 2009 | | | | Reliant
| | | | | | | | | South
| | | | | | | | | | | | | | | | | | | Energy | | | Texas | | | Northeast | | | Central | | | West | | | Thermal | | | Elimination | | | Total | | | | | | | (In millions) | | | Net gains/(losses) on settled positions | | $ | (480 | ) | | $ | 311 | | | $ | 377 | | | $ | (2 | ) | | $ | (8 | ) | | $ | 6 | | | $ | — | | | $ | 204 | | | | | | Mark-to-market gains/(losses) | | | 794 | | | | (110 | ) | | | (40 | ) | | | (90 | ) | | | — | | | | (2 | ) | | | — | | | | 552 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivative gains/(losses) included in revenues and cost of operations | | $ | 314 | | | $ | 201 | | | $ | 337 | | | $ | (92 | ) | | $ | (8 | ) | | $ | 4 | | | $ | — | | | $ | 756 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The breakdown of gains and losses included in revenue and cost of operations by region are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year ended December 31, 2009 | | | | Reliant
| | | | | | | | | South
| | | | | | | | | | | | | | | | | | | Energy | | | Texas | | | Northeast | | | Central | | | West | | | Thermal | | | Elimination | | | Total | | | | | | | (In millions) | | | Net gains/(losses) on settled positions, or financial income in revenues | | $ | — | | | $ | 330 | | | $ | 384 | | | $ | 7 | | | $ | (8 | ) | | $ | 6 | | | $ | (11 | ) | | $ | 708 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mark-to-market results in revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reversal of previously recognized unrealized gains on settled positions related to economic hedges | | | — | | | | (73 | ) | | | (120 | ) | | | — | | | | — | | | | (3 | ) | | | — | | | | (196) | | | | | | Reversal of gain positions acquired as part of the Reliant Energy acquisition as of May 1, 2009 | | | (1 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (1) | | | | | | Reversal of previously recognized unrealized gains on settled positions related to trading activity | | | — | | | | (65 | ) | | | (34 | ) | | | (58 | ) | | | — | | | | — | | | | — | | | | (157) | | | | | | Reversal of previously recognized unrealized gains due to the termination of positions related to the CSRA unwind | | | — | | | | (24 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (24) | | | | | | Net unrealized gains/(losses) on open positions related to economic hedges | | | 1 | | | | 80 | | | | 50 | | | | (17 | ) | | | — | | | | 1 | | | | (1 | ) | | | 114 | | | | | | Net unrealized losses on open positions related to trading activity | | | — | | | | (20 | ) | | | (3 | ) | | | (3 | ) | | | — | | | | — | | | | — | | | | (26) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Subtotalmark-to-market results | | | — | | | | (102 | ) | | | (107 | ) | | | (78 | ) | | | — | | | | (2 | ) | | | (1 | ) | | | (290) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivative gains/(losses) included in revenues | | $ | — | | | $ | 228 | | | $ | 277 | | | $ | (71 | ) | | $ | (8 | ) | | $ | 4 | | | $ | (12 | ) | | $ | 418 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year ended December 31, 2009 | | | | Reliant
| | | | | | | | | South
| | | | | | | | | | | | | Energy | | | Texas | | | Northeast | | | Central | | | Elimination | | | Total | | | | | | | (In millions) | | | Net gains/(losses) on settled positions, or financial expense in cost of operations | | $ | (480 | ) | | $ | (19 | ) | | $ | (7 | ) | | $ | (9 | ) | | $ | 11 | | | $ | (504) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mark-to-market results in cost of operations | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reversal of previously recognized unrealized losses on settled positions related to economic hedges | | | — | | | | 47 | | | | 81 | | | | — | | | | — | | | | 128 | | | | | | Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009 | | | 657 | | | | — | | | | — | | | | — | | | | — | | | | 657 | | | | | | Reversal of previously recognized unrealized losses due to the termination of positions related to the CSRA unwind | | | 104 | | | | — | | | | — | | | | — | | | | — | | | | 104 | | | | | | Net unrealized gains/(losses) on open positions related to economic hedges | | | 33 | | | | (55 | ) | | | (14 | ) | | | (12 | ) | | | 1 | | | | (47) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Subtotalmark-to-market results | | | 794 | | | | (8 | ) | | | 67 | | | | (12 | ) | | | 1 | | | | 842 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivative gains/(losses) included in cost of operations | | $ | 314 | | | $ | (27 | ) | | $ | 60 | | | $ | (21 | ) | | $ | 12 | | | $ | 338 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The $114 millionmark-to-market gain in revenue related to economic hedges consisted of a $217 million gain recognized in earnings from previously deferred amounts in other comprehensive income, or OCI, as the Company discontinued cash flow hedge accounting in the first quarter for certain 2009 transactions in Texas and New York due to lower expected generation, offset by a $103 million decrease in value in forward sales of electricity and fuel relating to economic hedges due to lower forward power and gas prices. The $47 million mark-to-market loss in expense related to economic hedges consisted of a $18 million decrease in value of forward purchases of electricity and fuel and a loss of $29 million resulting from discontinued Normal Purchase Normal Sale, or NPNS, designated coal purchases due to expected lower coal consumption and accordingly, the Company could not assert taking physical delivery of coal purchase transactions under NPNS designation. Reliant Energy’s loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. The $656 million roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in revenues and cost of operations during the same period. The $104 million gain from the reversal of a loss was offset by a realized loss at the settled prices and are reflected in cost of operations during the same period. Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy, the changes in such results should not be viewed in isolation, but rather should be taken together with the effects of pricing and cost changes on energy revenue and costs. During and prior to 2009, NRG hedged a portion of the Company’s 2009 through 2013 generation. During 2009, the settled prices of electricity and natural gas decreased resulting in the recognition of realized gains while forward power and gas prices decreased resulting in the recognition of unrealizedmark-to-market gains. During 2008, decreasing forward prices of electricity and natural gas resulted in recognition of unrealizedmark-to-market gains while the settled prices for power and gas increased resulting in the recognition of realized losses. In accordance with ASC815-10-45-9, the following table represents the results of the Company’s financial and physical trading of energy commodities for the years ended December 31, 2009, and 2008. The realized financial trading results and unrealized financial and physical trading results are included in the risk management activities 84
above, while the realized physical trading results are included in energy revenue. The Company’s trading activities are subject to limits in accordance with the Company’s risk management policy. | | | | | | | | | | | | | | | Year ended
| | | | December 31, | | | | 2009 | | | 2008 | | | | | | | (In millions) | | Trading gains/(losses) | | | | | | | | | | | | | Realized | | $ | 216 | | | $ | 67 | | | | | | Unrealized | | | (183 | ) | | | 63 | | | | | | | | | | | | | | | | | | | Total trading (losses)/gains | | $ | 33 | | | $ | 130 | | | | | | | | | | | | | | | | | | |
Depreciation and Amortization NRG’s depreciation and amortization expense increased by $169 million for the year ended December 31, 2009, compared to the same period in 2008. Reliant Energy’s depreciation and amortization expense for the eight month period was $137 million principally for amortization of customer relationships. The balance of the increase was due to depreciation on the baghouse projects in western New York and the Elbow Creek project which came online in late 2008, and the Cedar Bayou 4 plant which came online in the second quarter 2009. Selling, General and Administrative Expenses Selling, general and administrative expenses increased by $231 million for the year ended December 31, 2009, compared to the same period in 2008 and increased as a percentage of revenues to 6% for 2009 from 5% for 2008. The increase was due to: | | | | • | Reliant Energy’s selling, general and administrative expense— totaled $203 million, including $61 million of bad debt expense incurred during the eight months ended December 31, 2009. | | | • | Wage and benefits expense— increased $19 million. | | | • | Consultant costs— increased $12 million consisting of a rise in non-recurring costs related to Exelon’s exchange offer and proxy contest efforts of $23 million offset by a decrease in other consulting costs of $11 million. |
Acquisition-Related Transaction and Integration Costs NRG incurred Reliant Energy acquisition-related transaction costs of $23 million and integration costs of $31 million for the year ended December 31, 2009. Equity in Earnings of Unconsolidated Affiliates NRG’s equity earnings from unconsolidated affiliates decreased by $18 million for the year ended December 31, 2009, compared to the same period in 2008. During 2009, the Company’s share in Gladstone Power Station and MIBRAG decreased by $4 million and $16 million, respectively. These decreases were offset by the Company’s share of NRG Saguaro, LLC earnings increasing $11 million in 2009 as compared to 2008. In addition, there was a $6 million decrease in Sherbino’smark-to-market unrealized loss as compared to 2008 as a result of a natural gas swap executed to hedge to future power generation. Gain on Sale of Equity Method Investments and Other Income/(Loss), Net NRG’s gain on sale of equity method investments was $128 million for the year ended December 31, 2009. Other income/(loss), net decreased by $22 million for the year ended December 31, 2009, compared to the same period in 2008. The 2009 amounts include a $128 million gain on the sale of NRG’s 50% ownership interest in MIBRAG and a $24 million realized loss on a forward contract for foreign currency executed to hedge the sale proceeds from the MIBRAG sale. In addition, interest income for 2009 was reduced by $17 million as compared to 85
2008 due to lower interest rates. Further in 2008, a $23 million impairment charge was incurred to restructure distressed investments in commercial paper. Refinancing Expenses In 2009, NRG incurred a $20 million expense associated with the unwind of CSRA with Merrill Lynch. There were no such expenses in 2008. Interest Expense NRG’s interest expense increased by $51 million for the year ended December 31, 2009, compared to the same period in 2008. This increase was primarily due to a $32 million increase in fees incurred during the months of May through December of 2009 on the CSRA facility, a $34 million increase in interest expense as a result of the 2019 Senior Notes issued in June 2009, a $4 million increase related to ineffective portion of the interest rate cash flow hedges on the Company’s Term Loan Facility and an $8 million increase in the amortization of deferred financing costs. These increases were offset by a $33 million decrease in interest expense on the Company’s Term Loan Facility due to a decrease in the outstanding notional amount and lower interest rates related to the unhedged portion of Term Loan and fair value portion of Senior Notes. Income Tax Expense Income tax expense increased by $15 million for the year ended December 31, 2009, compared to 2008. The effective tax rate was 43.6% and 40.4% for the year ended December 31, 2009, and 2008, respectively. | | | | | | | | | | | | | | | Year Ended
| | | | December 31, | | | | 2009 | | | 2008 | | | | | | | (In millions
| | | | except as otherwise stated) | | Income from continuing operations before income taxes | | $ | 1,669 | | | $ | 1,766 | | | | | | | | | | | | | | | | | | | Tax at 35% | | | 584 | | | | 618 | | | | | | State taxes, net of federal benefit | | | 23 | | | | 74 | | | | | | Foreign operations | | | (53 | ) | | | (10 | ) | | | | | Subpart F taxable income | | | — | | | | 2 | | | | | | Valuation allowance | | | 119 | | | | (12 | ) | | | | | Expiration of capital losses | | | 249 | | | | — | | | | | | Reversal of valuation allowance on expired capital losses | | | (249 | ) | | | — | | | | | | Change in state effective tax rate | | | (5 | ) | | | (11 | ) | | | | | Foreign dividends and foreign earnings | | | 33 | | | | 32 | | | | | | Non-deductible interest | | | 10 | | | | 12 | | | | | | FIN 48 interest | | | 9 | | | | 8 | | | | | | Production tax credits | | | (10 | ) | | | — | | | | | | Other | | | 18 | | | | — | | | | | | | | | | | | | | | | | | | Income tax expense | | $ | 728 | | | $ | 713 | | | | | | | | | | | | | | | | | | | Effective income tax rate | | | 43.6 | % | | | 40.4 | % | | | | |
The Company’s effective tax rate differs from the U.S. statutory rate of 35% due to: | | | | • | Valuation Allowance— The Company generated capital losses in 2009 primarily due to the derivative contracts that are eligible for capital treatment for tax purposes. The valuation allowance is recorded primarily against capital loss carryforwards. This resulted in an increase of $127 million in income tax expense in 2009. | | | • | Tax Expense Reduction— The Company recorded a lower federal and state tax expense of $35 million primarily due to lower pre-tax earnings. | | | • | Change in state effective tax rate— The Company decreased its estimated effective tax rate to 3% due to increased operational activities within the state of Texas resulting from the acquisition of Reliant Energy. This resulted in a tax benefit of $5 million. |
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| | | | • | Foreign Operations— The Company elected not to permanently reinvest its earnings from foreign operations in 2008. In 2009, the Company sold its investment in the MIBRAG facility for a book gain of $128 million and no tax gain which resulted in minimal tax due in the local jurisdiction. |
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC-740, Income Taxes, or ASC 740. These factors and others, including the Company’s history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets. Consolidated Results of Operations 2008 compared to 2007 The following table provides selected financial information for NRG Energy, Inc., for the years ended December 31, 2008 and 2007: | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended
| | | | | Year Ended
| | | | | | December 31, | | | | | December 31, | | | | | | 2008 | | 2007 | | Change% | | | 2008 | | 2007 | | Change % | | | | (In millions except otherwise noted) | | | | | (In millions
| | | | | | except otherwise noted) | | | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | | | | | Energy revenue | | $ | 4,519 | | | $ | 4,265 | | | | 6 | % | | $ | 4,519 | | | $ | 4,265 | | | | 6 | % | Capacity revenue | | | 1,359 | | | | 1,196 | | | | 14 | | | | 1,359 | | | | 1,196 | | | | 14 | | Risk management activities | | | 418 | | | | 4 | | | | N/A | | | | 418 | | | | 4 | | | | N/A | | Contract amortization | | | 278 | | | | 242 | | | | 15 | | | | 278 | | | | 242 | | | | 15 | | Thermal revenue | | | 114 | | | | 125 | | | | (9 | ) | | | 114 | | | | 125 | | | | (9 | ) | Other revenues | | | 197 | | | | 157 | | | | 25 | | | | 197 | | | | 157 | | | | 25 | | | | | | | | | | | | | Total operating revenues | | | 6,885 | | | | 5,989 | | | | 15 | | | | 6,885 | | | | 5,989 | | | | 15 | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Cost of operations | | | 3,598 | | | | 3,378 | | | | 7 | | | | 3,598 | | | | 3,378 | | | | 7 | | Depreciation and amortization | | | 649 | | | | 658 | | | | (1 | ) | | | 649 | | | | 658 | | | | (1 | ) | General and administrative | | | 319 | | | | 309 | | | | 3 | | | | 319 | | | | 309 | | | | 3 | | Development costs | | | 46 | | | | 101 | | | | (54 | ) | | | 46 | | | | 101 | | | | (54 | ) | | | | | | | | �� | | | | | | | Total operating costs and expenses | | | 4,612 | | | | 4,446 | | | | 4 | | | | 4,612 | | | | 4,446 | | | | 4 | | | | | | | | | | | | | Gain on sale of assets | | | — | | | | 17 | | | | (100 | ) | | | — | | | | 17 | | | | (100 | ) | | | | | | | | | | | | Operating Income | | | 2,273 | | | | 1,560 | | | | 46 | | | | 2,273 | | | | 1,560 | | | | 46 | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | | | | | | | | | | | | | Equity in earnings of unconsolidated affiliates | | | 59 | | | | 54 | | | | 9 | | | | 59 | | | | 54 | | | | 9 | | Gains on sales of equity method investments | | | — | | | | 1 | | | | (100 | ) | | | — | | | | 1 | | | | (100 | ) | Other income, net | | | 17 | | | | 55 | | | | (69 | ) | | | 17 | | | | 55 | | | | (69 | ) | Refinancing expenses | | | — | | | | (35 | ) | | | (100 | ) | | | — | | | | (35 | ) | | | (100 | ) | Interest expense | | | (620 | ) | | | (689 | ) | | | (10 | ) | | | (583 | ) | | | (702 | ) | | | (17 | ) | | | | | | | | | | | | Total other expenses | | | (544 | ) | | | (614 | ) | | | (11 | ) | | | (507 | ) | | | (627 | ) | | | (19 | ) | | | | | | | | | | | | Income from Continuing Operations before income tax expense | | | 1,729 | | | | 946 | | | | 83 | | | | 1,766 | | | | 933 | | | | 89 | | Income tax expense | | | 713 | | | | 377 | | | | 89 | | | | 713 | | | | 377 | | | | 89 | | | | | | | | | | | | | Income from Continuing Operations | | | 1,016 | | | | 569 | | | | 79 | | | | 1,053 | | | | 556 | | | | 89 | | Income from discontinued operations, net of income tax expense | | | 172 | | | | 17 | | | | N/A | | | | 172 | | | | 17 | | | | N/A | | | | | | | | | | | | | Net Income | | $ | 1,188 | | | $ | 586 | | | | 103 | | | | 1,225 | | | | 573 | | | | 114 | | Less: Net loss attributable to noncontrolling interest | | | | — | | | | — | | | | — | | | | | | | | | Net income attributable to NRG Energy, Inc. | | | $ | 1,225 | | | $ | 573 | | | | 114 | | | | | | | | | | | | | Business Metrics | | | | | | | | | | | | | | | | | | | | | | | | | Average natural gas price — Henry Hub ($/MMbtu) | | | 8.85 | | | | 7.12 | | | | 24 | % | | | 8.85 | | | | 6.94 | | | | 28 | % |
N/A — Not applicable
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Operating Revenues Operating revenues increased by $896 million for the year ended December 31, 2008, compared to 2007. This was due to: | | | | • | Energy revenuesrevenue— increased $254 million during the year ended December 31, 2008, compared to the same period in 2007: |
| | | | o○ | Texas— increased $172 million, with $219$430 million of this increase driven by higher prices, offset by $47$42 million reduced generation.generation and a $216 million decrease on net margin on MWh sold from market purchases. The price variance was attributable to a more favorable mix of merchant versus contract sales, as well as a 28% increase in merchant prices partially offset by a 14% decrease in contract energy prices. The 839 thousand MWh or 2% reduction in generation was comprised of a 3% reduction from nuclear plant generation, a 14% reduction from gas plant generation, offset by a 1% increase in coal plant generation. The reduction in gas plant generation was attributable to the effects of hurricane Ike in September 2008. | | | o○ | Northeast— decreased $40 million, with $66 million reduced generation, a $38 million decrease from lower net contract revenue offset by a $26$64 million increase driven by higher energy prices. The decline due to generation was driven by a net 6% reduction in the region’s generation, due to a decrease in oil-fired generation as a result of higher average oil prices as well as decrease in gas-fired generation related to a cooler summer in 2008 compared to 2007. The increase due to energy prices reflects an average 6% rise in merchant energy prices offset by lower contract revenue, driven by higher costs required to service the PJM contracts, as a result of the increase in market energy prices. | | | o○ | South Central— increased $74 million, attributable to a $41 million increase caused by higher merchant energy revenues.prices and a $33 million increase on net margin on MWh sold from market purchases. The growth in merchant energy revenues reflected 577 thousand more merchant MWh sold, as a decrease in contract load MWh allowed more sales to the merchant market at higher prices. | | | o○ | West— increased $35 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. |
| | | | • | Capacity revenuesrevenue— increased $163 million during the year ended December 31, 2008, compared to the same period in 2007: |
| | | | o○ | Texas— increased $130 million due to a greater proportion of base-load contracts, which contain a capacity component. | | | o○ | Northeast— increased $13 million reflecting $31 million higher capacity revenues in the PJM and NEPOOL markets offset by a $18 million reduction in capacity revenue in NYISO. | | | o○ | South Central— increased $12 million due to a $10 million higher capacity payment from the region’s cooperative customers and an $8 million rise in RPM capacity payments from the PJM market. These increases were offset by a $6 million reduction related to lower contract volume to other customers. | | | o○ | West— increased $3 million due to a tolling arrangement at Long Beach plant offset by the reduction of revenue from the El Segundo tolling arrangement. |
| | | | • | Contract amortization revenuesrevenue— increased $36 million during the year ended December 31, 2008, compared to the same period in 2007 due to the volume of contracted energy affected by a greater spread between contract prices and market prices used in the Texas Genco purchase accounting. | | | • | Other revenues— increased by $40 million during the year ended December 31, 2008, compared to the same period in 2007. The increases arose from greater ancillary services revenue of $28 million and increased activity in the trading of emission allowances and carbon financial instruments of $21 million. These increases were offset by $14 million in lower gas and coal trading activities. |
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| | | | • | Risk management activities —revenues from risk management activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges and trading activities. Such revenues increased by $414 million during the year ended December 31, 2008, compared to the same period in 2007. The breakdown of changes by region was as follows: |
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2008 | | | | Texas | | | Northeast | | | South Central | | | Thermal | | | Total | | | | (In millions) | | | Net (losses)/gains on settled positions, or financial revenues | | $ | (95 | ) | | $ | 3 | | | $ | (16 | ) | | $ | 1 | | | $ | (107 | ) | | | | | | | | | | | | | | | | | | | | | | Mark-to-market results | | | | | | | | | | | | | | | | | | | | | Reversal of previously recognized unrealized gains on settled positions related to economic hedges | | | (25 | ) | | | (13 | ) | | | — | | | | — | | | | (38 | ) | Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity | | | 1 | | | | (14 | ) | | | (19 | ) | | | — | | | | (32 | ) | Net unrealized gains on open positions related to economic hedges | | | 400 | | | | 96 | | | | — | | | | 4 | | | | 500 | | Net unrealized gains on open positions related to trading activity | | | 37 | | | | 13 | | | | 45 | | | | — | | | | 95 | | | | | | | | | | | | | | | | | | | | | | | Subtotal mark-to-market results | | | 413 | | | | 82 | | | | 26 | | | | 4 | | | | 525 | | | | | | | | | | | | | | | | | | | | | | | Total derivative gains | | $ | 318 | | | $ | 85 | | | $ | 10 | | | $ | 5 | | | $ | 418 | | | | | | | | | | | | | | | | | | | | | | |
NRG’s 2008 gain is comprised of $525 million of mark-to-market gains and $107 million in settled losses, or financial revenue. Of the $525 million of mark-to-market gains, the $38 million loss represents the reversal ofmark-to-market gains recognized on economic hedges and the $32 million loss represents the reversal of mark-to-market gains recognized on trading activity. Both of these losses ultimately settled as financial revenues during 2008. The $500 million gain from economic hedge positions included a $524 million increase in value of forward sales of electricity as the result of the reduction in forward power and gas prices at the close of the year-ended December 31, 2008. These hedges are considered effective economic hedges that do not receive cash flow hedge accounting treatment. In addition there was a $24 million loss primarily from hedge accounting ineffectiveness related to gas trades in the Texas region which was driven by decreasing forward gas prices while forward power prices declined at a slower pace. NRG also recognized a $95 million unrealized gain associated with the company’s trading activity. This gain was primarily due to declining forward electricity and fuel prices.
Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues the changes in such results should not be viewed in isolation, but rather should be taken together with the effects of pricing and cost changes on energy revenues. During and throughout 2008, NRG hedged a portion of the Company’s 2008 through 2013 generation. Since that time, the settled and forward prices of electricity and natural gas have decreased, resulting in the recognition of unrealized mark-to-market forward gains.
Cost of Operations Cost of operations excluding risk management activities, increased $220 million during the year ended December 31, 2008, compared to the same period in 2007 but it decreasedand remained flat as a percentage of revenues fromat 56% for the year ended 2007 compared to 52% for the year ended 2008.2008 and 2007. | | | | • | Cost of energy— increased $213 million during the year ended December 31, 2008, compared to the same period in 2007 and remained flat as a percentage of revenue it decreased fromrevenues at 41% for 2007 as compared to 38% for 2008.2008 and 2007. This increase was due to : |
| | | | o○ | Texas— Cost of energy increased $59 million due to a net increase in fuel expense and ancillary service costs offset by reductions in nuclear fuel expenses, purchased power expense and amortization of contracts cost. |
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| | | | — | Fuel expense— Natural gas costs rose $99 million due to an increase of 28% in average natural gas prices, offset by a 14% decrease in gas-fired generation. In addition, coal costs increased by $44 million as a result of higher coal prices and the settlement payment related to a coal contract dispute. These increases were offset by a decrease of $19 million in nuclear fuel expense as amortization of nuclear fuel inventory established under Texas Genco purchase accounting ended in early 2008. | | | — | Purchased energy— Purchased energy expense decreased $26 million as a result of lower forced outage rates at the region’s base-load plants. | | | — | Ancillary service expense— Ancillary services and other costs increased by $14 million as a result of higher ERCOT ISO fees offset by reduced purchased ancillary services costs. | | | — | Fuel contract amortization— Amortized contract costs decreased by $59 million due to a $36 million decrease in the amortization of water supply contracts which ended in 2007. In addition, the amortization of coal contracts decreased by a net $22 million as a result of a reduction in expense related toin-the-money coal contract amortization. These contracts were established under Texas Genco purchase accounting. |
| | | | o○ | Northeast— Cost of energy increased $54 million due to higher fuel costs. Coal costs increased $61 million due to higher coal prices and fuel transportation surcharges. Natural gas costs rose $22 million as a result of 32% higher average natural gas prices, despite 12% lower generation. These increases were offset by a $27 million reduction in oil costs as a result of 55% lower oil-fired generation. | | | o○ | South Central— Cost of energy increased $56 million due to higher fuel costs and increased purchased energy expense. |
| | | | — | Fuel expense— Coal costs increased $16 million resulting from an increase in coal consumption and higher fuel transportation surcharges; natural gas costs rose by $14 million as the region’s peaker plants ran extensively to support transmission system stability after hurricane Gustav. | | | — | Purchased energy— Higher purchased energy expenses of $16 million reflected higher natural gas costs for tolling contracts. | | | — | Transmission costs— Increasedincreased by $9 million due to additionalpoint-to-point transmission costs driven by an increase in merchant energy sales. |
| | | | o○ | West— Cost of energy increased $30 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. |
| | | | • | Other operating costs —increased $7 million during the year ended December 31, 2008, compared to the same period in 2007. This increase was due to: |
| | | | o○ | Texas— increased $30 million due to a second planned outage at STP and the acceleration of planned outages at the base-load plants. |
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| | | | o○ | Northeast —decreased $3 million due to $18 million in lower operating and maintenance expenses resulting from less outage work at the Norwalk plants and Indian River plants. This decrease was offset by a $16 million increase in utilities cost. The 2007 utilities cost included a benefit of $19 million due to a lower than planned settlement of the station service agreement with CL&P. | | | o○ | South Central —decreased by $10 million due to reduction in major maintenance expense. The 2007 expense included more extensive outage work that was performed at the Big Cajun II plant. | | | o○ | West —decreased by $4 million due to a $3 million reduction in lease expenses and an environmental liability of $2 million which was recognized in 2007 related to the El Segundo plant. |
Risk Management Activities Risk management activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges and trading activities. Such revenues increased by $414 million during the year ended December 31, 2008, compared to the same period in 2007. The breakdown of changes by region was as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | Year ended December 31, 2008 | | | | | | | | | | South
| | | | | | | | | | | (In millions) | | Texas | | | Northeast | | | Central | | | Thermal | | | Total | | | | | | | (In millions) | | | Net (losses)/gains on settled positions, or financial income in revenues | | $ | (95 | ) | | $ | 3 | | | $ | (16 | ) | | $ | 1 | | | $ | (107 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mark-to-market results | | | | | | | | | | | | | | | | | | | | | | | | | Reversal of previously recognized unrealized gains on settled positions related to economic hedges | | | (25 | ) | | | (13 | ) | | | — | | | | — | | | | (38 | ) | | | | | Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity | | | 1 | | | | (14 | ) | | | (19 | ) | | | — | | | | (32 | ) | | | | | Net unrealized gains on open positions related to economic hedges | | | 400 | | | | 96 | | | | — | | | | 4 | | | | 500 | | | | | | Net unrealized gains on open positions related to trading activity | | | 37 | | | | 13 | | | | 45 | | | | — | | | | 95 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Subtotalmark-to-market results | | | 413 | | | | 82 | | | | 26 | | | | 4 | | | | 525 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivative gain | | $ | 318 | | | $ | 85 | | | $ | 10 | | | $ | 5 | | | $ | 418 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivative gain included in revenues | | | 318 | | | | 85 | | | | 10 | | | | 5 | | | | 418 | | | | | | Total derivative gain included in cost of operations | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NRG’s 2008 gain is comprised of $525 million ofmark-to-market gains and a $107 million in settled losses, or financial revenue. Of the $525 million ofmark-to-market gains, the $38 million loss represents the reversal ofmark-to-market gains recognized on economic hedges and the $32 million loss represents the reversal ofmark-to-market gains recognized on trading activity. Both of these losses ultimately settled as financial or physical revenues during 2008. The $500 million gain from economic hedge positions included a $524 million increase in value of forward sales of electricity as the result of the reduction in forward power and gas prices at the close of the year ended December 31, 2008. These hedges are considered effective economic hedges that do not receive cash flow hedge accounting treatment. In addition there was a $24 million loss primarily from hedge accounting ineffectiveness related to gas trades in the Texas region which was driven by decreasing forward gas prices while forward power prices declined at a slower pace. NRG also recognized a $95 million unrealized gain associated with the company’s trading activity. This gain was primarily due to declining forward electricity and fuel prices. Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues the changes in such results should not be viewed in isolation, but rather should be taken together with the effects of pricing and cost changes on energy revenues. During and throughout 2008, NRG hedged a portion of the Company’s 2008 through 2013 generation. Since that time, the settled and forward prices of electricity and natural gas have decreased, resulting in the recognition of unrealizedmark-to-market forward gains.
8090
In accordance with ASC815-10-45-9, the following table represents the results of the Company’s financial and physical trading of energy commodities for the years ended December 31, 2008, and 2007. The realized financial trading results and unrealized financial and physical trading results are included in the risk management activities above, while the realized physical trading results are included in energy revenue. The Company’s trading activities are subject to limits in accordance with the Company’s risk management policy. | | | | | | | | | | | | | | | Year ended
| | | | December 31, | | | | 2008 | | | 2007 | | | | | | | (In millions) | | | Trading gains | | | | | | | | | | | | | Realized | | $ | 67 | | | $ | 396 | | | | | | Unrealized | | | 63 | | | | 18 | | | | | | | | | | | | | | | | | | | Total trading gains | | $ | 130 | | | $ | 414 | | | | | | | | | | | | | | | | | | |
General and Administrative NRG’s G&A costs for the year ended December 31, 2008, increased by $10 million compared to 2007, and as a percentage of revenues was 5% in both 2008 and 2007. | | | | • | Wage and benefit costs —increased $19 million attributable to higher wages and related benefits cost increases. | | | • | Consultant cost —increased by $3 million resulting from $8 million spent on Exelon’s exchange offer offset by a $5 million reduction in information technology consultants. | | | • | Franchise tax —The Company’s Louisiana state franchise tax decreased by approximately $4 million. Prior year franchise tax was assessed based on the Company’s total debt and equity that increased significantly following the acquisition of Texas Genco. | | | • | Insurance cost —decreased by $4 million due to favorable rates. |
Development Costs NRG’s development costs for the year ended December 31, 2008 decreased by $55 million compared to 2007. These costs were due to the Company’sRepoweringNRG projects: | | | | • | Texas STP unitsUnits 3 and 4 projects— No development expense was reflected in results of operations for 2008 as NRG began to capitalize STP unitsUnits 3 and 4 development costs incurred after January 1, 2008, following the NRC’s docketing of the Company’s COLA in late 2007. The Company recorded $52 million in development expenses during 2007. | | | • | Wind projects— The Company incurred $21 million in costs related to wind development which is a $4 million decrease from the same period in 2007. | | | • | Other projects— The Company incurred $25 million in development costs related to other domesticRepoweringNRG projects in 2008, which decreased $7 million from the same period in 2007 as a result of the capitalization of costs to develop the El Segundo Energy Center in 2008. |
Gain on Sale of Assets The Company reported no gains on sales of assets for 2008. For 2007, NRG’s gain on the sale of assets was $17 million. On January 3, 2007, NRG completed the sale of the Company’s Red Bluff and Chowchilla II power plants resulting in a pre-tax gain of $18 million. Equity in Earnings of Unconsolidated Affiliates NRG’s equity earnings from unconsolidated affiliates for the year ended December 31, 2008, increased by $5 million compared to 2007. This increase was due to a $9 millionmark-to-market unrealized gain on a forward contract for a natural gas swap executed to hedge the future power generation of Sherbino I Wind Farm LLC, offset by a $4 million reduction in earnings from international equity investments. 91
Other Income, Net NRG’s other income, net decreased by $38 million for 2008 compared to the same period in 2007. The Company recorded a further $23 million impairment charge in 2008 to restructure distressed investments in commercial paper, for which an $11 million impairment charge was taken in the fourth quarter of 2007. The impairment charge resulted from a change in the Company’s fair value assessment as a result of a public auction of the assets in the structured investment vehicle holding the investments; this auction was the first observable market participation since the structured investment vehicle became illiquid in 2007. This 2008 impairment charge, along with cash receipts of $2 million, reduced the carrying value of the commercial paper to $7 million. In addition, the 2008 results reflect reduced interest income of $25 million from lower market interest rates on cash deposits.
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Interest Expense NRG’s interest expense decreased by $69$119 million for 2008 compared to the same period in 2007. This decrease was due to interest savings on $531 million debt repayments accompanied by a reduction on the variable interest rates on long-term debt. The debt repayments included a $300 million prepayment in December 2007 and an additional payment of $143 million in March 2008 of the Term Loan Facility in connection with the mandatory offer under the Senior Credit Facility. Interest capitalized onRepoweringNRG projects under construction also contributed to this decrease in interest expense. Offsetting this decrease was the $45 million payment made to the Credit Suisse Group, or CS, for the benefit of NRG Common Stock Finance I LLC, or CSF I, in August 2008 to early settle the embedded derivative in the Company’s CSF I notes and preferred interests. NRG has interest rate swaps with the objective of fixing the interest rate on a portion of NRG’s Senior Credit Facility. These swaps were designated as cash flow hedges under SFAS 133,ASC 815, and the impact associated with ineffectiveness was immaterial to NRG financial results. For the year ended December 31, 2008, NRG had a deferred loss of $90 million in other comprehensive income compared to a deferred loss of $31 million in 2007. Refinancing Expense There was no refinancing activity in 2008. In 2007, NRG completed a $4.4 billion refinancing of the Company’s Senior Credit Facility, resulting in a charge of $35 million from the write-off of deferred financing costs as the lenders for 45% of the Term Loan Facility either exited the financing or reduced their holdings and were replaced by other institutions. Income Tax Expense Income tax expense increased by $336 million for the year ended December 31, 2008, compared to 2007. The effective tax rate was 41.2% and 39.9%40.4% for the yearyears ended December 31, 2008, and 2007, respectively2007. | | | | | | | | | | | | | | | | | | | | | | Year Ended
| | | Year Ended
| | | | December 31, | | | December 31, | | | | 2008 | | 2007 | | | 2008 | | 2007 | | | | | | (In millions
| | | (In millions
| | | | except as otherwise stated) | | | except as otherwise stated) | | | Income from continuing operations before income taxes | | $ | 1,729 | | | $ | 946 | | | $ | 1,766 | | | $ | 933 | | | | | | | | | | | | | | | | | Tax at 35% | | | 605 | | | | 331 | | | | 618 | | | | 327 | | | | | | State taxes, net of federal benefit | | | 73 | | | | 46 | | | | 74 | | | | 46 | | | | | | Foreign operations | | | (10 | ) | | | (13 | ) | | | (10 | ) | | | (13 | ) | | | | | Subpart F taxable income | | | 2 | | | | — | | | | 2 | | | | — | | | | | | Valuation allowance, including change in state effective rate | | | (12 | ) | | | 6 | | | Valuation allowance | | | | (12 | ) | | | 6 | | | | | | Change in state effective tax rate | | | (11 | ) | | | — | | | | (11 | ) | | | — | | | | | | Change in local German effective tax rates | | | — | | | | (29 | ) | | | — | | | | (29 | ) | | | | | Foreign dividends | | | 32 | | | | 26 | | | Foreign dividends and foreign earnings | | | | 32 | | | | 26 | | | | | | Non-deductible interest | | | 26 | | | | 10 | | | | 12 | | | | 10 | | | | | | Permanent differences, reserves, other | | | 8 | | | | — | | | FIN 48 interest | | | | 8 | | | | — | | | | | | Other | | | | — | | | | 4 | | | | | | | | | | | | | | | | | Income tax expense | | $ | 713 | | | $ | 377 | | | $ | 713 | | | $ | 377 | | | | | | | | | | | | | | | | | Effective income tax rate | | | 41.2 | % | | | 39.9 | % | | | 40.4 | % | | | 40.4 | % | | | | |
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The increase in income tax expense was primarily due to: | | | | • | Increase in income— pre-tax income increased by $783$833 million, with a corresponding increase of $305$336 million in income tax expense. |
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| | | | • | Permanent differences— theThe Company’s effective tax rate differs from the USU.S. statutory rate of 35% due to: |
| | | | o○ | Taxable dividends from foreign subsidiaries— due to the provision of deferred taxes in 2008 on foreign income no longer expected to be permanently reinvested overseas offset by decreased dividends from foreign operations in the current year, tax expense increased by approximately $6 million as compared to 2007. | | | o○ | Non-deductible interest on CAGR Settlement— the Company’s $45 million settlement of the embedded derivative in its CSF I notes and preferred interests resulted in an additional income tax expense of $16$2 million in 2008 as compared to the same period in 2007. | | | o○ | Change in German tax rate— as a result of revaluing ourthe Company’s deferred tax assets, income tax expense benefited by $29 million in 2007, with no comparable benefit in 2008. | | | o○ | Valuation Allowance— theThe Company generated capital gains in 2008 primarily due to the sale of ITISA and derivative contracts that are eligible for capital treatment for tax purposes. These gains enabled NRG to reduce ourthe Company’s valuation allowance against capital loss carryforwards. In addition, applicable changes to the state and local effective tax rate are captured in the current period. This resulted in a decrease of $18 million income tax expense in 2008 as compared to 2007. | | | o○ | Change in state effective tax rate— theThe Company reduced its domestic state and local deferred income tax rate from 7% to 6% in the current period. |
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with SFAS 109.ASC 740. These factors and others, including the Company’s history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets. Income from Discontinued Operations, Net of Income Tax Expense Discontinued operations included ITISA results for 2008 and the same period in 2007. NRG classifies as discontinued operations the income from operations and gains/losses recognized on the sale of projects that were sold or have met the required criteria for such classification pending final disposition. For 2008 and the same period in 2007, NRG recorded income from discontinued operations, net of income tax expense, of $172 million and $17 million, respectively. NRG closed the sale of ITISA during the second quarter 2008 and recognized an after-tax gain of $164 million.
8393
Consolidated Results of Operations for Reliant Energy
2007Selected Income Statement Data
| | | | | | | Period Ended
| | | | December 31,
| | | | 2009(a) | | | | (In millions except
| | | | otherwise noted) | | | Operating Revenues | | | | | Mass revenues | | $ | 2,597 | | Commercial and industrial revenues | | | 1,592 | | Supply management revenues | | | 251 | | Contract amortization | | | (258 | ) | | | | | | Total operating revenues | | | 4,182 | | Operating Costs and Expenses | | | | | Cost of energy (including risk management activities) | | | 2,688 | | Other operating expenses | | | 356 | | Depreciation and amortization | | | 137 | | | | | | | Operating Income | | $ | 1,001 | | | | | | | Electricity sales volume-GWh (in thousands): | | | | | Mass | | | 17,152 | | Commercial and Industrial (b) | | | 20,915 | | Business Metrics | | | | | Weighted average retail customers count (in thousands, metered locations) | | | | | Mass | | | 1,566 | | Commercial and Industrial (b) | | | 68 | | Retail customers count (in thousands, metered locations) | | | | | Mass | | | 1,531 | | Commercial and Industrial (b) | | | 66 | | Cooling Degree Days, or CDDs (c) | | | 2,972 | | CDD’s30-year average | | | 2,713 | | Heating Degree Days, or HDDs (c) | | | 699 | | HDD’s30-year average | | | 644 | |
| | | (a) | | For the period May 1, 2009, to December 31, 2009. | (b) | | Includes customers of the Texas General Land Office for whom the Company provides services. | (c) | | National Oceanic and Atmospheric Administration-Climate Prediction Center - A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Reliant Energy serves its customer base. |
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Year to date results Operating Income Operating income for the period ended December 31, 2009, was $1,001 million, which consisted of the following: | | | | | | | Period Ended
| | | | December 31, 2009 | | | Reliant Energy Operating Income: | | | | | Mass revenues | | $ | 2,597 | | Commercial and industrial revenues | | | 1,592 | | Supply management revenues | | | 251 | | | | | | | Total retail revenues (a) | | | 4,440 | | | | | | | Retail cost of sales (a) | | | 3,531 | | | | | | | Total retail gross margin | | | 909 | | Unrealized gains on energy derivatives | | | 794 | | Contract amortization, net | | | (209 | ) | Other operating expenses | | | (356 | ) | Depreciation and amortization | | | (137 | ) | | | | | | Operating Income | | $ | 1,001 | | | | | | |
| | | (a) | | Amounts exclude unrealized gains/(losses) on energy derivatives and contract amortization. |
| | | | • | Gross margin— Reliant Energy’s gross margin totaled $909 million, which was driven by strong margins in the Mass customer class and expanding margins in the C&I customer class. Volumes were higher due to greater customer usage driven by favorable weather as compared to the 30 year CDD and HDD averages, although partially offset by a decrease in number of customers during the period ended December 31, 2009. The Company acquired Reliant Energy customers on prices more consistent with 2008 costs of natural gas. Reliant Energy announced and enacted price reductions effective June 1 and July 1, 2009, that cumulatively lowered prices up to 20% for certain Mass customer classes. These reduced prices, relative to lower short-term supply costs, delivered strong margins. Competition, price reductions, and supply costs based on forward market prices, will likely drive lower margins in the future. |
With the decline in natural gas prices, and the corresponding decline in the cost of energy supply, competitive retail prices have decreased relative to 2008. If supply costs continue to remain low, the Company expects competitive retail prices to continue their decline and to place pressure on unit margins. Additionally, the Company’s customer counts have declined approximately by 6% since May 1, 2009. Operating Revenues Total operating revenues, including risk management activities, for the period ended December 31, 2009, were $4.2 billion and consisted of the following: • Mass revenues— totaled $2.6 billion from retail electric sales to approximately 1.6 million end use customers in the Texas market. Revenue rates for acquired Reliant Energy customers were not consistent with the current costs of natural gas. These acquired revenue rates were reduced by Reliant Energy’s announced and enacted price reductions effective June 1 and July 1, 2009 of up to 20% for certain Mass customer classes. Also, favorable weather, as compared to 2006the30-year CDD and HDD averages, caused an increase in customer usage. The higher prices, along with higher usage, were accompanied by a 5% decrease in the number of customers since May 1, 2009. • Commercial and industrial revenue— C&I revenues for the period ended December 31, 2009, totaled $1.6 billion on volume sales of approximately 20,915 GWh. Variable rate contracts tied to the market price of natural gas accounted for approximately 73% of the contracted volumes as of December 31, 2009. 95
• Contract amortization— reduced operating revenues by $258 million resulting from net in-market C&I contracts acquired in the Reliant Energy acquisition. These contracts will be amortized over the life of the contracts with the longest contract term being approximately four years. • Supply management revenues— totaled $251 million from the sale of excess supply into various markets in Texas. Cost of Energy Cost of energy for the period ended December 31, 2009, was $2.7 billion and consisted of the following: • Supply costs— totaled $2 billion. The market cost of energy is significantly down due to the decline in natural gas prices since the same period last year. Also, favorable weather for the period, as compared to the30-year CDD and HDD averages, caused an increase in purchased supply volumes at a relatively low cost. • Risk management activities— Unrealized gains of $794 million on economic hedges relate to supply contracts that were recognized for the period ended December 2009, including $657 million of gains representing a roll-off of loss positions acquired at May 1, 2009, valued at forward prices on that date, reversal of losses of $104 million due to the termination of positions related to the CSRA unwind, and $33 million of gains that representmark-to-market changes in the forward value of purchased electricity and gas. The $657 million gain from the roll-off of loss positions was offset by realized losses at the settled prices and higher cost of physical power which are reflected in the cost of operations during the same period. The $104 million gain from reversal of losses was offset by realized losses at the settled prices and is reflected in cost of operations during the same period. • Transmission and distribution charges— totaled $964 million for the cost to transport the power from the generation sources to the end-use customers. • Financial settlements— totaled $480 million resulting from financial settlement of energy related derivatives. • Contract amortization— reduced cost of energy by $49 million, resulting from the netout-of-market supply contracts established at the acquisition date. These contracts will be amortized over the life of the contracts with the longest contract term being approximately seven years. Other Operating Expenses Other operating expenses for the period ended December 31, 2009, were $356 million, or 9% of Reliant Energy’s total operating revenues. Other operating expenses consisted of the following: • Operations and maintenance expenses— totaled $98 million. Theses expenses primarily consisted of the labor and external costs associated with customer activities, including the call center, billing, remittance processing and credit and collections, as well as the information technology costs associated with those activities. • Selling, general and administrative expenses— totaled $142 million. These expenses primarily consisted of the costs of labor and external costs associated with advertising and other marketing activities, as well as human resources, community activities, legal, procurement, regulatory, accounting, internal audit and management, as well as facilities leases and other office expenses. • Gross receipts tax— totaled $55 million or 1.3% of Mass and C&I revenues. • Bad debt expense— totaled $61 million or 1.5% of Mass and C&I revenues which was driven by higher summer bills due to warmer weather and economic factors including unemployment in Dallas and Houston which is approaching national averages. 96
Results of Operations for Wholesale Power Generation Regions Texas Region 2009 compared to 2008 The following table provides selected financial information for NRG Energy, Inc.,the Texas region for the years ended December 31, 20072009, and 2006:2008. | | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2007 | | | 2006 | | | Change % | | | | (In millions
| | | | | | | except otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 4,265 | | | $ | 3,155 | | | | 35 | % | Capacity revenue | | | 1,196 | | | | 1,516 | | | | (21 | ) | Risk management activities | | | 4 | | | | 124 | | | | (97 | ) | Contract amortization | | | 242 | | | | 628 | | | | (61 | ) | Thermal revenue | | | 125 | | | | 124 | | | | 1 | | Hedge Reset | | | — | | | | (129 | ) | | | (100 | ) | Other revenues | | | 157 | | | | 167 | | | | (6 | ) | | | | | | | | | | | | | | Total operating revenues | | | 5,989 | | | | 5,585 | | | | 7 | | | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of operations | | | 3,378 | | | | 3,265 | | | | 3 | | Depreciation and amortization | | | 658 | | | | 590 | | | | 12 | | General and administrative | | | 309 | | | | 276 | | | | 12 | | Development costs | | | 101 | | | | 36 | | | | 181 | | | | | | | | | | | | | | | Total operating costs and expenses | | | 4,446 | | | | 4,167 | | | | 7 | | | | | | | | | | | | | | | Gain on sale of assets | | | 17 | | | | — | | | | N/A | | | | | | | | | | | | | | | Operating Income | | | 1,560 | | | | 1,418 | | | | 10 | | | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | Equity in earnings of unconsolidated affiliates | | | 54 | | | | 60 | | | | (10 | ) | Gains on sales of equity method investments | | | 1 | | | | 8 | | | | (88 | ) | Other income, net | | | 55 | | | | 156 | | | | (65 | ) | Refinancing expenses | | | (35 | ) | | | (187 | ) | | | (81 | ) | Interest expense | | | (689 | ) | | | (590 | ) | | | 17 | | | | | | | | | | | | | | | Total other expenses | | | (614 | ) | | | (553 | ) | | | 11 | | | | | | | | | | | | | | | Income from Continuing Operations before income tax expense | | | 946 | | | | 865 | | | | 9 | | Income tax expense | | | 377 | | | | 322 | | | | 17 | | | | | | | | | | | | | | | Income from Continuing Operations | | | 569 | | | | 543 | | | | 5 | | Income from discontinued operations, net of income tax expense | | | 17 | | | | 78 | | | | (78 | ) | | | | | | | | | | | | | | Net Income | | $ | 586 | | | $ | 621 | | | | (6 | ) | | | | | | | | | | | | | | Business Metrics | | | | | | | | | | | | | Average natural gas price — Henry Hub ($/MMbtu) | | | 7.12 | | | | 6.99 | | | | 2 | % |
| | | | | | | | | | | | | | | | | | | Year Ended
| | | | | | | | | | December 31, | | | | | | | | | | 2009 | | | 2008 | | | Change % | | | | | | | (In millions except otherwise noted) | | | | | | | | Operating Revenues | | | | | | | | | | | | | | | | | Energy revenue | | $ | 2,439 | | | $ | 2,870 | | | | (15 | )% | | | | | Capacity revenue | | | 193 | | | | 493 | | | | (61 | ) | | | | | Risk management activities | | | 229 | | | | 318 | | | | (28 | ) | | | | | Contract amortization | | | 57 | | | | 255 | | | | (78 | ) | | | | | Other revenues | | | 28 | | | | 90 | | | | (69 | ) | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | | 2,946 | | | | 4,026 | | | | (27 | ) | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | Cost of energy | | | 963 | | | | 1,240 | | | | (22 | ) | | | | | Depreciation and amortization | | | 472 | | | | 451 | | | | 5 | | | | | | Other operating expenses | | | 671 | | | | 650 | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | $ | 840 | | | $ | 1,685 | | | | (50 | ) | | | | | | | | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 47,259 | | | | 47,806 | | | | (1 | ) | | | | | MWh generated (in thousands) | | | 44,993 | | | | 46,937 | | | | (4 | ) | | | | | Business Metrics | | | | | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 35.43 | | | $ | 86.23 | | | | (59 | ) | | | | | Cooling Degree Days, or CDDs(a) | | | 2,881 | | | | 2,719 | | | | 6 | | | | | | CDD’s30-year rolling average | | | 2,647 | | | | 2,647 | | | | — | | | | | | Heating Degree Days, or HDDs(a) | | | 1,890 | | | | 1,961 | | | | (4 | )% | | | | | HDD’s30-year rolling average | | | 1,997 | | | | 2,007 | | | | — | | | | | |
N/ | | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Operating Income Operating income decreased by $845 million for the year ended December 31, 2009, compared to the same period in 2008, primarily due to: • Operating revenues— Not applicabledecreased by $1.1 billion due to unfavorable energy and capacity revenue offset by a favorable impact of risk management activities. • Cost of energy— decreased by $277 million driven by lower natural gas costs.
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Operating Revenues OperatingTotal operating revenues increaseddecreased by $404 million for$1.1 billion during the year ended December 31, 2007,2009, compared to 2006. This wasthe same period in 2008, due to:
| | | | • | Energy revenuesrevenue— Energy revenues increased by $1.1 billion for the year ended December 31, 2007, compared to 2006: |
| | | | o | Texas— energy revenues increased by $972decreased $431 million of which $217 million was due to the inclusion of twelve months activity in 2007 compared to eleven months in 2006. Of the remaining $755 million increase, $449 million was due to the Hedge Reset transaction which resulted in higher 2007 average contracted prices of approximately $13 per MWh. In addition, revenues from 8.8 million MWh of generation moved from capacity revenue to energy revenue. Prior to the Acquisition, PUCT regulations required that Texas sell 15% of its capacity by auction at reduced rates. In March 2006, the PUCT accepted NRG’s request to no longer participate in these auctions and that capacity is now being sold in the merchant market. These favorable results were partially offset by lower sales from the region’s natural gas-fired units due to a cooler summer which resulted in lower generation of approximately 2.7 million MWh. | | | o | Northeast— energy revenues increased by approximately $138 million, of which $61 million was due to a 6% increase in generation, primarily driven by increases at the region’s Arthur Kill, Oswego and Indian River plants. The Arthur Kill plant increased generation by 448 thousand MWh due to transmission constraints around New York City, the Oswego plants’ generation increased by 127 thousand MWh due to a colder winter during 2007 compared to 2006, and the Indian River plants’ generation increased by 418 thousand MWh due to stronger pricing and fewer outages in the second half of 2007 compared to the second half of 2006. | | | o | South Central— energy revenues increased by approximately $70 million, due to a new contract which increased contract sales volume by approximately 1.3 million MWh and energy revenues by $69 million. Following a contractual fuel adjustment charge, energy revenues increased by $11 million from the region’s cooperative customers. This was offset by a $12 million decrease in merchant energy revenue. | | | o | West— energy revenues decreased by approximately $72 million, excluding the first quarter 2007, due to the tolling agreement at the Encina plant that has resulted in the receipt of fixed monthly capacity payment in return for the right to schedule and dispatch from the plant. The Encina tolling agreement replaced an RMR agreement under which the plant was called upon to generate and earn energy revenues for such dispatch. |
| | | | • | Capacity revenues— Capacity revenues decreased by $320 million for the year ended December 31, 2007, compared to 2006, due to a decrease in Texas capacity revenues that were partially offset by increases in capacity revenues in the Northeast, South Central and West regions: |
| | | | o | Texas— capacity revenues decreased by $486 million due to a reduction of capacity auction sales mandated by the PUCT in prior years as previously discussed. | | | o | Northeast— capacity revenues increased by $81 million of which $39 million of the increase was from the region’s NEPOOL assets and $36 million was from the region’s PJM assets. The NEPOOL assets benefited from the new LFRM market and transition capacity market, both introduced in the fourth quarter 2006. Capacity revenues increased by $24 million from the LFRM market and $18 million from transition capacity payments, which was offset by a $3 million reduction in capacity payments due to the expiration of the Devon plant’s RMR agreement on December 31, 2006. On June 1, 2007, the new RPM capacity market became effective in PJM increasing capacity revenues by $36 million as compared to 2006. | | | o | South Central— capacity revenues increased by approximately $22 million. Of this increase, $15 million was due to higher billing rates as a result of the region’s market setting new summer peaks hit in 2006 and 2007, $6 million was due to higher contractual transmission pass-though costs to the region’s cooperative customers and $3 million was due to improved market conditions at the region’s Rockford plants. In |
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| | | | | August 2007, the region set a new system peak of 2,123 MW which will continue to impact capacity revenue in the first half of 2008. |
| | | | o | West— capacity revenues increased by approximately $54 million, of which $26 million was related to the inclusion of the first quarter 2007 compared to 2006. New tolling agreements at the region’s Encina and Long Beach plants accounted for the remaining difference, with the Encina facility contributing approximately $15 million and the newly-repowered Long Beach facility contributing approximately $13 million. |
| | | | • | Contract amortization— revenues from contract amortization decreased by $386 million for the year ended December 31, 2007, compared to 2006, as a result of the November 2006 Hedge Reset transaction, which resulted in a write-off of a large portion of the Company’s out-of-market power contracts during the fourth quarter 2006. | | | • | Other revenues —Other revenues decreased by $10 million for the year ended December 31, 2007, compared to 2006 due to: |
| | | | o○ | Sale of emission allowances — net sales of SO2 emission allowances decreased by approximately $33 million. In 2006, we sold emissions in lieu of generation due to an unseasonably warm first quarter. Since that time the average market price for SO2 allowances decreased by 28%. | | | o | Physical gas salesEnergy prices— decreased by $7$253 million as the average realized merchant price was lower in 2009 due to the combination of lower sales of excess natural gas. | | | o | Ancillary revenues— Ancillary services revenue increasedgas prices and unusually high pricing events that occurred in 2008 but did not repeat in 2009. Higher MWh sold under merchant market was offset by approximately $27 million due tolower merchant prices. The average realized energy price decreased by 9%, driven by a change45% decrease in strategy to actively provide ancillary services in the Texas region which increased revenues by $33 million. This was partiallymerchant prices offset by a $4 million reduction23% increase in ancillary services in the Northeast region due to higher transmission costs following transmission constraints in the New York City area.contract prices. |
| | | | • | Risk management activities —Gains/losses from risk management activities include economic hedges that do not qualify for hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Such gains were $4 million for the year ended December 31, 2007. The breakdown of changes by region are as follows: |
| | | | | | | | | | | | | | | | | | | Year Ended December 31, 2007 | | | | | | | | | | South
| | | | | | | Texas | | | Northeast | | | Central | | | Total | | | | (In millions) | | | Net gains on settled positions, or financial revenues | | $ | 33 | | | $ | 43 | | | $ | 5 | | | $ | 81 | | | | | | | | | | | | | | | | | | | Mark-to-market results | | | | | | | | | | | | | | | | | Reversal of previously recognized unrealized gains on settled positions related to economic hedges | | | (83 | ) | | | (45 | ) | | | — | | | | (128 | ) | Reversal of previously recognized unrealized gains on settled positions related to trading activity | | | (1 | ) | | | (12 | ) | | | (19 | ) | | | (32 | ) | Net unrealized gains on open positions related to economic hedges | | | 19 | | | | 15 | | | | — | | | | 34 | | Net unrealized (losses)/gains on open positions related to trading activity | | | (1 | ) | | | 26 | | | | 24 | | | | 49 | | | | | | | | | | | | | | | | | | | Subtotal mark-to-market results | | | (66 | ) | | | (16 | ) | | | 5 | | | | (77 | ) | | | | | | | | | | | | | | | | | | Total derivative (losses)/gains | | $ | (33 | ) | | $ | 27 | | | $ | 10 | | | $ | 4 | | | | | | | | | | | | | | | | | | |
Risk management activities that did not qualify for hedge accounting treatment resulted in a total derivative gain of approximately $4 million for the year ended December 31, 2007 compared to a $124 million gain for the year ended December 31, 2006. NRG’s 2007 derivative gain was comprised of $77 million mark-to-market losses and $81 million in settled gains, or financial revenue. Of the $77 million of mark-to-market losses, $128 million represents the reversal of mark-to-market gains previously recognized on economic hedges and $32 million from the reversal of mark-to-market gains previously recognized on trading activity. Both of these losses ultimately settled as financial revenues during 2007. The $34 million gain from economic hedge positions was comprised of a $20 million increase in the value of forward sales of electricity and fuel due to favorable power and gas prices and a
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$14 million gain from hedge accounting ineffectiveness. This ineffectiveness was primarily related to gas swaps and collars in the Texas region due to a change in the correlation between natural gas and power prices. NRG also recognized a $49 million unrealized gain associated with the Company’s trading activity.
Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy sold, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on energy revenues. In late 2006 and during the course of 2007, NRG hedged a portion of the Company’s 2007 and 2008 generation. Since that time, the settled and forward prices of electricity and natural gas have decreased, resulting in the recognition of unrealized mark-to-market forward gains and the settlement of realized positions at a gain. In 2006, NRG recognized forward mark-to-market gains as forward prices of electricity decreased relative to its positions forward; settled loss positions were driven by the out-of-market gas swaps acquired with the Texas Genco purchase.
Cost of Operations
Cost of operations for the year ended December 31, 2007, increased by $113 million compared to 2006, but as a percentage of revenues it was 56% for 2007 compared to 58% for 2006.
| | | | • | Cost of energy —Cost of energy decreased by approximately $24 million, to $2,428 million, for the year ended December 31, 2007, compared to 2006, and as a percentage of revenue it decreased from 44% for the year ended December 31, 2006, to 41% for the year ended December 31, 2007. This decrease was due to: |
| | | | o | Texas —cost of energy decreased by $95 million for the year ended December 31, 2007, compared to 2006. This decrease included an additional month’s expense of $96 million in 2007, without which cost of energy would have decreased by $191 million. This decrease was due to a reduction in natural gas expense and fuel contract amortization, partially offset by increased ancillary service expense. |
| | | | — | Fuel expense and purchased power expense— Natural gas expense decreased by $170 million, which excludes January 2007 natural gas expense of $27 million. This decrease was due to a reduction of 2.7 million MWh in gas-fired generation as a result of cooler summer weather, coupled with greater economic purchases from the ERCOT and increased baseload generation. Despite higher coal-fired generation at the region’s W.A. Parish and Limestone plants, the region’s coal expenses, excluding January 2007, decreased by $13 million due to a 9% reduction in average contracted coal prices. | | | — | Fuel contract amortization— decreased by approximately $43 million, excluding January 2007, due to declining forward fuel price curves below the contracted prices used at the Acquisition. | | | — | Purchased ancillary service expense— increased by approximately $34 million due to favorable market prices in purchasing this service in the market compared to providing the service from internal resources. |
| | | | o | Northeast— cost of energy increased by $26 million primarily due to $30 million in higher natural gas costs related to increased generation at the region’s Arthur Kill plant due to its locational advantage to New York City following transmission constraints during the last three quarters of 2007. | | | o | South Central— cost of energy increased by $104 million due to increases in purchased energy, coal costs and transmission costs. |
| | | | — | Purchased energy— increased by approximately $69 million due to increased market purchases following increased cooperative load requirements and planned maintenance at the region’s Big Cajun II facility. | | | — | Coal costs— increased by approximately $17 million, of which $11 million was related to a 9% increase in coal prices and $7 million due to higher coal transportation costs. | | | — | Transmission costs— increased by approximately $16 million of which $6 million was due to contractual increases related to network transmission service. Point-to-point transmission costs also increased by $10 million reflecting more off-system sales. |
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| | | | o○ | WestGeneration— Cost of energy decreased by approximately $764% resulting in a $116 million excludingdecrease in sales volume. This decrease was driven by a 9% decrease in coal plant generation. This decrease was offset by a 12% increase in gas plant generation, and generation from the first quarter 2007, due to new tolling agreement entered into atrecently constructed Cedar Bayou 4 gas plant, the EncinaElbow Creek wind farm, and the Langford wind farm which began commercial operations in June 2009, December 2008 and December 2009, respectively. Coal plant generation was adversely affected by lower energy prices driven by a 56% decrease in 2007, which requiresaverage natural gas prices in combination with increased wind generation in the counterparty to supply their own fuel. Under the previous arrangement in 2006, the plant supplied the fuel. |
| | | | • | Other operating costs —Other operating costs which include operations and maintenance expenses, or O&M, increased by $137 million, to $950 million, for the year ended December 31, 2007, compared to 2006. This increase was due to: |
| | | | o | Texas— other operating costs increased by $75 million, after excluding January 2007 expense of $39 million, other operating costs increased by $36 million. This $36 million increase was due to $25 million in higher O&M expense as a result of increased maintenance associated with planned outages and fuel handling at the W.A. Parish facility and $10 million in higher property tax expenses following an increased valuation after the Acquisition.region. | | | o○ | NortheastMargin on MWH sold from market purchases— other operating costs increaseddecreased by $18 million due to increased staffing costs and higher maintenance costs. | | | o | South Central —other operating costs increased by approximately $28 million, $19 million of which was due to increased maintenance expense primarily related to planned outages. Additionally, the region disposed of $4 million in assets in conjunction with the outage. | | | o | Acquisition of WCP —these results include $15 million of WCP expenses that were not included in the Company’s results in 2006.$62 million. |
• Capacity revenue— decreased by $300 million due to a lower proportion of baseload contracts which contain a capacity component. • Risk management activities — decreased by $89 million reflecting the difference between gains of $228 million recorded for the year ended December 31, 2009, compared to gains of $318 million during the same period in 2008. The $89 million decrease included $102 million of unrealizedmark-to-market losses and $330 million in gains on settled transactions, or financial income, compared to $413 million in unrealizedmark-to-market gains and $95 million in financial losses during the same period in 2008. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations. • Contract amortization revenue— resulting from the Texas Genco acquisition decreased by $198 million due to the reduced volume of contracted energy in 2009 as compared to 2008. • Other revenues— decreased by $62 million primarily due to lower ancillary services revenue of $47 million provided to the market, and lower emissions credit revenue of $11 million. Cost of Energy Cost of energy decreased by $277 million during the year ended December 31, 2009, compared to the same period in 2008, due to: • Natural gas costs— decreased by $281 million due to a 56% decline in average natural gas prices offset by a 12% increase in gas-fired generation. • Ancillary service costs— decreased by $44 million due to a decrease in purchased ancillary services costs incurred to meet contract obligations. These decreases were offset by: • Fuel risk management activities— losses of $27 million were recorded for the year ended December 31, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified intomark-to-market accounting. The $27 million loss included $8 million of unrealizedmark-to-market losses, largely associated with forward coal positions and $19 million in losses on settled transactions, or financial cost of energy. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations. • Coal costs —increased by $5 million driven by a $44 million increase in coal prices, offset by a $28 million decrease in coal volume. Additionally, an increase in higher transportation costs of $9 million was offset by a $15 million loss reserve related to a coal contract dispute in the first quarter of 2008, combined with a decrease of $3 million due to lower lignite royalties. • Cost Contract Amortization —increased $19 million driven primarily by the reduction in amortization forout-of-the money coal contracts assumed in the acquisition of Texas Genco as coal is delivered under that contract. Other Operating Expenses Other operating expenses increased by $21 million during the year ended December 31, 2009, compared to the same period in 2008, driven by an increase of $14 million in general and administrative expense due to higher corporate allocations as a result of the change in method in allocating corporate costs as described in Item 14 — Note 18,Segment Reporting,to the Consolidated Financial Statements. In addition, there was an increase of 98
$3 million for operations and maintenance costs, as well as an increase of $3 million in property and other taxes due to the recently constructed Cedar Bayou 4 and Elbow Creek facilities. Depreciation and Amortization NRG’s depreciationDepreciation and amortization expense for the year ended December 31, 2007 increased by $68 million compared to 2006. This increase was due to:
| | | | • | Texas acquisition —the inclusion of Texas results for twelve months in 2007 compared to eleven months in 2006 resulted in an increase of approximately $38 million. | | | • | Impact of new environmental legislation —due to new and more restrictive environmental legislation, the useful life of certain pollution control equipment has been reduced. The Company accelerated depreciation on certain equipment in its Northeast region to reflect the remaining useful life, resulting in increased depreciation of approximately $13 million. |
General and Administrative
NRG’s G&A costs for the year ended December 31, 2007 increased by $33 million compared to 2006, and as a percentage of revenues was 5% in both 2007 and 2006. This increase was due to:
| | | | • | Texas and WCP acquisitions —the inclusion of Texas results for twelve months in 2007 compared to eleven months in 2006 and the consolidation of WCP for the last three quarters of 2006 resulted in an increase of approximately $9 million. | | | • | Wage and benefit costs —due to the expansion of the Company, includingRepoweringNRG initiatives, wages and related benefits costs resulted in a $28 million increase in G&A. Additionally, information technology and other office services to support this expansion increased by $8 million. | | | • | Franchise tax —the Company’s Louisiana state franchise tax increased by approximately $6 million. This increase was because the state’s franchise tax was assessed based on the Company’s total debt and equity that rose significantly following the acquisition of Texas Genco. | | | • | Non-recurring expenses during 2006 —for the year ended December 31, 2006, G&A included non-recurring fees of $20 million of which $6 million were related to the unsolicited takeover attempt by Mirant Corporation and $14 million associated with the Texas integration efforts. |
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Development Costs
NRG’s development costs for the year ended December 31, 2007 increased by $65 million. These costs were due to the Company’sRepoweringNRG projects:
| | | | • | Texas —on September 24, 2007, NRG filed a COLA with the NRC to build and operate two new nuclear units at the STP site. During the period, NRG incurred $91 million in development costs related to STP units 3 and 4 project in 2007. These development costs were reduced by a $39 million reimbursement related to a partnership agreement signed during the fourth quarter 2007. | | | • | Wind projects —approximately $13 million in development costs related to wind projects primarily in Texas. | | | • | Other project —approximately $4 million in development costs related to otherRepoweringNRG projects in the West region. |
Gain on Sale of Assets
NRG’s net gain on sale of assets for the year ended December 31, 2007, was approximately $17 million. On January 3, 2007, NRG completed the sale of the Company’s Red Bluff and Chowchilla II power plants resulting in a pre-tax gain of approximately $18 million.
Equity in Earnings of Unconsolidated Affiliates
NRG’s equity earnings from unconsolidated affiliates for the year ended December 31, 2007, decreased by $6 million compared to 2006. This decrease was due to the sale of multiple equity investments from which the Company earned $8$21 million for the year ended December 31, 2006.
Other Income, Net
NRG’s other income for the year ended December 31, 2007, decreased by $101 million2009, compared to 2006. This decrease was due to the non-cash settlement during the first quarter 2006 where NRG recorded $67 million of other income associated with a settlement with an equipment manufacturer related to turbine purchase agreements entered intosame period in 1999 and 2001. The settlement resulted in the reversal of accounts payable totaling $35 million resulting from the discharge of the previously recorded liability, and an adjustment to write up the value of the equipment received to its fair value, resulting in income of approximately $32 million. Additionally, in 2006, other income was favorably impacted by a $13 million non-cash gain associated with the discharge of liabilities upon dissolution of an inactive legal entity and a $5 million non-cash gain due to a favorable settlement with respect to post closing adjustments on the acquisition of the Company’s western New York plants.
During 2007, the Company recorded an $11 million impairment charge in the fourth quarter related to an investment in commercial paper reducing its carrying value to approximately $32 million. The Company earned $10 million less in interest income in 2007 compared to 2006, due to lower average cash balances.
Interest Expense
NRG’s interest expense for the year ended December 31, 2007, increased by $99 million compared to 2006.2008. This increase was due to:
| | | | • | Refinancing for the acquisition of Texas Genco in February 2006 — the Company significantly increased its corporate debt facilities from approximately $2 billion as of December 31, 2005, to approximately $7 billion as of February 2, 2006. This increased interest expense by approximately $12 million compared to 2006. | | | • | Increase of $1.1 billion in debt for Hedge Reset —the Company issued $1.1 billion in Senior Notes due 2017 in November 2006 related to the Hedge Reset, which increased interest expense by approximately $72 million. |
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| | | | • | Capital Allocation Program —the Company issued a total of $330 million of debt to fund Phase I of the Capital Allocation Program during the second half of 2006. This increased interest expense by $20 million compared to 2006. |
In the first quarter 2006, NRG entered into interest rate swaps with the objectiveresult of fixing the interest rate on a portion of NRG’s Senior Credit Facility. These swaps were designated as cash flow hedges under SFAS 133,Cedar Bayou 4 and the impact associated with ineffectiveness was immaterial to NRG financial results. For the year endedElbow Creek reaching commercial operations in June 2009 and December 31, 2007, NRG had a deferred loss of $31 million in other comprehensive income compared to deferred gains of $16 million in 2006.
Refinancing Expense
Refinancing expense decreased by $152 million for the year ended December 31, 2007, compared to 2006, due to higher expense for the refinancing of the Company’s corporate debt for the acquisition of Texas Genco on February 2, 2006, compared to the refinancing of the Company’s Senior Credit Facility during 2007.
On June 8, 2007, NRG completed a $4.4 billion refinancing of the Company’s Senior Credit Facility previously announced on May 2, 2007. The transaction resulted in a 0.25% reduction on the spread that the Company pays on its Term Loan Facility and Synthetic Letter of Credit Facility, a $200 million reduction in the Synthetic Letter of Credit Facility to $1.3 billion, and various amendments to provide improved flexibility, efficiency for returning capital to shareholders, asset repowering and investment opportunities. The pricing on the Company’s Term Loan Facility and Synthetic Letter of Credit are also subject to further reductions upon the achievement of certain financial ratios. The refinancing resulted in a charge of approximately $35 million to the Company’s results of operations that were primarily related to the write-off of deferred financing costs as the lenders for approximately 45% of the Term Loan Facility either exited the financing or reduced their holdings and were replaced by other institutions.
Income Tax Expense
Income tax expense increased by $55 million for the year ended December 31, 2007, compared to 2006. The effective tax rate was 39.9% and 37.2% for the year ended December 31, 2007 and 2006,2008, respectively.
| | | | | | | | | | | Year Ended December 31, | | | | 2007 | | | 2006 | | | | (In millions
| | | | except otherwise stated) | | | Income from continuing operations before income taxes | | $ | 946 | | | $ | 865 | | | | | | | | | | | Tax at 35% | | | 331 | | | | 303 | | State taxes, net of federal benefit | | | 46 | | | | 34 | | Foreign operations | | | (13 | ) | | | (21 | ) | Subpart F taxable income | | | — | | | | 11 | | Valuation allowance, including change in state effective rate | | | 6 | | | | (10 | ) | Change in state effective tax rate | | | — | | | | 21 | | Claimant reserve settlements | | | — | | | | (28 | ) | Change in local German effective tax rates | | | (29 | ) | | | — | | Foreign dividends | | | 26 | | | | 1 | | Non-deductible interest | | | 10 | | | | 3 | | Permanent differences, reserves, other | | | — | | | | 8 | | | | | | | | | | | Income tax expense | | $ | 377 | | | $ | 322 | | | | | | | | | | | Effective income tax rate | | | 39.9 | % | | | 37.2 | % |
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The increase in income tax expense was primarily due to:
| | | | • | Increase in profits —income before tax increased by $81 million, with a corresponding increase of approximately $32 million in income tax expense. | | | • | Permanent differences —the Company’s effective tax rate differs from the US statutory rate of 35% due to: |
| | | | o | Change in German tax rate— due to a reduction in the German statutory and resulting effective tax rate, income tax expense benefited by $29 million for the year-ended 2007. | | | o | Taxable dividends from foreign subsidiaries— in January 2007, the Company transferred the proceeds from the sale of its Flinders assets to the US creating additional income tax expense of approximately $25 million. | | | o | Lower tax rates in foreign jurisdictions— lower income tax rates at the Company’s foreign locations resulted in additional income tax expense during 2007 compared to 2006 of $8 million. | | | o | Non-deductible interest— interest expense from the stock buybacks from Phase I of the Company’s Capital Allocation Program was non-deductible for income tax purposes, thus increasing income tax expense by approximately $7 million. | | | o | Change in state effective tax rate— the state effective tax rate remained unchanged for 2007. This resulted in a net decrease in income tax expense of approximately $5 million as compared to 2006, after taking into account the movement in valuation allowance as a result of the change in rate from 2005 to 2006. | | | o | Subpart F taxable income— a dividend was declared and paid in 2007 by NRGenerating International B.V. As result of this dividend, there was no Subpart F income compared to 2006. This resulted in a decrease to income tax expense of approximately $11 million. | | | o | Disputed claims reserve— During 2007 as compared to 2006, the Company made no distribution from its disputed claims reserve, this increased income tax expense by approximately $28 million. |
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with SFAS 109. These factors and others, including the Company’s history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.
Income from Discontinued Operations, Net of Income Tax Expense
For the years ended December 31, 2007 and 2006, NRG recorded income from discontinued operations, net of income tax expense of $17 million and $78 million, respectively. Discontinued operations for the year ended December 31, 2007 were comprised of the results of ITISA. Discontinued operations for the year ended December 31, 2006 were comprised of the results of ITISA, Flinders, Audrain and Resource Recovery. NRG closed on the sale of Flinders during the third quarter 2006 and recognized an after-tax gain of approximately $60 million from the sale.
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Results of Operations — Regional Discussions
Texas Region
2008 compared to 2007 The following table provides selected financial information for the Texas region for the yearyears ended December 31, 2008 and the period ended December 31, 2007. | | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2008 | | | 2007 | | | Change % | | | | (In millions except
| | | | | | | otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 2,870 | | | $ | 2,698 | | | | 6 | % | Capacity revenue | | | 493 | | | | 363 | | | | 36 | | Risk management activities | | | 318 | | | | (33 | ) | | | N/A | | Contract amortization | | | 255 | | | | 219 | | | | 16 | | Other revenues | | | 90 | | | | 40 | | | | 125 | | | | | | | | | | | | | | | Total operating revenues | | | 4,026 | | | | 3,287 | | | | 22 | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of energy | | | 1,240 | | | | 1,181 | | | | 5 | | Depreciation and amortization | | | 451 | | | | 469 | | | | (4 | ) | Other operating expenses | | | 650 | | | | 668 | | | | (3 | ) | | | | | | | | | | | | | | Operating Income | | $ | 1,685 | | | $ | 969 | | | | 74 | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 47,806 | | | | 49,220 | | | | (3 | ) | MWh generated (in thousands) | | | 46,937 | | | | 47,779 | | | | (2 | ) | Business Metrics | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 96.53 | | | $ | 62.00 | | | | 56 | | Cooling Degree Days, or CDDs(a) | | | 2,719 | | | | 2,707 | | | | — | | CDD’s 30 year rolling average | | | 2,647 | | | | 2,647 | | | | — | | Heating Degree Days, or HDDs(a) | | | 1,961 | | | | 1,949 | | | | 1 | | HDD’s 30 year rolling average | | | 2,007 | | | | 1,997 | | | | 1 | % |
| | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2008 | | | 2007 | | | Change % | | | | (In millions except otherwise noted) | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 2,870 | | | $ | 2,698 | | | | 6 | % | Capacity revenue | | | 493 | | | | 363 | | | | 36 | | Risk management activities | | | 318 | | | | (33 | ) | | | N/A | | Contract amortization | | | 255 | | | | 219 | | | | 16 | | Other revenues | | | 90 | | | | 40 | | | | 125 | | | | | | | | | | | | | | | Total operating revenues | | | 4,026 | | | | 3,287 | | | | 22 | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of energy | | | 1,240 | | | | 1,181 | | | | 5 | | Depreciation and amortization | | | 451 | | | | 469 | | | | (4 | ) | Other operating expenses | | | 650 | | | | 668 | | | | (3 | ) | | | | | | | | | | | | | | Operating Income | | $ | 1,685 | | | $ | 969 | | | | 74 | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 47,806 | | | | 49,220 | | | | (3 | ) | MWh generated (in thousands) | | | 46,937 | | | | 47,779 | | | | (2 | ) | Business Metrics | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 86.23 | | | $ | 60.98 | | | | 41 | | Cooling Degree Days, or CDDs(a) | | | 2,719 | | | | 2,707 | | | | — | | CDD’s30-year rolling average | | | 2,647 | | | | 2,647 | | | | — | | Heating Degree Days, or HDDs(a) | | | 1,961 | | | | 1,949 | | | | 1 | | HDD’s30-year rolling average | | | 2,007 | | | | 1,997 | | | | 1 | % |
| | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Operating Income Operating income increased by $716 million for the year ended December 31, 2008, compared to the same period in 2007, primarily due to: | | | | • | Energy revenues— increased by $172 million due to higher merchant energy revenue as a result of higher power prices and sales volumes offset by lower contract energy revenue. | | | • | Capacity revenue— increased by $130 million due to a greater proportion of base-load contracts which contain a capacity component. | | | • | Risk management activities— an increase of $351 million was primarily due to $479 million in greater unrealized derivative gains offset by $128 million in greater realized losses on settled financial transactions. These changes reflect a reduction in forward power and gas prices at the close of the year ended December 31, 2008. |
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• Operating revenues— increased by $739 million due to favorable risk management activities, energy and capacity revenues.
These increases were offset by:• Cost of energy— increased by $59 million reflecting the effects of increased natural gas and coal prices.
| | | | • | Cost of energy— increased by $59 million reflecting the effects of increased natural gas and coal prices. |
Operating Revenues Total operating revenues from the Texas region increased by $739 million during the year ended December 31, 2008, compared to 2007 due to the following: • Risk management activities— gains of $318 million were recognized for the year ended December 31, 2008, compared to a $33 million loss in the same period in 2007. The $318 million included $413 million of unrealizedmark-to-market gains and $95 million in settled losses, or financial 99
revenue. The $413 million was the net effect of a $400 million gain from economic hedge positions and a $25 million loss on reversals ofmark-to-market gains on economic hedges. In addition, there were $37 million in unrealizedmark-to-market gains on trading transactions combined with a $1 million gain on reversals ofmark-to-market losses on trading activity. The $400 million gain from economic hedges incorporated $424 million in unrealized gains in the value of forward sales of electricity and fuel driven by lower power and natural gas prices. These hedges were considered effective economic hedges that do not receive cash flow hedge accounting treatment. The remaining $24 million in losses were from hedge ineffectiveness which was driven by decreasing gas prices while power prices decreased at a slower pace. | | | | • | Risk management activities— gains of $318 million were recognized for the year ended December 31, 2008, compared to a $33 million loss in the same period in 2007. The $318 million included $413 million of unrealized mark-to-market gains and $95 million in settled losses, or financial revenue. The $413 million was the net effect of a $400 million gain from economic hedge positions and a $25 million loss on reversals of mark-to-market gains on economic hedges. In addition, there were $37 million in unrealized mark-to-market gains on trading transactions combined with a $1 million gain on reversals of mark-to-market losses on trading activity. The $400 million gain from economic hedges incorporated $424 million in unrealized gains in the value of forward sales of electricity and fuel driven by lower power and natural gas prices. These hedges were considered effective economic hedges that do not receive cash flow hedge accounting treatment. The remaining $24 million in losses were from hedge ineffectiveness which was driven by decreasing gas prices while power prices decreased at a slower pace. | | | • | Energy revenuesrevenue— increased by $172 million due to: |
| | | | o○ | Energy prices —increased by $219$430 million as the average realized merchant price was higher in 2008 due to the combination of higher gas prices and unusually high pricing events. The average realized energy price increased by 18%, driven by a more favorable mix of merchant versus contract sales resulting in a 28%44% increase in merchant prices offset by a 14%16% decrease in contract energy prices. | | | o○ | Generation —decreased by 839 thousand MWh or 2%. resulting in a $42 million decline in sales volume. This decrease in generation was due to a 3% decline in nuclear generation at STP, as a result of additional plant outages, and a 14% decline in overall gas plant generation for the year ended December 2008. Hurricane Ike in September 2008 caused major damage to the Houston area transmission grid which reduced significantly the demand for power causing a decrease in gas-fired generation. These declines were offset by a 1% increase in coal generation in 2008. |
| | | | • | Capacity revenue— increased by $130 million due to a greater proportion of base-load contracts which contain a capacity component. | | | • ○ | Other revenuesMargin on MWh sold from market purchases —increaseddecreased by $50 million related to a $23 million increase in ancillary services revenue in 2008, a $22 million increase of allocations for trading of emission allowances and carbon financial instruments, and increased activity in trading natural gas and coal of $4$216 million. | | | • | Contract amortization revenue— increased by $36 million due to the volume of contracted energy being positively affected by a greater spread between contract prices and market prices used in the Texas Genco purchase accounting. |
• Capacity revenue— increased by $130 million due to a greater proportion of base-load contracts which contain a capacity component. • Other revenue —increased by $50 million related to a $23 million increase in ancillary services revenue in 2008, a $22 million increase of allocations for trading of emission allowances and carbon financial instruments, and increased activity in trading natural gas and coal of $4 million. • Contract amortization revenue— increased by $36 million due to the volume of contracted energy being positively affected by a greater spread between contract prices and market prices used in the Texas Genco purchase accounting. Cost of Energy Cost of energy for the Texas region increased by $59 million for the year ended December 31, 2008, compared to 2007 due to the following: | | | | • | Natural gas costs— increased by $99 million due to a 28% rise in average gas prices offset by a 14% decrease in gas-fired generation. | | | • | Coal costs— increased by $44 million due to higher coal prices and the settlement of a coal contract dispute. | | | • | Ancillary services— increased by $14 million due to a $16 million rise in ancillary service costs purchased through ERCOT, offset by a $2 million decrease in other purchased ancillary services costs. |
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• Coal costs— increased by $44 million due to higher coal prices and the settlement of a coal contract dispute. • Ancillary service costs— increased by $14 million due to a $16 million rise in ancillary service costs purchased through ERCOT, offset by a $2 million decrease in other purchased ancillary service costs. These increases were partially offset by: | | | | • | Amortized contract costs— decreased by $59 million due to a $36 million decrease in the amortization of water supply contracts which ended in 2007. In addition, the amortization of coal contracts decreased by a net $22 million as a result of a reduction in expense related to in-the-money coal contract amortization. These contracts were established under Texas Genco purchase accounting. | | | • | Nuclear fuel expense— decreased by $19 million as amortization of nuclear fuel inventory established under Texas Genco purchase accounting ended in early 2008. | | | • | Purchased power— decreased by $26 million due to lower forced outage rates at the region’s baseload plants. |
• Amortized contract costs— decreased by $59 million due to a $36 million decrease in the amortization of water supply contracts which ended in 2007. In addition, the amortization of coal contracts decreased by a net $22 million as a result of a reduction in expense related toin-the-money coal contract amortization. These contracts were established under Texas Genco purchase accounting. • Nuclear fuel expense— decreased by $19 million as amortization of nuclear fuel inventory established under Texas Genco purchase accounting ended in early 2008. 100
• Purchased power— decreased by $26 million due to lower forced outage rates at the region’s baseload plants. Other Operating Expenses Other operating expenses for the Texas region decreased by $18 million for the year ended December 31, 2008, compared to 2007 due to the following: | | | | • | Development costs— decreased by $59 million primarily due to the initial costs for developing the nuclear units 3 and 4 at STP associated with theRepoweringNRG initiative that began in 2007. Costs for STP nuclear units 3 and 4 are being capitalized in 2008. |
• Development costs— decreased by $59 million primarily due to the initial costs for developing the nuclear Units 3 and 4 at STP associated with theRepoweringNRG initiative that began in 2007. Costs for STP nuclear Units 3 and 4 are being capitalized in 2008. This decrease was primarily offset by: | | | | • | Operations &• Operations and maintenance expense— increased by $32 million due to an additional planned outage at STP and the acceleration of planned outages at the baseload plants. | | | • | General and Administrative expense— increased by $10 million driven by higher corporate allocations. |
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• General and administrative expense— increased by $10 million driven by higher corporate allocations. 2007Northeast Region
2009 compared to 20062008 The following table provides selected financial information for the TexasNortheast region for the yearyears ended December 31, 2007,2009, and the period ended December 31, 2006.2008: | | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2007 | | | 2006(b) | | | Change % | | | | (In millions except
| | | | | | | otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 2,698 | | | $ | 1,726 | | | | 56 | % | Capacity revenue | | | 363 | | | | 849 | | | | (57 | ) | Risk management activities | | | (33 | ) | | | (30 | ) | | | 10 | | Contract amortization | | | 219 | | | | 609 | | | | (64 | ) | Hedge Reset | | | — | | | | (129 | ) | | | (100 | ) | Other revenues | | | 40 | | | | 63 | | | | (37 | ) | | | | | | | | | | | | | | Total operating revenues | | | 3,287 | | | | 3,088 | | | | 6 | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of energy | | | 1,181 | | | | 1,276 | | | | (7 | ) | Depreciation and amortization | | | 469 | | | | 413 | | | | 14 | | Other operating expenses | | | 668 | | | | 518 | | | | 29 | | | | | | | | | | | | | | | Operating Income | | $ | 969 | | | $ | 881 | | | | 10 | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 49,220 | | | | 46,361 | | | | 6 | | MWh generated (in thousands) | | | 47,779 | | | | 44,910 | | | | 6 | | Business Metrics | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 62.00 | | | $ | 63.07 | | | | (2 | ) | Cooling Degree Days, or CDDs(a) | | | 2,707 | | | | 3,108 | | | | (13 | ) | CDD’s 30 year rolling average | | | 2,647 | | | | 2,647 | | | | — | | Heating Degree Days, or HDDs(a) | | | 1,949 | | | | 1,533 | | | | 27 | % | HDD’s 30 year rolling average | | | 1,997 | | | | 1,997 | | | | — | |
| | | | | | | | | | | | | | | | | | | Year Ended
| | | | | | | | | | December 31, | | | | | | | | | | 2009 | | | 2008 | | | Change % | | | | | | | (In millions except otherwise noted) | | | | | | | | Operating Revenues | | | | | | | | | | | | | | | | | Energy revenue | | $ | 489 | | | $ | 1,064 | | | | (54 | )% | | | | | Capacity revenue | | | 407 | | | | 415 | | | | (2 | ) | | | | | Risk management activities | | | 277 | | | | 85 | | | | N/A | | | | | | Other revenues | | | 28 | | | | 66 | | | | (58 | ) | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | | 1,201 | | | | 1,630 | | | | (26 | ) | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | Cost of energy | | | 341 | | | | 695 | | | | (51 | ) | | | | | Depreciation and amortization | | | 118 | | | | 109 | | | | 8 | | | | | | Other operating expenses | | | 399 | | | | 392 | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | $ | 343 | | | $ | 434 | | | | (21 | ) | | | | | | | | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 9,220 | | | | 13,349 | | | | (31 | ) | | | | | MWh generated (in thousands) | | | 9,220 | | | | 13,349 | | | | (31 | ) | | | | | Business Metrics | | | | | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 46.14 | | | $ | 91.68 | | | | (50 | ) | | | | | Cooling Degree Days, or CDDs(a) | | | 475 | | | | 611 | | | | (22 | ) | | | | | CDD’s30-year rolling average | | | 537 | | | | 537 | | | | — | | | | | | Heating Degree Days, or HDDs(a) | | | 6,286 | | | | 6,057 | | | | 4 | | | | | | HDD’s30-year rolling average | | | 6,262 | | | | 6,294 | | | | (1 | )% | | | | |
| | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. | | (b) | | For the period February 2, 2006 to December 31, 2006 only. |
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Operating Income ForOperating income decreased by $91 million for the year ended December 31, 2007, operating income increased by $88 million2009, compared to 2006; however, excluding January 2007 results, operating income increasedthe same period in 2008, due to:
• Operating revenues— decreased by $21 million. The primary drivers were:$429 million due to unfavorable energy revenues, other revenues and capacity revenues partially offset by a favorable impact from risk management activities. • Cost of energy — decreased by $354 million due to lower generation and fuel prices. Operating Revenues Operating revenues decreased by $429 million for the year ended December 31, 2009, compared to the same period in 2008, due to: | | | | • | Energy Revenuesrevenue— decreased by $575 million due to: |
| | | | ○ | Energy prices— decreased by $295 million reflecting an average 40% decline in merchant energy prices. | | | ○ | Generation— decreased by $334 million due to a 31% decrease in generation in 2009 compared to 2008, driven by a 31% decrease in coal generation and a 31% decrease in oil and gas generation. Coal generation declined 24%, or 1,471,726 MWhs, in western New York; 39%, or 1,503,975 MWhs, at Indian River; and 80%, or 476,537 MWh, at Somerset. The decline in generation at these plants is due to a combination of weakened demand for eleven monthspower, low gas prices and higher cost of 2007production from the introduction of RGGI resulting in increased hours where the units were uneconomic to dispatch. The decline in oil and gas generation is attributable to fewer reliability run hours at the Norwalk plant and higher maintenance work at the Arthur Kill plant in 2009. | | | ○ | Margin on MWh sold from market purchases— increased by $54 million driven by lower net costs incurred in meeting obligations under load serving contracts in the PJM market. |
• Other revenues— decreased by $38 million due to $20 million from decreased activity in the trading of emission allowances and $17 million lower allocations of net physical gas sales. • Capacity revenue— decreased by $8 million due to lower capacity cash flow revenue in New York in 2009. These decreases were offset by: • Risk management activities— gains of $277 million were recorded for the year ended December 31, 2009, compared to gains of $85 million during the same period in 2008. The $277 million gain included $107 million of unrealizedmark-to-market losses and $384 million in gains on settled transactions, or financial income, compared to $82 million in unrealizedmark-to-market gains and $3 million in financial gains during the same period in 2008. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations. Cost of Energy Cost of energy decreased by $354 million for the year ended December 31, 2009, compared to the same period in 2008, due to: • Natural gas and oil costs— decreased by $187 million, or 60%, due to 31% lower generation and 56% lower average natural gas prices. • Coal costs— decreased by $129 million, or 35%, due to lower coal generation of 31% accounting for $111 million and lower prices accounting for $18 million. The lower prices are due to lower fuel transportation surcharges. • Fuel risk management activities— gains of $60 million were recorded for the year ended December 31, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified to 102
mark-to-market accounting. The $60 million gain included $67 million of unrealizedmark-to-market gains, largely associated with forward coal positions and $7 million in losses on settled transactions, or financial cost of energy. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations. These decreases were offset by: • Carbon emission expense— increased by $22 million due to the January 1, 2009, implementation of RGGI and the recognition of carbon compliance cost under this program. Depreciation and Amortization Depreciation and amortization increased by $9 million primarily due to depreciation from the 2009 baghouse projects at NRG’s Western New York coal plants. Other Operating Expenses Other operating expenses increased by $7 million for the year ended December 31, 2009, compared to the same period in 2008, due to: | | | | • | Property taxes— increased by $14 million due to lower Empire Zone tax benefits recognized in 2009 at the Oswego plant due to the plant receiving notice of decertification from the Empire Zone program in 2009 from the State of New York which decision is under appeal by the Company. | | | • | Write-down of assets— increased by $12 million for the year ended December 31, 2009, compared to the same period in 2006 were up by $755 million, $449 million of which2008. The write-down was due to the Hedge Reset transaction, ascancellation and subsequent write off of construction costs incurred through year end 2009 on the average priceIndian River Unit 3 air pollution control equipment project. NRG and DNREC announced a proposed plan, subject to definitive documentation, that would shut down Unit 3 by December 31, 2013, and relieve NRG of the underlying power contractsrequirement to install this back-end control equipment. Unit 4 is not affected by this plan and construction on similar equipment continues with an expected in-service date of year-end 2011. | | | • | General and administrative expense— increased by $13 per MWh compared to average contract prices prior to the hedge reset. The balance of the increase in energy revenues was$2 million due to higher labor and employee benefit costs. | | | • | Development costs— increased by $2 million due to increased repowering efforts at the sale of additional output as energy rather than under PUCT mandated capacity auctions.Astoria plant and a biomass project at the Montville plant. |
This favorable resultThese increases was offset by:
| | | | • | Capacity RevenuesOperations and maintenance expenses— reduction in capacity auction sales reduced capacity revenues by approximately $517 million, excluding January 2007. |
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| | | | • | Contract Amortization— the Hedge Reset transaction decreased contract amortization by approximately $498 million, excluding January 2007. | | | • | Gas-fired Generation —lower natural gas-fired generation of approximately 2.7 million MWh, for the comparable eleven month period in 2007, was a result of cooler summer weather coupled with increased economic purchases of energy and ancillary services from the ERCOT. Lower sales revenue for the eleven months was offset by natural lower natural gas fuel costs of $170 million and cash flow economic hedge improvements. | | | • | Development Costs— increased by $44 million in 2007 compared to 2006 largely due to the development of STP nuclear units 3 and 4 project, including $2 million of expenses in January 2007. The $44 million increase also includes $39 million in reimbursements from a partnership agreement signed in the fourth quarter 2007. |
Operating Revenues
Total operating revenues from the Texas region increased by $199 million during the year ended December 31, 2007, compared to 2006. Excluding January 2007, operating revenues decreased by $56 million. This decrease was due to:
| | | | • | Energy revenues— energy revenues increased by $972 million, of which $217 million was due to the inclusion of twelve months activity in 2007 compared to eleven months in 2006. Of the remaining $755 million increase, $449 million was due to the Hedge Reset transaction which resulted in higher 2007 average contracted prices of approximately $13 per MWh. In addition, revenues from 8.8 million MWh of generation moved from capacity revenue to energy revenue. Prior to the Acquisition, PUCT regulations required that NRG Texas sell 15% of its capacity by auction at reduced rates. In March 2006, the PUCT accepted NRG’s request to no longer participate in these auctions and that capacity is now being sold in the merchant market. These favorable results were partially offset by lower sales from natural gas-fired units due to a cooler summer which resulted in lower natural gas-fired generation of approximately 2.7 million MWh. | | | • | Other revenues— the region’s other revenues decreased by $27 million for the eleven months of 2007 compared to 2006. This was due to a decrease in intercompany emission allowance sales of $40 million and a $19 million decrease in physical gas sales. This $59 million decrease was offset by a $33 million increase in ancillary services revenue due to a change in strategy to more actively provide ancillary services in the Texas region. | | | • | Capacity revenues— capacity revenues decreased by $517 million, excluding $31 million incurred in January 2007. This decrease was due to the reduction of capacity auction sales mandated by the PUCT in prior years as described above. | | | • | Contract amortization— revenues from contract amortization excluding January 2007 decreased by $405 million primarily due to the write-off of out-of-market power contracts during the fourth quarter 2006 related to the Hedge Reset transaction. | | | • | Risk management activities— The Texas region recorded a total of $33 million in derivative losses for the year ended December 31, 2007, compared to a $30 million loss for the year ended December 31, 2006. The Texas region’s 2007 derivative loss was comprised of $66 million of mark-to-market losses and $33 million in settled gains, or financial revenue. Of the $66 million of mark-to-market losses, $83 million represents the reversal of mark-to-market gains previously recognized on economic hedges and $1 million from the reversal of mark-to-market gains previously recognized on trading activity. Both of these losses ultimately settled as financial revenues during 2007. The $19 million gain from economic hedge positions was comprised of an $8 million increase in the value of forward sales of electricity and fuel due to favorable power and natural gas prices and a $11 million gain from hedge accounting ineffectiveness. This ineffectiveness was primarily related to gas swaps and collars due to a change in the correlation between natural gas and power prices. |
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Cost of Energy
Cost of energy for the Texas region decreased by $95 million for the year ended December 31, 2007, compared to 2006. This included an additional month’s expense for January 2007 of $96 million, without which cost of energy would have decreased by $191 million. This decrease was due to:
| | | | • | Fuel expense — natural gas expense decreased by $170 million, excluding the January 2007 expense of $27$22 million due to a decrease of 2.7 million MWh in natural gas-fired generationlower chemical spending and routine maintenance work as a result of cooler summer weather, coupled with greater economic purchases of energylower generation and ancillary services from the ERCOT and increased baseload generation. Coal expenses, excluding January 2007, decreased by $13 million due to a 9% reduction in average contracted coal prices in 2007, despite a 1.1 million MWh increase in coal-fired generationlower planned major maintenance work at the region’s W.A. ParishHuntley and LimestoneIndian River plants. | | | • | Purchased ancillary service— increased by approximately $34 million due to the favorable market prices in purchasing this service in the market compared to providing the service from internal resources causing an associated decrease in natural gas expense. | | | • | Fuel contract amortization— decreased by approximately $43 million, excluding January 2007, due to declining forward fuel price curves below the contracted prices used at acquisition in February 2006. |
Other Operating Expenses
Other operating expenses for the Texas region increased by $150 million for the year ended December 31, 2007, compared to 2006. This included an additional month’s expense for January 2007, of $53 million, without which other operating expenses would have increased by $97 million. This increase was due to:
| | | | • | Development costs— on September 24, 2007, NRG filed a COLA with the NRC. The Company incurred $91 million in development costs related to STP nuclear unit 3 and 4 project in 2007, including $2 million in January 2007, compared to development costs of $14 million in 2006. Of the $91 million incurred this year, $39 million was reimbursed through a partnership agreement in the fourth quarter 2007. Fossil development costs were $6 million in 2007. | | | • | Plant O&M expense— increased by $25 million, excluding January 2007, due to increased maintenance associated with planned outages and fuel handling at W.A. Parish, increased maintenance related to higher utilization in 2006 of the region’s natural gas fleet, and retirement of older assets. | | | • | Corporate allocations— were higher by approximately $16 million. | | | • | Property tax expense— increased by approximately $10 million related to the Texas acquisition. |
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Northeast Region
2008 compared to 2007 The following table provides selected financial information for the Northeast region for the years ended December 31, 2008, and 2007: | | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2008 | | | 2007 | | | Change % | | | | (In millions except
| | | | | | | otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 1,064 | | | $ | 1,104 | | | | (4 | )% | Capacity revenue | | | 415 | | | | 402 | | | | 3 | | Risk management activities | | | 85 | | | | 27 | | | | 215 | | Other revenues | | | 66 | | | | 72 | | | | (8 | ) | | | | | | | | | | | | | | Total operating revenues | | | 1,630 | | | | 1,605 | | | | 2 | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of energy | | | 695 | | | | 641 | | | | 8 | | Depreciation and amortization | | | 109 | | | | 102 | | | | 7 | | Other operating expenses | | | 392 | | | | 404 | | | | (3 | ) | | | | | | | | | | | | | | Operating Income | | $ | 434 | | | $ | 458 | | | | (5 | ) | | | | | | | | | | | | | | MWh sold (in thousands) | | | 13,349 | | | | 14,163 | | | | (6 | ) | MWh generated (in thousands) | | | 13,349 | | | | 14,163 | | | | (6 | ) | Business Metrics | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 91.70 | | | $ | 76.37 | | | | 20 | | Cooling Degree Days, or CDDs(a) | | | 611 | | | | 702 | | | | (13 | ) | CDD’s 30 year rolling average | | | 537 | | | | 537 | | | | — | | Heating Degree Days, or HDDs(a) | | | 6,057 | | | | 6,074 | | | | — | | HDD’s 30 year rolling average | | | 6,294 | | | | 6,261 | | | | 1 | % |
| | | | | | | | | | | | | | | | | | | Year Ended
| | | | | | | | | | December 31, | | | | | | | | | | 2008 | | | 2007 | | | Change % | | | | | | | (In millions except otherwise noted) | | | | | | | | Operating Revenues | | | | | | | | | | | | | | | | | Energy revenue | | $ | 1,064 | | | $ | 1,104 | | | | (4 | )% | | | | | Capacity revenue | | | 415 | | | | 402 | | | | 3 | | | | | | Risk management activities | | | 85 | | | | 27 | | | | 215 | | | | | | Other revenues | | | 66 | | | | 72 | | | | (8 | ) | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | | 1,630 | | | | 1,605 | | | | 2 | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | Cost of energy | | | 695 | | | | 641 | | | | 8 | | | | | | Depreciation and amortization | | | 109 | | | | 102 | | | | 7 | | | | | | Other operating expenses | | | 392 | | | | 404 | | | | (3 | ) | | | | | | | | | | | | | | | | | | | | | | Operating Income | | $ | 434 | | | $ | 458 | | | | (5 | ) | | | | | | | | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 13,349 | | | | 14,163 | | | | (6 | ) | | | | | MWh generated (in thousands) | | | 13,349 | | | | 14,163 | | | | (6 | ) | | | | | Business Metrics | | | | | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 91.68 | | | $ | 76.37 | | | | 20 | | | | | | Cooling Degree Days, or CDDs(a) | | | 611 | | | | 702 | | | | (13 | ) | | | | | CDD’s30-year rolling average | | | 537 | | | | 537 | | | | — | | | | | | Heating Degree Days, or HDDs(a) | | | 6,057 | | | | 6,074 | | | | — | | | | | | HDD’s30-year rolling average | | | 6,294 | | | | 6,261 | | | | 1 | % | | | | |
| | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Operating Income Operating income decreased by $24 million for the year ended December 31, 2008, compared to 2007, due to: | | | | • | Cost of energy— increased by $54 million due to higher coal costs, increased coal transportation surcharges and higher natural gas prices. The increase was offset by lower oil costs from lower oil-fired generation. |
• Cost of energy— increased by $54 million due to higher coal costs, increased coal transportation surcharges and higher natural gas prices. The increase was offset by lower oil costs from lower oil-fired generation. This unfavorable variance was offset by: | | | | • | Operating revenues —increased by $25 million due to higher capacity revenue and risk management revenues partially offset by lower energy revenue. | | | • | Other operating expenses— decreased by $12 million due to lower major maintenance expenses and property taxes offset by higher utilities expense. |
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• Other operating expenses— decreased by $12 million due to lower major maintenance expenses and property taxes offset by higher utilities expense. Operating Revenues Operating revenues increased by $25 million for the year ended December 31, 2008, compared to 2007, due to: • Risk management activities— gains of $85 million were recorded for the year ended December 31, 2008, compared to gains of $27 million during the same period in 2007. The $85 million gain includes $82 million of unrealizedmark-to-market gains and $3 million of gains in settled transactions, or financial revenue. The $82 million unrealized gains is the net effect of a $96 million gain from economic hedge positions, the $13 million loss due to the reversal of previously recognizedmark-to-market gains on economic hedges, the $14 million loss due to the reversal ofmark-to-market gains on trading activity and $13 million in unrealizedmark-to-market gains on trading activity. Gains are driven by increases in power and gas prices. 104
| | | | • | Risk management activities— gains of $85 million were recorded for the year ended December 31, 2008, compared to gains of $27 million during the same period in 2007. The $85 million gain includes $82 million of unrealized mark-to-market gains and $3 million of gains in settled transactions, or financial revenue. The $82 million unrealized gains is the net effect of a $96 million gain from economic hedge positions, the $13 million loss due to the reversal of previously recognized mark-to-market gains on economic hedges, the $14 million loss due to the reversal of mark-to-market gains on trading activity and $13 million in unrealized mark-to-market gains on trading activity. Gains are driven by increases in power and gas prices. | | | • | Capacity revenuesrevenue— increased by $13 million due to: |
| | | | o○ | PJM— capacity revenuesrevenue increased by $20 million reflecting recognition of a year of revenue from the RPM capacity market (effective on June 1, 2007) in 2008 compared to seven months in 2007. | | | o○ | NEPOOL— capacity revenuesrevenue increased $11 million due to increased revenue recognized on the Norwalk RMR contract (effective on June 19, 2007) in 2008 compared to seven months in 2007. | | | o○ | NYISO— capacity revenuesrevenue decreased by $18 million due to unfavorable market prices. The lower capacity market prices are a result of NYISO’s reductions in Installed Reserve Margins and ICAPinstalled capacity in-city mitigation rules effective March 2008. These decreases were offset by higher capacity contract revenue. |
These gains were offset by: | | | | • | Energy revenues —decreased by $40 million due to: |
| | | | o○ | Energy prices— increased by a net $26 million. An$64 million due to an average 6% rise in merchant energy prices resulted in an increase of $64 million. This increase was offset by lower contract revenue of $38 million driven by higher net costs incurred to service PJM contracts as a result of the increase in market energy prices. | | | o○ | Generation— decreased by $66 million due to a net 6% decrease in generation. The decrease in generation represented a 55% decrease in oil-fired generation as these oil-fired plants were not dispatched due to 41% higher average oil prices. In addition, there was a 12% decrease in gas-fired generation related to a cooler summer in 2008 as compared to 2007. Coal generation was flat in 2008 compared to 2007. |
| | | | • ○ | Other revenuesMargin on MWh sold from market purchases— decreased by $6$38 million due to lower allocations of net physical sales in 2008 of $17 million offsetdriven by higher allocations for tradingnet costs incurred to service PJM contracts as a result of emission allowances and carbon financial instruments of $10 million.the increase in market energy prices. |
• Other revenues— decreased by $6 million due to lower allocations of net physical sales in 2008 of $17 million offset by higher allocations for trading of emission allowances and carbon financial instruments of $10 million. Cost of Energy Cost of energy increased by $54 million for the year ended December 31, 2008, compared to the same period in 2007, due to: | | | | • | Coal costs— increased by $61 million due to higher coal costs and fuel transportation surcharges. | | | • | Natural gas costs— increased by $22 million, despite 12% lower generation, due to a 32% higher average natural gas prices. |
These increases were offset by: | | | | • | Oil costs— decreased by $27 million due to lower oil-fired generation of 55% as these plants were not dispatched in 2008 due to 41% higher average oil prices. |
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Other Operating Expenses Other operating expenses decreased by $12 million for the year ended December 31, 2008, compared to the same period in 2007, due to: | | | | • | Major Maintenancemaintenance— decreased $18 million as a result of less outage work at the Norwalk and Indian River plants. | | | • | Property taxes— decreased $10 million due to $4 million in property tax credits received in 2008 at our New York City plants and higher property credits received in 2008 at our Western New York plants. |
• Property taxes— decreased $10 million due to $4 million in property tax credits received in 2008 at the region’s New York City plants and higher property credits received in 2008 at the region’s Western New York plants. These decreases were offset by: | | | | • | Utilities expense— increased by $16 million as a result of a $19 million benefit included in the 2007 utilities cost due to a lower than planned settlement of the station service agreement with CL&P. |
• Utilities expense— increased by $16 million as a result of a $19 million benefit included in the 2007 utilities cost due to a lower than planned settlement of the station service agreement with CL&P. 105
2007South Central Region
2009 compared to 20062008 The following table provides selected financial information for the NortheastSouth Central region for the years ended December 31, 20072009 and 2006:2008: | | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2007 | | | 2006 | | | Change % | | | | (In millions except otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 1,104 | | | $ | 966 | | | | 14 | % | Capacity revenue | | | 402 | | | | 321 | | | | 25 | | Risk management activities | | | 27 | | | | 144 | | | | (81 | ) | Other revenues | | | 72 | | | | 112 | | | | (36 | ) | | | | | | | | | | | | | | Total operating revenues | | | 1,605 | | | | 1,543 | | | | 4 | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of energy | | | 641 | | | | 615 | | | | 4 | | Depreciation and amortization | | | 102 | | | | 89 | | | | 15 | | Other operating expenses | | | 404 | | | | 378 | | | | 7 | | | | | | | | | | | | | | | Operating Income | | $ | 458 | | | $ | 461 | | | | (1 | ) | | | | | | | | | | | | | | MWh sold (in thousands) | | | 14,163 | | | | 13,309 | | | | 6 | | MWh generated (in thousands) | | | 14,163 | | | | 13,309 | | | | 6 | | Business Metrics | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 76.37 | | | $ | 67.73 | | | | 13 | | Cooling Degree Days, or CDDs(a) | | | 702 | | | | 653 | | | | 8 | | CDD’s 30 year rolling average | | | 537 | | | | 537 | | | | — | | Heating Degree Days, or HDDs(a) | | | 6,074 | | | | 5,417 | | | | 12 | % | HDD’s 30 year rolling average | | | 6,261 | | | | 6,261 | | | | — | |
| | | | | | | | | | | | | | | | | | | Year Ended
| | | | | | | | | | December 31, | | | | | | | | | | 2009 | | | 2008 | | | Change % | | | | | | | (In millions except otherwise noted) | | | | | | | | Operating Revenues | | | | | | | | | | | | | | | | | Energy revenue | | $ | 360 | | | $ | 478 | | | | (25 | )% | | | | | Capacity revenue | | | 269 | | | | 233 | | | | 15 | | | | | | Risk management activities | | | (71 | ) | | | 10 | | | | N/A | | | | | | Contract amortization | | | 22 | | | | 23 | | | | (4 | ) | | | | | Other revenues | | | 1 | | | | 2 | | | | (50 | ) | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | | 581 | | | | 746 | | | | (22 | ) | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | Cost of energy | | | 399 | | | | 468 | | | | (15 | ) | | | | | Depreciation and amortization | | | 67 | | | | 67 | | | | — | | | | | | Other operating expenses | | | 109 | | | | 111 | | | | (2 | ) | | | | | | | | | | | | | | | | | | | | | | Operating Income | | $ | 6 | | | $ | 100 | | | | (94 | ) | | | | | | | | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 12,144 | | | | 12,447 | | | | (2 | ) | | | | | MWh generated (in thousands) | | | 10,398 | | | | 11,148 | | | | (7 | ) | | | | | Business Metrics | | | | | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 33.58 | | | $ | 71.25 | | | | (53 | ) | | | | | Cooling Degree Days, or CDDs(a) | | | 1,549 | | | | 1,618 | | | | (4 | ) | | | | | CDD’s30-year rolling average | | | 1,548 | | | | 1,547 | | | | — | | | | | | Heating Degree Days, or HDDs(a) | | | 3,521 | | | | 3,672 | | | | (4 | ) | | | | | HDD’s30-year rolling average | | | 3,604 | | | | 3,623 | | | | (1 | )% | | | | |
| | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
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Operating Income Operating income decreased by $3$94 million for the year ended December 31, 2007,2009, compared to 2006,the same period in 2008 due to: | | | | • | Cost of energy— increased by approximately $26 million due to a 6% increase in generation at the region’s coal and natural gas-fired plants. | | | • | Other operating expenses— increased by $26 million primarily due to increased maintenance and staffing costs combined with higher property tax. | | | • | Depreciation— increased by $13 million reflecting the additional depreciation expense following the reduction in estimated useful lives of certain components of the region’s power plants as a result of new environmental regulation. | | | • | Offset by higher operating revenues— of approximately $62 million due to increased generation, favorable pricing and the favorable impact from new capacity markets. This was partially offset by lower gains in the region’s risk management activities and lower sales of emission allowances due to a 28% reduction in market prices. |
• Operating revenues— declined by $165 million as a result of decreases in energy revenue, risk management activities and other revenue. These decreases were offset by an increase in capacity revenue. • Cost of energy — declined by $69 million due to lower purchased energy, fuel and transmission costs, offset by higher fuel risk management activities. Operating Revenues Operating revenues increaseddecreased by $62$165 million for the year ended December 31, 2007,2009, compared to 2006,the same period in 2008, due to: | | | | • | Energy revenues —increased by approximately $138 million, of which $61 million was due to increased generation, and $88 million due to a 9% increase in average realized market prices partially offset by an $11 million reduction in contracted bilateral energy revenues. |
• Energy revenue— decreased by $118 million due to a $80 million decline in contract revenue, a $2 million decrease in merchant energy revenue and a $36 million decrease in margin on MWh sold from market purchases. The contract revenue decrease was attributed to a 10% decrease in sales volumes and a $5.15 per MWh lower average realized price. The decline in contract energy price was driven by a $16 million decrease in fuel cost pass-through to the cooperatives reflecting an overall decline in natural gas prices. Also contributing to the decline in contract revenue was a $60 million decrease due to the expiration of a | | | | o | Generation— increased by 6%, primarily driven by increases at the region’s Arthur Kill, Oswego and Indian River plants. The Arthur Kill plant increased generation by 448 thousand MWh due to transmission constraints around New York City, the Oswego plants’ generation increased by 127 thousand MWh due to a colder winter during 2007 compared to 2006, and Indian River plants’ generation increased by 418 thousand MWh due to stronger pricing and fewer outages. | | | o | Price— on average, realized prices in the Northeast increased by 9% due to a mix of higher priced New York City generation coupled with improved economic energy hedge trading resulting in a $37 million increase in energy revenues. |
| | | | • | Capacity revenues— increased by $81 million, of which $39 million was from the region’s NEPOOL assets, $36 million from the region’s PJM assets and $6 million from the region’s New York Rest of State assets. |
| | | | o | NEPOOL— The region’s NEPOOL assets benefited from the new LFRM market and transition capacity market, both of which were introduced in the fourth quarter 2006. Capacity revenues increased by $24 million from the LFRM market and $18 million from transition capacity payments, which were partially offset by a $3 million reduction due to the expiration of an RMR agreement for the region’s Devon plant on December 31, 2006 and by RMR payments from the region’s Norwalk plant which began in the third quarter 2007. | | | o | PJM— On June 1, 2007, the new RPM capacity market became effective in PJM increasing capacity revenues by approximately $36 million. | | | o | NYISO— New York Rest of State capacity prices increased by 75% as load requirement growth increased demand for capacity. This was coupled with the impact from the new capacity markets in NEPOOL which reduced exported supply into the New York market that further improved the supply/demand dynamics. |
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contract with a regional utility. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower prices resulting in a $2 million decline in revenue. • Risk management activities— losses of $71 million were recorded for the year ended December 31, 2009, compared to gains of $10 million during the same period in 2008. The $71 million loss included $78 million of unrealizedmark-to-market losses offset by $7 million in gains on settled transactions, or financial income, compared to $26 million in unrealizedmark-to-market gains offset by $16 million in financial losses during the same period in 2008. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations. These decreases were partially offset by: | | | | • | Risk management activities— The Northeast region recorded $27 million in derivative gain for the year ended December 31, 2007 compared to a $144 million gain for the year ended December 31, 2006. The region’s 2007 derivative gain was comprised of $16 million of mark-to-market losses and $43 million in settled gains, or financial revenue. Of the $16 million of mark-to-market losses, $45 million represents the reversal of mark-to-market gains previously recognized on economic hedges and $12 million from the reversal of mark-to-market gains previously recognized on trading activity. Both of these losses ultimately settled as financial revenues during 2007. The region also recognized a $15 million unrealized gain from economic hedge positions which was comprised primarily of a $13 million increase in the value of forward sales of electricity and fuel due to favorable power and gas prices. The region also recognized a $26 million unrealized gain associated with the Company’s trading activity. The $144 million derivative gain for the year ended December 31, 2006 was comprised of a $154 million unrealized mark-to-market gain and $10 million in settled losses. Most of these unrealized gains reversed out in 2007. | | | • | Other revenues— decreased by $40 million, of which approximately $48 million was due to reduced activity in the trading of emission allowances following both an increase in generation and a 28% decrease in market prices. This decrease was partially offset by an $11 million increase in physical gas sales to third parties due to favorable trading opportunities in the market. |
• Capacity revenue— grew by $36 million driven by a $40 million increase from new capacity agreements with regional utilities and a $5 million increase in capacity revenue contributed by the region’s Rockford plants which dispatch into the PJM market, offset by reduced contract capacity revenue of $9 million. Cost of Energy | | | | • | Cost of energy increased by $26 million for the year ended December 31, 2007, compared to 2006, primarily due to $30 million in higher natural gas costs related to increased generation at the region’s Arthur Kill plant due to its locational advantage to New York City following transmission constraints during the last three quarters of 2007. |
Cost of energy is down by $69 million for the year ended December 31, 2009, compared to the same period in 2008, reflecting: • Purchased energy— declined by $58 million while purchased capacity rose by $3 million. The lower purchased energy was driven by lower fuel costs associated with the region’s tolled facility and lower market energy prices. The energy declines were offset by increased capacity payments of $3 million on tolled facilities. • Natural gas expense— decreased by $15 million reflecting a 30% drop in owned gas generation and a 54% decline in gas prices. The region’s gas facilities ran extensively to support transmission system stability following hurricane Gustav in September 2008. • Coal expense— decreased $11 million as coal generation was down 6%, offset by a 1% increase in cost per ton. • Transmission expense— declined by $8 million due to certain transmission line outages between electrical power regions which limited merchant energy volumes that would incur transmission costs as well as lower network interchange transmission costs associated with reduced contract customer energy volumes. These decreases were offset by: • Fuel risk management activities— losses of $21 million were recorded for the year ended December 31, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified intomark-to-market accounting. The $21 million loss included $12 million of unrealizedmark-to-market losses largely associated with forward coal positions and $9 million in losses on settled transactions, or financial cost of energy. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations. Other Operating Expenses Other operating expenses increaseddecreased by $26$2 million for the year ended December 31, 2007,2009, compared to 2006, due to:2008, associated with: | | | | • | Plant O&M spending— of $15 million due to increased plant staffing costs of $7 million, increased maintenance costs of $6 million and increased environmental remediation costs of $2 million. | | | • | Property tax— increased by approximately $3 million due to a favorable tax decision in 2006 related to NYC assets of $10 million partially offset by a tax law change the same year that resulted in a reduction of property tax receivable of $5 million in 2006 and a $2 million reduction in property taxes at the New England plants in 2007. | | | • | Regional G&A expenditures— Regional staffing and benefits increased by $3 million primarily related to the region’sRepoweringNRG development efforts while corporate allocations increased by $5 million. |
• General and administrative expense— Corporate allocations declined by $8 million in 2009 versus the same period in 2008. Franchise tax expense grew by $2 million due to credits recorded in 2008 related to prior years. • Operating and maintenance expense— Labor costs increased by $2 million because of higher benefit costs. Major maintenance rose by $2 million due to more extensive outage work performed at the Big Cajun II plant in 2009 compared to the same period in 2008.
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South Central Region
2008 compared to 2007 The following table provides selected financial information for the South Central region for the years ended December 31, 2008, and 2007: | | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2008 | | | 2007 | | | Change % | | | | (In millions except otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 478 | | | $ | 404 | | | | 18 | % | Capacity revenue | | | 233 | | | | 221 | | | | 5 | | Risk management activities | | | 10 | | | | 10 | | | | — | | Contract amortization | | | 23 | | | | 23 | | | | — | | Other revenues | | | 2 | | | | — | | | | N/A | | | | | | | | | | | | | | | Total operating revenues | | | 746 | | | | 658 | | | | 13 | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of energy | | | 468 | | | | 412 | | | | 14 | | Depreciation and amortization | | | 67 | | | | 68 | | | | (1 | ) | Other operating expenses | | | 111 | | | | 121 | | | | (8 | ) | | | | | | | | | | | | | | Operating Income | | $ | 100 | | | $ | 57 | | | | 75 | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 12,447 | | | | 12,452 | | | | — | | MWh generated (in thousands) | | | 11,148 | | | | 10,930 | | | | 2 | | Business Metrics | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 71.25 | | | $ | 59.62 | | | | 20 | | Cooling Degree Days, or CDDs(a) | | | 1,618 | | | | 1,963 | | | | (18 | ) | CDD’s 30 year rolling average | | | 1,547 | | | | 1,547 | | | | — | | Heating Degree Days, or HDDs(a) | | | 3,672 | | | | 3,236 | | | | 13 | | HDD’s 30 year rolling average | | | 3,623 | | | | 3,604 | | | | 1 | % |
| | | | | | | | | | | | | | | | | | | Year Ended
| | | | | | | | | | December 31, | | | | | | | | | | 2008 | | | 2007 | | | Change % | | | | | | | (In millions except otherwise noted) | | | | | | | | Operating Revenues | | | | | | | | | | | | | | | | | Energy revenue | | $ | 478 | | | $ | 404 | | | | 18 | % | | | | | Capacity revenue | | | 233 | | | | 221 | | | | 5 | | | | | | Risk management activities | | | 10 | | | | 10 | | | | — | | | | | | Contract amortization | | | 23 | | | | 23 | | | | — | | | | | | Other revenues | | | 2 | | | | — | | | | N/A | | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | | 746 | | | | 658 | | | | 13 | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | Cost of energy | | | 468 | | | | 412 | | | | 14 | | | | | | Depreciation and amortization | | | 67 | | | | 68 | | | | (1 | ) | | | | | Other operating expenses | | | 111 | | | | 121 | | | | (8 | ) | | | | | | | | | | | | | | | | | | | | | | Operating Income | | $ | 100 | | | $ | 57 | | | | 75 | | | | | | | | | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 12,447 | | | | 12,452 | | | | — | | | | | | MWh generated (in thousands) | | | 11,148 | | | | 10,930 | | | | 2 | | | | | | Business Metrics | | | | | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 71.25 | | | $ | 59.63 | | | | 19 | | | | | | Cooling Degree Days, or CDDs(a) | | | 1,618 | | | | 1,963 | | | | (18 | ) | | | | | CDD’s30-year rolling average | | | 1,547 | | | | 1,547 | | | | — | | | | | | Heating Degree Days, or HDDs(a) | | | 3,672 | | | | 3,236 | | | | 13 | | | | | | HDD’s30-year rolling average | | | 3,623 | | | | 3,604 | | | | 1 | % | | | | |
| | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Operating Income Operating income increased by $43 million for the year ended December 31, 2008, compared to the same period in 2007, due to: | | | | • | Operating revenues —increased by $88 million due to increases in energy revenue and capacity revenue. | | | • | Cost of energy— increased by $56 million due to higher purchased energy, coal transportation costs, natural gas and transmission costs. |
• Cost of energy— increased by $56 million due to higher purchased energy, coal transportation costs, natural gas and transmission costs. Operating Revenues Operating revenues increased by $88 million for the year ended December 31, 2008, compared to 2007, due to: | | | | • | Energy revenues— increased by $74 million due to higher merchant energy revenues. A decline in contract sales of 577 thousand MWh allowed for increased sales into the merchant market at higher prices. Merchant |
• Energy revenue— increased by $74 million due to a $41 million increase in merchant energy revenues and a $33 million increase in margin on MWh sold from market purchases. A decline in contract sales of 577 thousand MWh allowed for increased sales into the merchant market at higher prices. Revenue from contract load was flat as higher fuel cost pass-through adjustments for the region’s cooperative customers were offset by reductions in contract volume to other contract customers. • Capacity revenue— increased by $12 million. Capacity payments from the region’s cooperative customers increased by $10 million due to new peak loads set by the region’s cooperative customers and increased transmission and environmental pass-through costs. Increased RPM capacity payments from the region’s Rockford facilities in the PJM market contributed an additional
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| | | | | energy sales increased 573 thousand MWh. Revenue from contract load was flat as higher fuel cost pass-through adjustments for the region’s cooperative customers were offset by reductions in contract volume to other contract customers. |
$8 million. These increases were offset by a reduction in contract volumes to other customers of $6 million. | | | | • | Capacity revenues— increased by $12 million. Capacity payments from the region’s cooperative customers increased by $10 million due to new peak loads set by the region’s cooperative customers and increased transmission and environmental pass-through costs. Increased RPM capacity payments from the region’s Rockford facilities in the PJM market contributed an additional $8 million. These increases were offset by a reduction in contract volumes to other customers of $6 million. | | | • | Risk Management Activities— gains of $10 million were recognized during 2008 compared to $10 million in gains recognized during the same period in 2007. Unrealized gains in 2008 of $26 million were offset by realized losses of $16 million. The $26 million unrealized gain was the net effect of a $45 million unrealized mark-to-market gain from trading activities in the region offset by the reversal of $19 million loss of previously recognized mark-to-market gains on trading activity. Unrealized gains were primarily driven by decreases in power and gas prices relative to our forward positions. |
• Risk management activities— gains of $10 million were recognized during 2008 compared to $10 million in gains recognized during the same period in 2007. Unrealized gains in 2008 of $26 million were offset by realized losses of $16 million. The $26 million unrealized gain was the net effect of a $45 million unrealizedmark-to-market gain from trading activities in the region offset by the reversal of $19 million loss of previously recognizedmark-to-market gains on trading activity. Unrealized gains were primarily driven by decreases in power and gas prices relative to the Company’s forward positions. Cost of Energy Cost of energy increased by $56 million for the year ended December 31, 2008, compared to 2007, due to: | | | | • | Purchased energy— increased by $16 million reflecting a 21% increase in the average cost per MWh of purchased energy which reflects higher gas costs associated with the region’s tolling agreements. This increase was offset by an 8% decrease in purchased MWh as increased plant availability and lower contract load requirements reduced the need to purchase power. | | | • | Coal costs— increased by $16 million due to a $2 per ton increase in fuel transportation surcharges combined with a 1% increase in coal generation. These increases were offset by a $3 million decrease in allocated rail car lease fees. | | | • | Natural gas costs — increased $14 million. The region’s Bayou Cove and Big Cajun I peaker plants ran extensively to support transmission system stability after hurricane Gustav in September 2008. | | | • | Transmission costs— increased by $9 million due to additional point-to-point transmission costs driven by an increase in merchant energy sales. |
• Purchased energy— increased by $16 million reflecting a 21% increase in the average cost per MWh of purchased energy which reflects higher gas costs associated with the region’s tolling agreements. This increase was offset by an 8% decrease in purchased MWh as increased plant availability and lower contract load requirements reduced the need to purchase power. • Coal costs— increased by $16 million due to a $2 per ton increase in fuel transportation surcharges combined with a 1% increase in coal generation. These increases were offset by a $3 million decrease in allocated rail car lease fees. • Natural gas costs— increased $14 million. The region’s Bayou Cove and Big Cajun I peaker plants ran extensively to support transmission system stability after hurricane Gustav in September 2008. • Transmission costs— increased by $9 million due to additionalpoint-to-point transmission costs driven by an increase in merchant energy sales. Other Operating Expenses Other operating expenses decreased by approximately $10 million for the year ended December 31, 2008, compared to 2007, due to: | | | | • | G&A Expense— Franchise tax decreased by $5 million due to retroactive charges recorded in 2007. The Louisiana state franchise tax is assessed on the Company’s total debt and equity that significantly increased following the Acquisition of Texas Genco. This decrease was offset by $6 million in higher corporate allocations in 2008 compared to the same period in 2007. | | | • | Operating and maintenance expense— Major maintenance decreased by $9 million due to more extensive spring outage work performed at the Big Cajun II plant in 2007 compared to the same period in 2008. Normal maintenance rose $2 million as a result of increased forced outages and higher contractor costs. Asset retirements decreased by $4 million reflecting disposals associated with the 2007 outage work at Big Cajun II. |
• General and administrative expense— Franchise tax decreased by $5 million due to retroactive charges recorded in 2007. The Louisiana state franchise tax is assessed on the Company’s total debt and equity that significantly increased following the acquisition of Texas Genco. This decrease was offset by $6 million in higher corporate allocations in 2008 compared to the same period in 2007. • Operating and maintenance expense— Major maintenance decreased by $9 million due to more extensive spring outage work performed at the Big Cajun II plant in 2007 compared to the same period in 2008. Normal maintenance rose $2 million as a result of increased forced outages and higher contractor costs. Asset retirements decreased by $4 million reflecting disposals associated with the 2007 outage work at Big Cajun II.
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2007West Region
2009 compared to 20062008 The following table provides selected financial information for the South CentralWest region for the years ended December 31, 20072009, and 2006:2008: | | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2007 | | | 2006 | | | Change % | | | | (In millions except otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 404 | | | $ | 334 | | | | 21 | % | Capacity revenue | | | 221 | | | | 199 | | | | 11 | | Risk management activities | | | 10 | | | | 13 | | | | (23 | ) | Contract amortization | | | 23 | | | | 19 | | | | 21 | | Other revenues | | | — | | | | 5 | | | | (100 | ) | | | | | | | | | | | | | | Total operating revenues | | | 658 | | | | 570 | | | | 15 | | Operating Costs and Expenses | | | | | | | | | | | | | Cost of energy | | | 412 | | | | 308 | | | | 34 | | Depreciation and amortization | | | 68 | | | | 68 | | | | — | | Other operating expenses | | | 121 | | | | 89 | | | | 36 | | | | | | | | | | | | | | | Operating Income | | $ | 57 | | | $ | 105 | | | | (46 | ) | | | | | | | | | | | | | | MWh sold (in thousands) | | | 12,452 | | | | 11,845 | | | | 5 | | MWh generated (in thousands) | | | 10,930 | | | | 11,036 | | | | (1 | ) | Business Metrics | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 59.62 | | | $ | 56.18 | | | | 6 | | Cooling Degree Days, or CDDs(a) | | | 1,963 | | | | 1,797 | | | | 9 | | CDD’s 30 year rolling average | | | 1,547 | | | | 1,547 | | | | — | | Heating Degree Days, or HDDs(a) | | | 3,236 | | | | 3,169 | | | | 2 | % | HDD’s 30 year rolling average | | | 3,604 | | | | 3,604 | | | | — | |
| | | | | | | | | | | | | | | | | | | Year Ended
| | | | | | | | | | December 31, | | | | | | | | | | 2009 | | | 2008 | | | Change % | | | | | | | (In millions except otherwise noted) | | | | | | | | Operating Revenues | | | | | | | | | | | | | | | | | Energy revenue | | $ | 34 | | | $ | 39 | | | | (13 | )% | | | | | Capacity revenue | | | 122 | | | | 125 | | | | (2 | ) | | | | | Risk management activities | | | (8 | ) | | | — | | | | — | | | | | | Other revenues | | | 2 | | | | 7 | | | | (71 | ) | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | | 150 | | | | 171 | | | | (12 | ) | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | Cost of energy | | | 29 | | | | 35 | | | | (17 | ) | | | | | Depreciation and amortization | | | 8 | | | | 8 | | | | — | | | | | | Other operating expenses | | | 81 | | | | 70 | | | | 16 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | $ | 32 | | | $ | 58 | | | | (45 | ) | | | | | | | | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 1,279 | | | | 1,532 | | | | (17 | ) | | | | | MWh generated (in thousands) | | | 1,279 | | | | 1,532 | | | | (17 | ) | | | | | Business Metrics | | | | | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 40.10 | | | $ | 82.20 | | | | (51 | ) | | | | | Cooling Degree Days, or CDDs(a) | | | 908 | | | | 953 | | | | (5 | ) | | | | | CDD’s30-year rolling average | | | 704 | | | | 704 | | | | — | | | | | | Heating Degree Days, or HDDs(a) | | | 3,105 | | | | 3,190 | | | | (3 | )% | | | | | HDD’s30-year rolling average | | | 3,228 | | | | 3,243 | | | | — | | | | | |
| | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Operating Income Operating income for the region declineddecreased by $48$26 million for the year ended December 31, 2007,2009, compared to 2006,the same period in 2008, due to higher operating expenses, despite a 1% decreasedecreases in generation at the region’s Big Cajun II plant.capacity revenue, energy revenue, risk management activities and other revenues. Operating Revenues Operating revenues increaseddecreased by $88$21 million for the year ended December 31, 2007,2009, compared to 2006,the same period in 2008, due to: | | | | • | Energy revenues— increased by approximately $70 million due to a new contract which contributed $69 million in contract energy revenues, increasing contract sales volume by approximately 1.3 million MWh. A contractual change in the fuel adjustment charge for the region’s cooperative customers increased energy revenues by an additional $11 million. This was offset by a $12 million decrease in merchant energy revenue as a result of satisfying increasing load requirement from the new contract. |
• Capacity revenue— decreased by $3 million due to the expiration of a two-year tolling agreement at the El Segundo facility in April 2008, which was replaced by resource adequacy and capacity contracts at lower prices. • Energy revenue — decreased by $5 million primarily due to a 16% decrease in merchant prices in 2009 compared to 2008. This decrease was offset by a 5% increase in merchant generation in 2009 compared to 2008. • Other revenues— decreased by $5 million due to lower emission allowance sales partially offset by an increase in ancillary services revenue.
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| | | | • | Capacity revenues— increased by approximately $22 million, of which $15 million was due to higher rates as a result of the region setting new summer peaks in 2006 and 2007; the new system peak of 2,123 MW set in August 2007 will continue to impact capacity revenue in the first half of 2008. Higher network transmission costs, which are passed through to the region’s cooperative customers, also increased capacity revenues by $6 million. Improved market conditions in PJM resulted in an increase of $3 million in merchant capacity revenue from the Rockford plants. |
• Risk management activities— realized losses of $8 million on settled transactions were recognized during the period. There was no risk management activity in 2008. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations. Cost of Energy and Other Operating Expenses Cost of energy and other operating expenses increased by $104$5 million for the year ended December 31, 2007,2009, compared to 2006,the same period in 2008, due to: | | | | • | Purchased energy— increased by approximately $69 million as planned and maintenance outage hours at the region’s Big Cajun II facility increased by 1,209 hours, primarily due to the planned turbine/generator outage at the Big Cajun II Unit 3 facility in the fourth quarter 2007. These increases were offset by a drop of $2.53/MWh in realized purchased power prices. | | | • | Coal costs— increased by approximately $17 million, of which approximately $11 million was due to a 9% increase in coal prices and $7 million due to higher coal transportation costs. | | | • | Transmission costs— increased by approximately $16 million. Network transmission costs, which are passed-through to the region’s cooperative customers, increased by $6 million due to load growth and increased utilization of the Entergy transmission system. Point-to-point transmission costs to support off-system sales increased by $10 million. |
• Other Operating ExpensesCost of energy— decreased by $6 million due to a 29% decline in average natural gas prices per MMBtu. This decrease was partially offset by an 8% increase in natural gas consumption and a $3 million increase in fuel oil expense resulting from a write-down to market of fuel oil inventory no longer used in the production of energy. • Other operating expenses— increased by approximately $32$11 million for the year ended December 31, 2007, compareddue to 2006, due to: | | | | • | Maintenance expense— increased by approximately $19 million as the scope of work on planned outages were more extensive in 2007. The Big Cajun II Unit 3 facility incurred a major planned outage in the fourth quarter 2007, during which the generator was rewound, turbine controls were replaced with a modern digital control system, and the turbine steam path was replaced with a high-efficiency design. Asset disposals in conjunction with the outage added $4 million. | | | • | Franchise tax— Louisiana state franchise tax increased by approximately $6 million due to an increased assessment based on the Company’s total debt and equity. The Company’s total debt and equity increased significantly following the acquisition of Texas Genco. |
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West Regionhigher maintenance expense associated with a major overhaul at El Segundo and higher maintenance at Long Beach.
2008 compared to 2007 The following table provides selected financial information for the West region for the years ended December 31, 2008, and 2007: | | | | | | | | | | | | | | | | Year Ended
| | | | | | | | | | | | | | | | | | December 31, | | | | | Year Ended
| | | | | | 2008 | | 2007 | | Change % | | | December 31, | | | | | | (In millions except otherwise noted) | | | | | 2008 | | 2007 | | Change% | | | | (In millions except otherwise noted) | | | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | | | | | Energy revenue | | $ | 39 | | | $ | 4 | | | | N/A | | | $ | 39 | | | $ | 4 | | | | N/A | | Capacity revenue | | | 125 | | | | 122 | | | | 2 | % | | | 125 | | | | 122 | | | | 2 | % | Risk management activities | | | — | | | | — | | | | N/A | | | | — | | | | — | | | | N/A | | Other revenues | | | 7 | | | | 1 | | | | N/A | | | | 7 | | | | 1 | | | | N/A | | | | | | | | | | | | | Total operating revenues | | | 171 | | | | 127 | | | | 35 | | | | 171 | | | | 127 | | | | 35 | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Cost of energy | | | 35 | | | | 5 | | | | N/A | | | | 35 | | | | 5 | | | | N/A | | Depreciation and amortization | | | 8 | | | | 3 | | | | 167 | | | | 8 | | | | 3 | | | | 167 | | Other operating expenses | | | 70 | | | | 80 | | | | (13 | ) | | | 70 | | | | 80 | | | | (13 | ) | | | | | | | | | | | | Operating Income | | $ | 58 | | | $ | 39 | | | | 49 | | | $ | 58 | | | $ | 39 | | | | 49 | | | | | | | | | | | | | MWh sold (in thousands) | | | 1,532 | | | | 1,246 | | | | 23 | | | | 1,532 | | | | 1,246 | | | | 23 | | MWh generated (in thousands) | | | 1,532 | | | | 1,246 | | | | 23 | | | | 1,532 | | | | 1,246 | | | | 23 | | Business Metrics | | | | | | | | | | | | | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 82.62 | | | $ | 66.52 | | | | 24 | | | $ | 82.20 | | | $ | 66.46 | | | | 24 | | Cooling Degree Days, or CDDs(a) | | | 953 | | | | 785 | | | | 21 | | | | 953 | | | | 785 | | | | 21 | | CDD’s 30 year rolling average | | | 704 | | | | 704 | | | | — | | | CDD’s30-year rolling average | | | | 704 | | | | 704 | | | | — | | Heating Degree Days, or HDDs(a) | | | 3,190 | | | | 3,048 | | | | 5 | % | | | 3,190 | | | | 3,048 | | | | 5 | % | HDD’s 30 year rolling average | | | 3,243 | | | | 3,228 | | | | — | | | HDD’s30-year rolling average | | | | 3,243 | | | | 3,228 | | | | — | |
| | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Operating income increased by $19 million for the year ended December 31, 2008, compared to the same period in 2007, due to:
| | | | • | Energy revenues— increased by $35 million due to the 2008 dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. | | | • | Other operating expense— decreased by $10 million as a result of a $5 million reduction inRepoweringNRG expenses due to the capitalization of cost for the El Segundo Energy Center project in 2008. In addition there was a $3 million reduction in lease expenses in 2008 and the recognition of a $2 million environmental liability for the El Segundo plant in 2007. | | | • | Other revenues— increased by $6 million due to higher allocations for trading of emission allowances in 2008. |
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| | | | • | Capacity revenues— increased by $3 million primarily due to the tolling agreement at the Long Beach plant partially offset by the expiration of a two year tolling agreement at the El Segundo facility: |
| | | | o | Long Beach— On August 1, 2007, NRG successfully completed the repowering of a 260 MW natural gas-fueled generating plant at its Long Beach generating facility. The plant contributed $15 million in incremental capacity revenues for the year ended December 31, 2008. | | | o | El Segundo— The expiration of the two year tolling agreement at the end of April resulted in a decrease of $11 million in capacity revenues for the year ended December 31, 2008. |
These increases were partially offset by:
| | | | • | Cost of energy —increased by $30 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. | | | • | Depreciation and amortization— increased by $5 million, reflecting depreciation associated with the repowered plant at the Long Beach generating facility. |
2007 compared to 2006
The following table provides selected financial information for the West region for the years ended December 31, 2007, and 2006:
| | | | | | | | | | | | | | | Year Ended
| | | | | | | December 31, | | | | | | | 2007 | | | 2006 | | | Change % | | | | (In millions except otherwise noted) | | | | | | Operating Revenues | | | | | | | | | | | | | Energy revenue | | $ | 4 | | | $ | 75 | | | | (95 | )% | Capacity revenue | | | 122 | | | | 68 | | | | 79 | | Risk management activities | | | — | | | | (3 | ) | | | 100 | | Other revenues | | | 1 | | | | 6 | | | | (83 | ) | | | | | | | | | | | | | | Total operating revenues | | | 127 | | | | 146 | | | | (13 | ) | Operating Costs and Expenses | | | | | | | | | | | | | Cost of energy | | | 5 | | | | 80 | | | | (94 | ) | Depreciation and amortization | | | 3 | | | | 3 | | | | — | | Other operating expenses | | | 80 | | | | 55 | | | | 45 | | | | | | | | | | | | | | | Operating Income | | $ | 39 | | | $ | 8 | | | | 388 | | | | | | | | | | | | | | | MWh sold (in thousands) | | | 1,246 | | | | 1,901 | | | | (34 | ) | MWh generated (in thousands) | | | 1,246 | | | | 1,901 | | | | (34 | ) | Business Metrics | | | | | | | | | | | | | Average on-peak market power prices ($/MWh) | | $ | 66.52 | | | $ | 61.54 | | | | 8 | | Cooling Degree Days, or CDDs(a) | | | 785 | | | | 926 | | | | (15 | ) | CDD’s 30 year rolling average | | | 704 | | | | 704 | | | | — | | Heating Degree Days, or HDDs(a) | | | 3,048 | | | | 3,001 | | | | 2 | % | HDD’s 30 year rolling average | | | 3,228 | | | | 3,228 | | | | — | |
| | | (a) | | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
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Operating Income Operating income increased by $31$19 million for the year ended December 31, 2007,2008, compared to 2006. Excluding the consolidation of WCP’s results following the acquisition of Dynegy’s 50% interest on March 31, 2006, operating incomesame period in 2007, due to: Operating Revenues Operating revenues increased by $24$44 million for the year ended December 31, 2008, compared to the same period in 2007, due to: • Energy revenue— increased by $35 million due to:to the 2008 dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. • Other revenues— increased by $6 million due to higher allocations for trading of emission allowances in 2008. • Capacity revenue— increased by $3 million primarily due to the tolling agreement at the Long Beach plant partially offset by the expiration of a two year tolling agreement at the El Segundo facility: | | | | •¡ | Capacity revenues Long Beach—increased by approximately $28 million, excluding On August 1, 2007, NRG successfully completed the first quarter 2007, due to new tolling agreementsrepowering of a 260 MW natural gas-fueled generating plant at the region’s Encina andits Long Beach plants:generating facility. The plant contributed $15 million in incremental capacity revenues for the year ended December 31, 2008. |
| | | | o¡ | EncinaEl Segundo— In January 2007, NRG signed a newThe expiration of the two year tolling agreement forat the region’s Encina plant which contributed $15end of April resulted in a decrease of $11 million in capacity revenues for the year ended December 31, 2007. | | | o | Long Beach— The repowered plant at the Long Beach generating facility contributed approximately $13 million in capacity revenues for the year ended December 31, 2007. |
| | | | • | Cost of energy —decreased by $76 million, excluding the first quarter 2007, due to the new tolling agreement entered into at the Encina plant in 2007, which required the counterparty to supply its own fuel. Under the previous arrangement in 2006, the plant supplied the fuel.2008. |
This increase was offset by:Cost of Energy and Other Operating Expenses
| | | | • | Energy revenues— decreased by approximately $72 million, excluding the first quarter 2007, primarily due to the tolling agreement at the Encina plant that has resulted in the receipt of a fixed monthly capacity payment in return for the right to schedule and dispatch from the plant. The Encina tolling agreement replaced the RMR agreement under which the plant was called upon to generate revenues for such dispatch. | | | • | O&M expense— increased by approximately $6 million, excluding the first quarter 2007, primarily due to increases in labor costs, major maintenance and auxiliary power. | | | • | Development expenses— increased by $4 million, reflectingRepoweringNRG initiatives at the region’s El Segundo and Encina sites. | | | • | Other revenues— decreased ancillary service revenue of $3 million at the Encina plant due to the new tolling agreement that consigns ancillary service revenue to the counterparty in exchange for a fixed monthly capacity payment. |
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Cost of energy and other operating expenses increased by $25 million for the year ended December 31, 2008, compared to the same period in 2007, due to:
• Cost of energy —increased by $30 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. • Depreciation and amortization— increased by $5 million, reflecting depreciation associated with the repowered plant at the Long Beach generating facility. • Other operating expenses— decreased by $10 million as a result of a $5 million reduction inRepoweringNRG expenses due to the capitalization of cost for the El Segundo Energy Center project in 2008. In addition there was a $3 million reduction in lease expenses in 2008 and the recognition of a $2 million environmental liability for the El Segundo plant in 2007. Liquidity and Capital Resources Liquidity Position As of December 31, 20082009, and 2007,2008, NRG’s liquidity, excluding collateral received, was approximately $3.4$3.8 billion and $2.7$3.4 billion, respectively, comprised of the following: | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | | | | 2008 | | 2007 | | | 2009 | | 2008 | | | | (In millions) | | | (In millions) | | | Cash and cash equivalents | | $ | 1,494 | | | $ | 1,132 | | | $ | 2,304 | | | $ | 1,494 | | Funds deposited by counterparties | | | 754 | | | | — | | | | 177 | | | | 754 | | Restricted cash | | | 16 | | | | 29 | | | | 2 | | | | 16 | | | | | | | | | | | | | Total cash | | | 2,264 | | | | 1,161 | | | | 2,483 | | | | 2,264 | | Synthetic Letter of Credit Facility availability | | | 860 | | | | 557 | | | | 583 | | | | 860 | | Revolver Credit Facility availability | | | 1,000 | | | | 997 | | | Revolving Credit Facility availability | | | | 905 | | | | 1,000 | | | | | | | | | | | | | Total liquidity | | | 4,124 | | | | 2,715 | | | | 3,971 | | | | 4,124 | | Less: Funds deposited as collateral by hedge counterparties | | | (760 | ) | | | — | | | | (177 | ) | | | (760 | ) | | | | | | | | | | | | Total liquidity, excluding collateral received | | $ | 3,364 | | | $ | 2,715 | | | $ | 3,794 | | | $ | 3,364 | | | | | | | | | | | | |
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For the year ended December 31, 2008,2009, total liquidity, excluding collateral received, increased by $1.4 billion$430 million due to a rise in funds deposited of $754 million as well as higher cash balancesbalance of $362 million.$810 million, partially offset by decreased availability of the Synthetic Letter of Credit Facility and the Revolving Credit Facility of $277 million and $95 million, respectively. Changes in cash balances are further discussed hereinafter underCash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at December 31, 20082009, are predominantly held in money market funds invested in treasury securities, or treasury repurchase agreements.agreements or government agency debt. The line item “Funds deposited by counterparties” consistrepresents the amounts that are held by NRG as a result of cash collateral receivedposting obligations from hedgethe Company’s counterparties due to positions in support of energy risk management activities, and it isthe Company’s hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company’s intention, asare not available for the payment of December 31, 2008 to limit the use of these funds. The increase in these amounts is due to the in-the-money position of our transactions following the drop in commodity prices since the summer of 2008.NRG’s general corporate obligations. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. TheSince collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company’s balance sheet, reflects awith an offsetting liability for this cash collateral received within current liabilities. The decrease in these amounts from December 31, 2008, was due to cash collateral moved from NRG to Merrill Lynch in connection with novations under the CSRA (see Item 14 — Note 3,Business Acquisitions, to the Consolidated Financial Statements), offset by a increase ofin-the-money positions as a result of decreasing forward prices. Management believes that the Company’s liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG’s preferred shareholders, and other liquidity commitments. Management continues to regularly monitor the Company’s ability to finance the needs of its operating, financing and investing activity in a manner consistent with its intention to maintain a net debt to capital ratio in the range of45-60%. Credit Ratings Credit rating agencies rate a firm’s public debt securities. These ratings are utilized by the debt markets in evaluating a firm’s credit risk. Ratings influence the price paid to issue new debt securities by indicating to the market the Company’s ability to pay principal, interest and preferred dividends. Rating agencies evaluate a firm’s industry, cash flow, leverage, liquidity, and hedge profile, among other factors, in their credit analysis of a firm’s credit risk. As of December 31, 2008, NRG’s credit ratings are on positive watch from both S&P and Moody’s rating agencies.
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The following table summarizes the credit ratings for NRG Energy, Inc., its Term Loan Facility and its senior notesSenior Notes as of December 31, 2008:2009: | | | | | | | | | | | | | | | S&P | | | Moody’s | | | Fitch | | | NRG Energy, Inc. | | | B+ | | BB− | | Ba3 | | B | 8.5% Senior Notes due 2019 | | BBB− | | B1 | | B+ | 7.375% Senior Notes, due 2016, 2017 | | | B | | BB− | | B1 | | | | B+ | | 7.25% Senior Notes due 2014 | | | B | | BB− | | B1 | | | | B+ | | Term Loan Facility | | | BBBB+ | | | | Ba1 | | Baa3 | | BB | |
SOURCES OF FUNDS The principal sources of liquidity for NRG’s future operating and capital expenditures are expected to be derived from new and existing financing arrangements, asset sales, existing cash on hand and cash flows from operations. Financing Arrangements Senior Credit Facility As of December 31, 2008,2009, NRG has a Senior Credit Facility which is comprised of a senior first priority secured term loan, or the Term Loan Facility, a $1.0 billion senior first priority secured revolving credit facility, or the Revolving Credit Facility, and a $1.3 billion senior first priority secured synthetic letter of credit facility, or the 113
Synthetic Letter of Credit Facility. The Senior Credit Facility was last amended on June 8, 2007. As of December 31, 2008,2009, NRG had issued $440$717 million of letters of credit under the Synthetic Letter of Credit Facility, leaving $860$583 million available for future issuances. Under the Revolving Credit Facility as of December 31, 2008,2009, NRG had not issued any letters of credit.credit of $95 million, of which $59 million supports the tax exempt bonds issued by Dunkirk Power LLC as described in Item 14 — Note 12,Debt and Capital Leases,to the Consolidated Financial Statements. 2019 Senior Notes On June 5, 2009, NRG completed the issuance of $700 million aggregate principal amount of 8.5% Senior Notes due 2019, or 2019 Senior Notes, as described in Item 14 — Note 12,Debt and Capital Leases,to the Consolidated Financial Statements. The Company used a portion of the net proceeds of $678 million to facilitate the early termination on October 5, 2009 of NRG’s obligations pursuant to the CSRA Amendment. Net proceeds in excess of this amount are available for general corporate purposes. See further discussion of the CSRA Amendment in Item 14 — Note 3,Business Acquisitions,to the Consolidated Financial Statements. Merrill Lynch Credit Sleeve Facility See discussion in Item 14 — Note 3,Business Acquisitions,to the Consolidated Financial Statements, regarding the CSRA entered into to support the retail business as a result of the acquisition of Reliant Energy on May 1, 2009. Effective October 5, 2009, the Company executed the CSRA Amendment. In connection with this amendment, the Company posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued $206 million of letters of credit, and received $45 million of counterparty collateral. In addition, Merrill Lynch returned $250 million of previously posted cash collateral, and released liens on $322 million of unrestricted cash held by Reliant Energy. Upon execution of the CSRA Amendment, the Company was required to post collateral for any net liability derivatives, and other static margin associated with supply for Reliant Energy. TANE Facility On February 24, 2009, NINA executed an EPC agreement with TANE, which specifies the terms under which STP Units 3 and 4 will be constructed. Concurrent with the execution of the EPC agreement, NINA and TANE entered into the TANE Facility wherein TANE has committed up to $500 million to finance purchases of long-lead materials and equipment for the construction of STP Units 3 and 4. The TANE Facility matures on February 24, 2012, subject to two renewal periods, and provides for customary events of default, which include, among others: nonpayment of principal or interest; default under other indebtedness; the rendering of judgments; and certain events of bankruptcy or insolvency. Outstanding borrowings will accrue interest at LIBOR plus 3%, subject to a ratings grid, and are secured by substantially all of the assets of and membership interests in NINA and its subsidiaries. As of December 31, 2009, no amounts had been borrowed under the TANE Facility. Dunkirk Power LLC Tax-Exempt Bonds On April 15, 2009, NRG executed a $59 million tax-exempt bond financing through its wholly-owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial Development Agency and will be used for construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially bear weekly interest based on the Securities Industry and Financial Markets Association, or SIFMA, rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit under the Company’s Revolving Credit Facility covering amounts drawn on the facility. The proceeds received through December 31, 2009, were $52 million with the remaining balance being released over time as construction costs are paid. On February 1, 2010, the Company fixed the rate on the bonds at 5.875%. Interest will be payable semiannually. In addition, the $59 million letter of credit issued by NRG in support of the bonds was cancelled and replaced with a parent guarantee. These bonds are part of the Company’s first lien debt. 114
GenConn Energy LLC related financings In April 2009, NRG Connecticut Peaking LLC., a wholly-owned subsidiary of NRG, executed an equity bridge loan facility, or EBL, in the amount of $121.5 million from a syndicate of banks. The purpose of the EBL is to fund the Company’s proportionate share of the project construction costs required to be contributed into GenConn Energy LLC, or GenConn, a 50% equity method investment of the Company. The EBL, which is fully collateralized with a letter of credit issued under the Company’s Synthetic Letter of Credit Facility covering amounts drawn on the facility, will bear interest at a rate of LIBOR plus 2% on drawn amounts. The EBL will mature on the earlier of the commercial operations date of the Middletown project or July 26, 2011. The EBL also requires mandatory prepayment of the portion of the loan utilized to pay costs of the Devon project, of approximately $54 million, on the earlier of Devon’s commercial operations date or January 27, 2011. The proceeds of the EBL received through December 31, 2009, were $108 million and the remaining amounts will be drawn as necessary to fund construction costs. In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a7-year term loan facility, and also entered into a5-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving facility. In August 2009, GenConn began to draw under the GenConn Facility to cover costs related to the Devon project and as of December 31, 2009, has drawn $48 million. First and Second Lien Structure NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets. NRG uses the first or second lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations underout-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty arein-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-the moneyout-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first and second lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date. The Company’sNRG’s lien counterparties may have a claim on ourthe Company’s assets to the extent market prices exceed the hedged price. As of December 31, 20082009 and February 2, 2009, the first lien exposure of net out-of-the-money positions to counterparties on hedges was $88 million and $43 million, respectively. As of December 31, 2008 and February 2, 2009, there was no exposure to out-of-the-money positions to counterparties on9, 2010, all hedges under the first and second lien.lien werein-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MWs hedged against the Company’s baseload assets and as a percentage relative to the Company’s forecasted baseload capacity under the first and second lien structure as of February 2, 2009:9, 2010: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equivalent Net Sales Secured by First and Second Lien Structure(a) | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | 2010 | | 2011 | | 2012 | | 2013 | | In MW(b) | | | 4,967 | | | | 4,600 | | | | 3,788 | | | | 2,196 | | | | 828 | | | | 3,358 | | | | 2,931 | | | | 1,520 | | | | 732 | | As a percentage of total forecasted baseload capacity(c) | | | 71 | % | | | 67 | % | | | 56 | % | | | 33 | % | | | 12 | % | | | 49 | % | | | 43 | % | | | 22 | % | | | 11 | % |
| | | (a) | | Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region. | | (b) | | 20092010 MW value consists of March through December positions only. | | (c) | | Forecasted baseload capacity under the first and second lien structure represents 80% of the total Company’s baseload assets. |
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Common Stock Finance I Debt
The Company’s Senior Credit Facility and Senior Notes indentures contain restricted payment provisions limiting the use of funds for transactions such as common share repurchases. To maintain restricted payment capacity under the Senior Notes indentures, in March 2008 the Company executed an arrangement with CS to extend maturities of CSF I’s notes and preferred interests from October 2008 to June 2010. In addition, the settlement date of an embedded derivative, or CSF I CAGR, which is based on NRG’s share price appreciation above a threshold price, was extended 30 days to early December 2008. As part of this extension arrangement, the Company contributed 795,503 treasury shares to CSF I as additional collateral to maintain a blended interest rate in the CSF I facility of approximately 7.5%. Accordingly, the amount due at maturity in June 2010 for the CSF I notes and preferred interests will be $248 million. In August 2008, the Company amended the CSF I notes and preferred interests to early settle the CSF I CAGR. Accordingly, NRG made a cash payment of $45 million to CS for the benefit of CSF I, which was recorded to interest expense in the Company’s Consolidated Statement of Operations.
Asset Sales MIBRAG — On June 10, 2009, NRG completed the sale of its 50% ownership interest in Mibrag B.V. to a consortium of Severoćeské doly Chomutov, a member of the CEZ Group, and J&T Group. Mibrag B.V.’s principal 115
holding was MIBRAG, which was jointly owned by NRG and URS Corporation. As part of the transaction, URS Corporation also entered into an agreement to sell its 50% stake in MIBRAG. For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40 U.S.$/EUR), net of transaction costs. During the year ended December 31, 2009, NRG recognized a pre-tax gain of $128 million. Prior to completion of the sale, NRG continued to record its share of MIBRAG’s operations to “Equity in earnings of unconsolidated affiliates.” In connection with the transaction, NRG entered into a foreign currency forward contract to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in exchange for $255 million on June 15, 2009. For the year ended December 31, 2009, NRG recorded an exchange loss of $24 million on the contract within “Other income/(loss), net.” ITISA — On April 28, 2008, NRG completed the sale of its 100% interest in Tosli Acquisition B.V., or Tosli, which held all NRG’s interest in ITISA, to Brookfield Renewable Power Inc. (previously Brookfield Power Inc.), a wholly-owned subsidiary of Brookfield Asset Management Inc. In addition, the purchase price adjustment contingency under the sale agreement was resolved on August 7, 2008. In connection with the sale, NRG received $300 million of cash proceeds from Brookfield, and removed $163 million of assets, including $59 million of cash, $122 million of liabilities, including $63 million of debt, and $15 million in foreign currency translation adjustment from its 2008 consolidated balance sheet. As discussed in Item 14 — Note 3,4,Discontinued Operations Business Acquisitions and Dispositions, to the Consolidated Financial Statements, the activities of Tosli and ITISA have been classified as discontinued operations. USES OF FUNDS The Company’s requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures includingRepoweringNRG and environmental; and (iv) corporate financial transactions including return of capital to shareholders. Commercial Operations NRG’s commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of December 31, 2008,2009, commercial operations had total cash collateral outstanding of $492$359 million, and $283$508 million outstanding in letters of credit to third parties primarily to support its economic hedging activities.activities for both wholesale and retail transactions. As of December 31, 2008,2009, total collateral held from counterparties was $788$177 million, including $6 million of restricted cash, and $28$24 million of letters of credit. Upon execution of the CSRA Amendment, effective October 5, 2009, the Company was required to post collateral for any net liability derivatives, and other static margin associated with supply for Reliant Energy that was transferred to NRG. As of January 29, 2010, all wholesale energy supply contracts relating to retail supply hedging were transferred to the Company, so that Merrill Lynch was no longer providing any credit support for wholesale energy supply contracts relating to retail supply hedging. Future liquidity requirements may change based on the Company’s hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG’s credit ratings and general perception of its creditworthiness. Debt Service Obligations NRG must annually offer a portion of its excess cash flow (as defined in the Senior Credit Facility) to its first lien lenders under the Term Loan Facility. The percentage of excess cash flow offered to these lenders is dependent 116
upon the Company’s consolidated leverage ratio (as defined in the Senior Credit Facility) at the end of the preceding year. OfThe 2010 mandatory offer related to 2009 is expected to be $430 million, against which the amount offered, the first lien lenders must accept 50% while the remaining 50% may either be accepted or rejected at the lenders’ option.Company made a prepayment of $200 million in December 2009. Based on current credit market conditions, the Company expects that its lenders will accept in full the 2010 mandatory offer required for 2008,related to 2009, and, as such, the Company has reclassified approximately
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$197 $230 million of Term Loan Facility maturity from a non-current to a current liability as of December 31, 2008. The mandatory annual offer required2009.
On October 9, 2009, NRG commenced the process of unwinding the CSF II Debt, making a $181 million capital contribution to a CSF II cash account, effectively restricting the cash for 2007 was $446 million, againstthe benefit of Credit Suisse Group, or CS. On October 13, 2009, CS began the process of unwinding their hedges in connection with the CSF II structure, which they completed by November 24, 2009. Once complete, CS returned 5,400,000 shares of NRG common stock borrowed under the Share Lending Agreements, and released 9,528,930 common shares held as collateral for the CSF II Debt, and the Company maderemitted payment to CS of the $181 million for outstanding principal and interest. The CSF II Debt contained an embedded derivative feature, or CFS II CAGR, which required NRG to pay CS at maturity, either in cash or stock at NRG’s option, the excess of NRG’s then current stock price over a $300 million prepayment in December 2007. With this prepayment,Threshold Price of $40.80 per share. On November 24, 2009, the Company met a financial ratio by the end of 2007 that resulted in a 0.25% reduction in the interest rate on both its Term Loan Facility and Synthetic Letter of Credit Facility which resulted in approximately $8 million in pre-tax interest savings during 2008. Of the remaining $146 million, the lenders accepted a repayment of $143 million in March 2008. The amount retained by the Company was used for investments, capital expenditures and other items as defined by the Senior Credit Facility.CSF II CAGR expired with no payment due. AsPrincipal payments on debt and capital leases as of December 31, 2008,2009, are due in the following periods:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Subsidiary/Description | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | Thereafter | | | Total | | | | (In millions) | | | Debt: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8.5% Notes due 2019 | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 700 | | | $ | 700 | | 7.375% Notes due 2017 | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1,100 | | | | 1,100 | | 7.375% Notes due 2016 | | | — | | | | — | | | | — | | | | — | | | | | | | | 2,400 | | | | 2,400 | | 7.25% Notes due 2014 | | | — | | | | — | | | | — | | | | — | | | | 1,200 | | | | — | | | | 1,200 | | Term Loan Facility, due 2013 | | | 261 | | | | 32 | | | | 32 | | | | 1,888 | | | | — | | | | — | | | | 2,213 | | CSF I notes and preferred interests, due June 2010 | | | 190 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 190 | | NRG Energy Center Minneapolis LLC, due 2013 and 2017 | | | 11 | | | | 12 | | | | 13 | | | | 10 | | | | 6 | | | | 21 | | | | 73 | | Dunkirk Power LLC tax-exempt bonds, due April 2042 | | | — | | | | — | | | | — | | | | — | | | | — | | | | 52 | | | | 52 | | NRG Connecticut Peaking LLC, equity bridge loan facility | | | 54 | | | | 54 | | | | — | | | | — | | | | — | | | | — | | | | 108 | | Nuclear Innovation North America LLC, due 2010 | | | 20 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 20 | | NRG Repowering Holdings LLC, due 2011 | | | — | | | | 19 | | | | — | | | | — | | | | — | | | | — | | | | 19 | | NRG Peaker Finance Co. LLC, due June 2019 | | | 20 | | | | 21 | | | | 22 | | | | 23 | | | | 29 | | | | 136 | | | | 251 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Subtotal Debt, Bonds and Notes | | | 556 | | | | 138 | | | | 67 | | | | 1,921 | | | | 1,235 | | | | 4,409 | | | | 8,326 | | Capital Lease: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Saale Energie GmbH, Schkopau | | | 22 | | | | 10 | | | | 8 | | | | 8 | | | | 7 | | | | 68 | | | | 123 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Payments and Capital Leases | | $ | 578 | | | $ | 148 | | | $ | 75 | | | $ | 1,929 | | | $ | 1,242 | | | $ | 4,477 | | | $ | 8,449 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
In addition to the debt and capital leases shown in the preceding table, NRG had approximately $4.7 billion in aggregate principal amount of unsecured high yield notes or Senior Notes, had approximately $2.6 billion in principal amount outstanding under the Term Loan Facility, and had issued $440$717 million of letters of credit under the Company’s $1.3 billion Synthetic Letter of Credit Facility.Facility and $95 million of letters of credit under the Company’s Revolving Credit Facility as of December 31, 2009. The Company’s Revolving Credit Facility matures on February 2, 2011, and the Synthetic Letter of Credit Facility matures on February 1, 2013. Principal payments on debt and capital leases as of December 31, 2008 are due in the following periods:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Subsidiary/Description | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | Thereafter | | | Total | | | | (In millions) | | | Debt: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 7.375% Notes due 2017 | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,100 | | | $ | 1,100 | | 7.25% Notes due 2014 | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1,200 | | | | 1,200 | | 7.375% Notes due 2016 | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2,400 | | | | 2,400 | | Term Loan Facility, due 2013 | | | 228 | | | | 32 | | | | 31 | | | | 32 | | | | 2,319 | | | | — | | | | 2,642 | | CSF notes and preferred interests, due 2009 and 2010 | | | 143 | | | | 190 | | | | — | | | | — | | | | — | | | | — | | | | 333 | | NRG Energy Center Minneapolis LLC, due 2013 and 2017 | | | 11 | | | | 11 | | | | 12 | | | | 13 | | | | 10 | | | | 27 | | | | 84 | | Nuclear Innovation North America LLC, due 2011 | | | — | | | | — | | | | 10 | | | | — | | | | — | | | | — | | | | 10 | | NRG Repowering Holdings LLC, due 2011 | | | — | | | | — | | | | 10 | | | | — | | | | — | | | | — | | | | 10 | | NRG Peaker Finance Co. LLC, due June 2019 | | | 15 | | | | 20 | | | | 21 | | | | 22 | | | | 23 | | | | 165 | | | | 266 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Subtotal Debt, Bonds and Notes | | | 397 | | | | 253 | | | | 84 | | | | 67 | | | | 2,352 | | | | 4,892 | | | | 8,045 | | Capital Lease: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Saale Energie GmbH, Schkopau | | | 72 | | | | 12 | | | | 6 | | | | 4 | | | | 4 | | | | 44 | | | | 142 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Payments and Capital Leases | | $ | 469 | | | $ | 265 | | | $ | 90 | | | $ | 71 | | | $ | 2,356 | | | $ | 4,936 | | | $ | 8,187 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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Capital Expenditures For the year ended December 31, 2008,2009, the Company’s capital expenditures, including accruals, were approximately $1.0 billion, of which $645 million was related toRepoweringNRG projects.$783 million. The following table summarizes the Company’s capital expenditures for the year ended December 31, 20082009 and the estimated capital expenditure and repowering investments forecast for 2009.2010. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maintenance | | Environmental | | Repowering | | Total | | | Maintenance | | Environmental | | Repowering | | Total | | | | (In millions) | | | (In millions) | | | Northeast | | $ | 32 | | | $ | 157 | | | $ | 19 | | | $ | 208 | | | $ | 30 | | | $ | 172 | | | $ | 5 | | | $ | 207 | | Texas | | | 115 | | | | 26 | | | | 97 | | | | 238 | | | | 160 | | | | — | | | | 29 | | | | 189 | | South Central | | | 9 | | | | 5 | | | | — | | | | 14 | | | | 9 | | | | — | | | | — | | | | 9 | | West | | | 5 | | | | — | | | | 30 | | | | 35 | | | | 4 | | | | — | | | | 4 | | | | 8 | | Reliant Energy | | | | 7 | | | | — | | | | — | | | | 7 | | Wind | | | — | | | | — | | | | 398 | | | | 398 | | | | — | | | | — | | | | 120 | | | | 120 | | NINA | | | — | | | | — | | | | 101 | | | | 101 | | | Nuclear Development | | | | — | | | | — | | | | 197 | | | | 197 | | Other | | | 21 | | | | — | | | | — | | | | 21 | | | | 46 | | | | — | | | | — | | | | 46 | | | | | | | | | | | | | | | | | | | | | Total | | $ | 182 | | | $ | 188 | | | $ | 645 | | | $ | 1,015 | | | $ | 256 | | | $ | 172 | | | $ | 355 | | | $ | 783 | | | | | | | | | | | | | | | | | | | | | Estimated capital expenditures for 2009 | | $ | 255 | | | $ | 256 | | | $ | 256 | | | $ | 767 | | | Estimated capital expenditures for 2010 | | | $ | 241 | | | $ | 233 | | | $ | 707 | | | $ | 1,181 | | | | | | | | | | | | | | | | | | | | |
RepoweringNRGcapital expenditures and investments —RepoweringNRG project capital expenditures consisted of approximately $218 million for wind turbines and construction related costs for the Elbow Creek wind farm project which became commercially operational in December 2008 and $180 million in turbine purchases for other wind projects currently under development. In addition, the Company’sRepoweringNRG capital expenditures included $97 million related to the construction of Cedar Bayou Unit 4 in Texas, $101$197 million related to the development of STP Units 3 and 4 in Texas, $30$120 million for the repowering of the El Segundo generating station in California, and $19 million for the construction of Cos Cob in Connecticut. The Company’s estimated repowering capital expenditures for 2009 are expected to be approximately $256 million, of which capital expenditures related to STP units 3the Company’s Langford wind farm project which became commercially operational in December 2009 and 4 will be approximately $145$29 million for the construction of Cedar Bayou Unit 4 anticipated to be approximately $22 million, and the balance of thein Texas.
The Company’s repowering capital expenditures relatedfor 2010 are expected to the purchase of additional wind turbines. The Company also anticipates receivingbe approximately $145$707 million. Of this amount, $684 million in third partyis estimated for STP Units 3 and 4 without giving effect to any partner contributions or potential equity investments related to itsRepoweringNRG projects in 2009. Related toRepoweringNRG, the Company contributed equity of approximately $84 million to its Sherbino wind farm joint venture project with BP in 2008 which became commercially operational in October 2008.sell down.
Major maintenance and environmental capital expenditures — The Company’s baghouse projectmaintenance capital expenditures were $256 million, of which $160 million was related to the Texas region’s assets including approximately $61 million in nuclear fuel expenditures related to STP Units 1 and 2. The Company’s environmental capital expenditures were $172 million consisting of $130 million at itsthe Huntley and Dunkirk plants resulted in environmental capital expenditures of $124due to the baghouse projects and $31 million forat the year endedIndian River plant due to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Units 3 and 4. On February 3, 2010, NRG and DNREC announced a proposed plan, subject to definitive documentation, that would shut down Unit 3 by December 31, 2008. Other capital expenditures included $44 million for STP fuel2013 and $71 millionrelieve NRG of the requirement to install this back end control equipment on this unit. Unit 4 is not affected by this plan and construction on similar equipment continues with an expected in maintenance capital expenditures in Texas primarily related to the W.A. Parish and Limestone plants.service date of year end 2011. NRG anticipates funding these maintenance capital projects primarily with funds generated from operating activities. TheIn addition, on April 15, 2009, the Company is also pursuing funding for certainexecuted a $59 million tax-exempt bond financing through its wholly-owned subsidiary, Dunkirk Power LLC, with the bonds issued by the County of Chautauqua Industrial Development Agency. These funds are expected to fund environmental capital expenditures inat the Northeast region through Solid Waste Disposal Bonds utilizing tax exempt financing, and expects to draw upon such funds during 2009.Dunkirk facility. Loans to affiliates — During 2008 theThe Company loanedhad funded approximately $36$48 million in fundsinterest bearing loans to GenConn Energy LLC, a 50/50 joint venture vehicle of NRG and the United Illuminating Company as a part of the Devon and Middletown plant projects.repowering projects prior to the closing of the EBL and GenConn Facility. During 2009, these loans were repaid with proceeds from the EBL financing. Subsequent to the financing, the equity portion of construction costs for GenConn is funded through the EBLs of NRG Connecticut Peaking and United Illuminating. These loans, whichfunds are in the form of anmade available to GenConn through convertible interest bearing note, mature inpromissory notes that convert to equity upon repayment of the EBL loans by NRG Connecticut Peaking and United Illuminating. As of December 31, 2009, at which point GenConn Energy LLC’s construction costs are expected to be funded through equity ofthere was $108 million outstanding under the loan from NRG and the United Illuminating Company and non-recourse project level financing.Connecticut Peaking.
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Environmental Capital Expenditures Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures to be incurred from 20092010 through 20132014 to meet NRG’s environmental commitments will be approximately $1.2$0.9 billion. These capital expenditures, in general, are related to installation of particulate, SO2, NOx, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under the Phase II 316(b) rule. NRG continues to explore cost effective alternatives that can achieve desired results. While this estimate reflects schedules and controls to meet anticipated reduction requirements, the full impact on the scope and timing of environmental retrofits cannot be determined until issuance of final rules by the USEPA.U.S. EPA. The following table summarizes the estimated environmental capital expenditures for the referenced periods by region: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Texas | | Northeast | | South Central | | Total | | | Texas | | Northeast | | South Central | | Total | | | | | | (In millions) | | | | 2009 | | $ | — | | | $ | 256 | | | $ | — | | | $ | 256 | | | | | 2010 | | | 8 | | | | 213 | | | | 57 | | | | 278 | | | $ | — | | | $ | 230 | | | $ | 3 | | | $ | 233 | | 2011 | | | 17 | | | | 175 | | | | 116 | | | | 308 | | | | — | | | | 179 | | | | 52 | | | | 231 | | 2012 | | | 29 | | | | 67 | | | | 114 | | | | 210 | | | | 6 | | | | 45 | | | | 108 | | | | 159 | | 2013 | | | 21 | | | | 3 | | | | 74 | | | | 98 | | | | 39 | | | | 9 | | | | 109 | | | | 157 | | 2014 | | | | 50 | | | | 4 | | | $ | 68 | | | | 122 | | | | | | | | | | | | | | | | | | | | | Total | | $ | 75 | | | $ | 714 | | | $ | 361 | | | $ | 1,150 | | | $ | 95 | | | $ | 467 | | | $ | 340 | | | $ | 902 | | | | | | | | | | | | | | | | | | | | |
This estimate reflects the recent announcement to retrofit only Unit 4 at the Indian River Generating Station and shifts in the timing of other projects to reflect anticipated issuance dates for revised regulations. NRG’s current contracts with the Company’s rural electrical customers in the South Central region allow for recovery of a significant portion of the regions capital costs, along with a capital return incurred by complying with new laws, including interest over the asset life of the required expenditures. Actual recoveries will depend, among other things, on the duration of the contracts. Capital Allocation 2008 Capital Allocation Plan —In December 2007, the Company initiated its 2008 Capital Allocation Plan, with the repurchase of 2,037,700 shares of NRG common stock during that month for approximately $85 million. In February 2008, the Company’s Board of Directors authorized an additional $200 million in common share repurchases that raised the total 2008 Capital Allocation Plan to approximately $300 million. In the first quarter 2008, the Company repurchased 1,281,600 shares of NRG common stock for approximately $55 million. In the third quarter 2008, the Company repurchased an additional 3,410,283 of NRG common stock in the open market for approximately $130 million. As of December 31, 2008, NRG had repurchased a total of 6,729,583 shares of NRG common stock at a cost of approximately $270 million as part of its 2008 Capital Allocation Plan.
2009 Capital Allocation Plan —On October 30, 2008,In addition to the Company announced itsaforementioned planned investments in maintenance and environmental capital expenditures andRepoweringNRG in 2009, and the 2009 repayment of Term Loan Facility debt to the first lien lenders, the Company’s Capital Allocation Plan toincluded the completion of the 2008 Capital Allocation Plan with the purchase of $30 million of common stock as well as the purchase of an additional $300 million in common stock under the previously announced 2009 Capital Allocation Plan. In July 2009, as part of the Company’s 2009 Capital Allocation Program, the Board of Directors approved an increase to the Company’s previously authorized common share repurchases under its capital allocation plan from the existing $330 million to $500 million. The Company’s repurchases during the year ended December 31, 2009, were $500 million. 2010 Capital Allocation Plan —On February 23, 2010, the Company announced its 2010 Capital Allocation Plan to purchase $180 million in common stock. The Company’s share repurchases are subject to market prices, financial restrictions under USthe Company’s debt facilities, and as permitted by securities laws. As part of the 20092010 plan, the Company will invest over $511approximately $474 million in maintenance and environmental capital expenditures in existing assets in 2009 and $256$707 million in investment in projects underRepoweringNRG that are currently under construction or for which there exists current obligations. Finally, in addition to scheduled debt amortization payment, in the first quarter 20092010 the Company will offer its first lien lenders $197$430 million of its 20082009 excess cash flow (as defined in the Senior Credit Facility). of which the Company made a prepayment of $200 million in December 2009. Preferred Stock Dividend Payments For the year ended December 31, 2008,2009, NRG paid approximately $29$6 million, $17 million and $9$10 million in dividend payments to holders of the Company’s 5.75%, 4% and 3.625% Preferred Stock. On March 16, 2009, the outstanding shares of the 5.75% Preferred Stock converted into common stock and, as a result, there will be no further dividends paid with respect to this series of preferred stock. During 2009, a total of 265,870 shares of the 4% Preferred Stock were converted into common stock and 73 shares were redeemed for cash. 119
Benefit Plans Obligations As of December 31, 2008,2009, NRG contributed $99$27 million towards its three defined benefit pension plans to meet the Company’s 20082009 benefit obligation, $35 million of which was to partially fund the plans as a result of the weak market performance of plan assets in 2008.obligation. Based on the Company’s December 31, 20082009 measurement of its benefit obligation for its three defined benefit pension plans, the Company is expected to contribute another $60$18 million to these plans during 2009, $292010, $5 million of which also relates to the Company’s 20082009 benefit obligation.
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Cash Flow DiscussionReliant Energy Customer Deposits
Revisions in the PUCT rules will require that NRG keep a segregated account, or that the Company post a fully collateralized letter of credit on or before May 21, 2010 to cover outstanding customer deposits and residential advance payments. The Company’s current plan is to file for an amendment to its Retail Energy Provider recertification applications during the first quarter 2010 and post a letter of credit to satisfy the rule changes. The amount of deposits subject to segregation or collateralization at December 31, 2009, was $54 million. 2008 compared to 2007Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative years; all cash flow categories include the cash flows from both continuing operations and discontinued operations: | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year ended December 31, | | | 2008 | | 2007 | | Change | | | 2009 | | 2008 | | Change | | | (In millions) | | | (In millions) | | Net cash provided by operating activities | | $ | 1,434 | | | $ | 1,517 | | | $ | (83 | ) | | $ | 2,106 | | | $ | 1,479 | | | $ | 627 | | Net cash used by investing activities | | | (672 | ) | | | (327 | ) | | | (345 | ) | | | (954 | ) | | | (672 | ) | | | (282 | ) | Net cash used by financing activities | | | (442 | ) | | | (814 | ) | | | 372 | | | | (343 | ) | | | (487 | ) | | | 144 | |
Net Cash Provided By Operating Activities For the year ended December 31, 2008,2009, net cash provided by operating activities decreasedincreased by $83$627 million compared to the same period in 2007. The difference was2008, due to: | | | | • | Collateral paid Cash generated by Reliant Energy—In 2008, higher cash collateral paid Reliant Energy contributed approximately $855 million to support the Company’s hedging and trading activities decreasedconsolidated cash flow from operations by $292in 2009, primarily reflecting $966 million as compared toin pre-tax income since the same periodMay 1, 2009, acquisition date, adjusted for the non-cash effects of depreciation and amortization and changes in 2007.derivatives. | | | • | Working capital Lower cash flows from Wholesale Power Generation— The Company’s cash flow from operation excluding Reliant Energy was lower by approximately $228 million in 2009 compared to 2008, as decreases in generation and power prices impacted results from operations. In 2008, theaddition, $16 million more cash provided bywas used for working capital items increased by $196 million. Changes in option premiums collected from 20072009 compared to 2008, classifiedas higher coal inventory balances were partially offset by $72 million in other current liabilities increased as a result of the deferral of option premium revenue to 2009 to match revenues with option expiration dates. Further, changes to account receivable were caused by higher energy revenues in December 2007 as compared to December 2008 and changes to accounts payable were caused by reduced maintenance expenses incurred in December 2007 as compared to December 2008.lower pension contributions. |
Net Cash Used By Investing Activities For the year ended December 31, 2008,2009, net cash used in investing activities was approximately $345increased by $282 million more thancompared to the same period in 2007. This was2008, due to: | | | | • | Capital expenditures Acquisition of businesses—NRG’s capital expenditures increased by $418 During 2009, the Company paid $427 million, duenet of cash acquired of $6 million, toRepoweringNRG projects, primarily related to $398 million for wind turbines and construction activities related to Elbow Creek and other wind projects currently under development. acquire three businesses. | | | • | SaleProceeds from sale of equity method investment and discontinued operations—Proceeds Net proceeds from investing activities increased by $43 million in 2009 as compared to 2008 due to the sale of MIBRAG in June 2009 for net proceeds of $284 million compared to the sale of ITISA for proceeds, net of divested cash, divested, wereof $241 million in April 2008. |
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| | | | • | Asset sales Capital expenditures and loans to affiliates—The Company received $14 NRG’s capital expenditures decreased by $165 million in proceeds primarily from the sale of rail cars in 2008 compareddue to proceeds of $57 million for the sale of Red Bluff and Chowchilla II power plants and equipment in the same period in 2007 for a net decrease in cash of $43 million.decreased spending onRepoweringNRG. | | | • | Trading of emission allowances—Net purchases and sales of emission allowances resulted in a decrease in cash of $44$105 million for 20082009 as compared to 2007. | | | • | Equity Contribution —The Company contributed approximately $84 million to its equity investment in Sherbino.2008. |
Net Cash Used By Financing Activities For the year ended December 31, 2008,2009, net cash used by financing activities decreased by approximately $372$144 million compared to 2007,the same period in 2008, due to: | | | | • | Issuance of debt— During 2009, the Company received $688 million in gross proceeds from the 2019 Senior Notes, $108 million in NRG Connecticut Peaking financing, $52 million from the Dunkirk bonds and $19 million from other borrowings. During 2008, the Company received $20 million in proceeds from borrowings which resulted in a net cash increase of $872 million. | | | • | Term Loan Facility debt payment—In 2008,2009, the Company paid down $174$429 million of its Term Loan Facility, including the payment of excess cash flow, as discussed above underDebt Service Obligations. The Company paid down $332$174 million of its Term Loan Facility during 2007 for2008 which resulted in a net cash increasedecrease of $158 million for the year ended 2008 compared to the same period in 2007. |
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| | | | • | Share repurchase —During 2008, the Company repurchased approximately $185 million shares of NRG common stock, compared to $353 million for 2007 for a net $168 million increase to cash for the year ended 2008 compared to the same period in 2007.$255 million. | | | • | SaleOther debt payments— In November 2009, the Company paid $181 million to CS for the benefit of minority interest —The Company received $50 million in proceeds fromCSF II to unwind the sale of minority interest in NINA in the first half of 2008.Company’s CSF II notes and preferred interests. | | | • | Payment of financing element of acquired derivatives Share repurchase—For 2008, During 2009, the Company paid approximately $43repurchased common stock of $500 million for the settlement of gas swaps relatedas compared to the acquisition of Texas Genco in 2006. | | | • | Issuance of debt —During 2008 the Company received $20$185 million in proceeds from borrowings made by its subsidiaries.2008, which resulted in a net cash decrease of $315 million. |
NOL’s,NOLs, Deferred Tax Assets and FIN 48Uncertain Tax Position Implications, under ASC-740, Income Taxes, or ASC 740
As of December 31, 2008,2009, the Company had generated total domestic pre-tax book income of $1,644 million$1.5 billion and foreign continuing pre-tax book income of $85$161 million. The Company has net operating losses for tax return purposes available to offset taxable income in the current period. The tax return net operating losses have been classified as capital loss carryforwards for financial statement purposes and a full valuation allowance has been established. As of December 31, 2009, these capital losses have expired for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $239$280 million, of which $41$82 million will expire starting in 2011 through 2017 and of which $198 million do not have an expiration date. In addition to these amounts, the Company has $527$643 million of tax effected unrecognized tax benefits which relate primarily to net operating losses for tax return purposes but have been classified as capital loss carryforwards for financial statements purposes and for which a full valuation allowance has been established. As a result of the Company’s tax position, and based on current forecasts, we anticipate income tax payments of up to $100$75 million in 2009.2010. However, as the position remains uncertain offor the $527$643 million of tax effected unrecognized tax benefits, the Company has recorded a non-current tax liability of $208$347 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $208$347 million non-current tax liability for unrecognized tax benefits is primarily due to taxable earnings for the period for which there are no NOLs available to offset for financial statement purposes. The Company has been contacted foris under examination by the Internal Revenue Service for years 2004 through 2006. The audit commencedIt is possible that the IRS examination may conclude during 2010 but because of a possible extension, an estimate of the third quarter 2008 and is expected to continue for approximately 18 to 24 months. On July 6, 2007, the German government passed the Tax Reform Actrange of 2008, which reduces the German statutory and resulting effectivereasonably possible changes in unrecognized tax rates on earnings from approximately 36% to approximately 27% effective January 1, 2008. Due to this reduction in the statutory and resulting effective tax rate in 2007, NRG recognized a $29 million tax benefit and as of December 31, 2007, NRG had a German net deferred tax liability of approximately $84 million which includes the impact of this tax rate change.benefits cannot be made.
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Off-Balance Sheet Arrangements Obligations under Certain Guarantee Contracts NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See also Item 1514 — Note 25,26,Guarantees,to the Consolidated Financial Statements for additional discussion. Retained or Contingent Interests NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
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Derivative Instrument Obligations On August 11, 2005, NRG issuedThe Company’s 3.625% Preferred Stock that includes a feature which is considered an embedded derivative per SFAS 133.ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133.ASC 815. As of December 31, 2008,2009, based on the Company’s stock price, the embedded derivative wasout-of-the-money and had no redemption value. See also Item 1514 — Note 13,15,Capital Structure,to the Consolidated Financial Statements for additional discussion.
On October 13, 2006, NRG, through its unrestricted wholly-owned subsidiaries CSF I and CSF II issued notes and preferred interests for the repurchase of NRG’s common stock. Included in each agreement was a feature considered an embedded derivative per SFAS 133. Although it is considered a derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133. In August 2008, the Company amended the CSF I notes and preferred interests to early settle the CSF I embedded derivative. Accordingly, NRG made a cash payment of $45 million to CS for the benefit of CSF I, which was recorded to interest expense in the Company’s Consolidated Statement of Operations. As of December 31, 2008, based on the Company’s stock price, the CSF II embedded derivative was out-of-the-money and had no redemption value. See also Item 15 — Note 11,Debt and Capital Leases,to the Consolidated Financial Statements for additional discussion.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity Variable interest in Equity investments — As of December 31, 2008,2009, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. One of these investments, GenConn Energy LLC, is a variable interest entity for which NRG is not the primary beneficiary. NRG’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $135$93 million as of December 31, 2008.2009. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Item 1514 — Note 14,16,Investments Accounted for by the Equity Method,to the Consolidated Financial Statements for additional discussion. Letter of Credit Facilities — The Company’s $1.3 billion Synthetic Letter of Credit Facility is unfunded by NRG and is secured by a $1.3 billion cash deposit at Deutsche Bank AG, New York Branch that was funded using proceeds from the Term Loan Facility investors who participated in the facility syndication. Under the Synthetic Letter of Credit Facility, NRG is allowed to issue letters of credit for general corporate purposes including posting collateral to support the Company’s commercial operations activities. 122
Contractual Obligations and Commercial Commitments NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company’s capital expenditure programs. The following tables summarize NRG’s contractual obligations and contingent obligations for guarantee. See also Item 1514 — Note 11,12,Debt and Capital Leases, Note 21,22,Commitments and Contingencies, and Note 25,26,Guarantees, to the Consolidated Financial Statements for additional discussion.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | By Remaining Maturity at December 31, | | | | 2008 | | | | | | | Under
| | | | | | | | | Over
| | | | | | 2007
| | Contractual Cash Obligations | | 1 Year | | | 1-3 Years | | | 3-5 Years | | | 5 Years | | | Total(b) | | | Total | | | | (In millions) | | | Long-term debt (including estimated interest) | | $ | 858 | | | $ | 1,316 | | | $ | 3,267 | | | $ | 5,701 | | | $ | 11,142 | | | $ | 12,301 | | Capital lease obligations (including estimated interest) | | | 87 | | | | 37 | | | | 25 | | | | 172 | | | | 321 | | | | 390 | | Operating leases | | | 43 | | | | 79 | | | | 62 | | | | 193 | | | | 377 | | | | 420 | | RepoweringNRG project commitments | | | 27 | | | | — | | | | — | | | | — | | | | 27 | | | | 352 | | Fuel purchase and transportation obligations(a) | | | 1,513 | | | | 477 | | | | 182 | | | | 206 | | | | 2,378 | | | | 3,203 | | Pension minimum funding requirement(c) | | | 65 | | | | 95 | | | | 34 | | | | — | | | | 194 | | | | 196 | | Other postretirement benefits minimum funding requirement(d) | | | 4 | | | | 11 | | | | 4 | | | | — | | | | 19 | | | | 15 | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 2,597 | | | $ | 2,015 | | | $ | 3,574 | | | $ | 6,272 | | | $ | 14,458 | | | $ | 16,877 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | By Remaining Maturity at December 31, | | | | 2009 | | | | | | | Under
| | | | | | | | | Over
| | | | | | 2008
| | Contractual Cash Obligations | | 1 Year | | | 1-3 Years | | | 3-5 Years | | | 5 Years | | | Total(b) | | | Total | | | | (In millions) | | | Long-term debt (including estimated interest) | | $ | 1,074 | | | $ | 1,195 | | | $ | 3,950 | | | $ | 5,171 | | | $ | 11,390 | | | $ | 11,142 | | Capital lease obligations (including estimated interest) | | | 28 | | | | 30 | | | | 27 | | | | 107 | | | | 192 | | | | 321 | | Operating leases | | | 100 | | | | 120 | | | | 98 | | | | 264 | | | | 582 | | | | 421 | | Fuel purchase and transportation obligations(a) | | | 1,011 | | | | 405 | | | | 140 | | | | 600 | | | | 2,156 | | | | 2,378 | | Purchased power commitments(c) | | | 55 | | | | 56 | | | | 10 | | | | — | | | | 121 | | | | — | | Pension minimum funding requirement(d) | | | 21 | | | | 55 | | | | 56 | | | | 31 | | | | 163 | | | | 194 | | Other postretirement benefits minimum funding requirement(e) | | | 4 | | | | 6 | | | | 8 | | | | 5 | | | | 23 | | | | 19 | | Other liabilities(f) | | | 53 | | | | 75 | | | | 38 | | | | 230 | | | | 396 | | | | 98 | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 2,346 | | | $ | 1,942 | | | $ | 4,327 | | | $ | 6,408 | | | $ | 15,023 | | | $ | 14,573 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | Includes only those coal transportation and lignite commitments for 20092010 as no other nominations were made as of December 31, 2008.2009. Natural gas nomination is through February 2010. | 2011. | (b) | | Excludes $208$347 million non-current FIN 48 payable relating to NRG’s uncertain tax benefits under ASC-740 as the period of payment cannot be reasonably estimated. | Also excludes $415 million of asset retirement obligations which are discussed in Item 14 — Note 13,Asset Retirement Obligations,to the Consolidated Financial Statements. | (c) | | Includes commitments with both fixed and variable components. | (d) | | These amounts represent the Company’s estimated minimum pension contributions required under the Pension Protection Act of 2006. These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 20132015 is currently not available. | | (d)(e) | | These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 20132015 are currently not available. | (f) | | Includes water right agreements, service and maintenance agreements, stadium naming rights and other contractual obligations. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | By Remaining Maturity at December 31, | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2008 | | | | | By Remaining Maturity at December 31, 2009 | | | | Under
| | | | | | Over
| | | | 2007
| | | Under
| | | | | | Over
| | | | 2008
| | Guarantees, Indemnifications and Other Contingent Obligations | | 1 Year | | 1-3 Years | | 3-5 Years | | 5 Years | | Total | | Total | | | 1 Year | | 1-3 Years | | 3-5 Years | | 5 Years | | Total | | Total | | | | (In millions) | | | (In millions) | | | Synthetic letters of credit | | $ | 357 | | | $ | 83 | | | $ | — | | | $ | — | | | $ | 440 | | | $ | 743 | | | $ | 531 | | | $ | 186 | | | $ | — | | | $ | — | | | $ | 717 | | | $ | 440 | | Unfunded standby letters of credit and surety bonds | | | 5 | | | | — | | | | — | | | | — | | | | 5 | | | | 8 | | | | 61 | | | | 36 | | | | — | | | | — | | | | 97 | | | | 5 | | Asset sales guarantee obligations | | | — | | | | 112 | | | | — | | | | 17 | | | | 129 | | | | 148 | | | | — | | | | 118 | | | | — | | | | 8 | | | | 126 | | | | 129 | | Commercial sales arrangements | | | 192 | | | | 13 | | | | — | | | | 800 | | | | 1,005 | | | | 791 | | | | 104 | | | | 44 | | | | 103 | | | | 965 | | | | 1,216 | | | | 1,005 | | Other guarantees | | | 24 | | | | 30 | | | | — | | | | 26 | | | | 80 | | | | 32 | | | | | | | | — | | | | — | | | | 117 | | | | 117 | | | | 80 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 578 | | | $ | 238 | | | $ | — | | | $ | 843 | | | $ | 1,659 | | | $ | 1,722 | | | $ | 696 | | | $ | 384 | | | $ | 103 | | | $ | 1,090 | | | $ | 2,273 | | | $ | 1,659 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments NRG may enter into long-term power sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities and protect fuel inventories.facilities. In addition, in order to mitigate interest rate risk associated with the issuance of the Company’s variable rate and fixed rate debt, NRG enters into interest rate swap agreements. 123
NRG’s trading activities include contracts entered into to profit from market price changes as opposed to hedging an exposure, and are subject to limits in accordance with the Company’s risk management policy.Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial 119
instruments are recognized in earnings. These trading activities are a complement to NRG’s energy marketing portfolio. The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value.value in accordance with ASC 820,Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; identify changes in fair value attributable to changes in valuation techniques; disaggregate estimated fair values at December 31, 2008,2009, based on whethertheir level within the fair values are determined by quoted market prices or more subjective means;value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2008.2009. Also, in connection with the Company’s acquisition of Reliant Energy, NRG acquired retail load and supply contracts. The tables below also includes the fair value of these contracts receivingmark-to-market accounting treatment as of May 1, 2009. | | | | | | | | | Derivative Activity Gains/(Losses) | | (In millions) | | | (In millions) | | | | Fair value of contracts as of December 31, 2007 | | $ | (492 | ) | | Fair value of contracts as of December 31, 2008 | | | $ | 996 | | Contracts realized or otherwise settled during the period | | | 162 | | | | (432 | ) | Contracts acquired in conjunction with Reliant Energy | | | | (1,054 | ) | Changes in fair value | | | 1,326 | | | | 949 | | | | | | | | | Fair value of contracts as of December 31, 2008 | | $ | 996 | | | Fair value of contracts as of December 31, 2009 | | | $ | 459 | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | Fair Value of Contracts as of December 31, 2008 | | | | Maturity
| | | | | | | | | Maturity
| | | | | | | Less Than
| | | Maturity
| | | Maturity
| | | in Excess
| | | Total Fair
| | Sources of Fair Value Gains/(Losses) | | 1 Year | | | 1-3 Years | | | 4-5 Years | | | 4-5 Years | | | Value | | | | (In millions) | | | Prices actively quoted | | $ | (32 | ) | | $ | 14 | | | $ | — | | | $ | — | | | $ | (18 | ) | Prices provided by other external sources | | | 614 | | | | 114 | | | | 283 | | | | (46 | ) | | | 965 | | Prices provided by models and other valuation methods | | | 37 | | | | 12 | | | | — | | | | — | | | | 49 | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 619 | | | $ | 140 | | | $ | 283 | | | $ | (46 | ) | | $ | 996 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | Fair Value of Contracts as of December 31, 2009 | | | | Maturity
| | | | | | | | | Maturity
| | | | | | | Less Than
| | | Maturity
| | | Maturity
| | | in Excess
| | | Total Fair
| | Fair value hierarchy Gains/(Losses) | | 1 Year | | | 1-3 Years | | | 4-5 Years | | | 4-5 Years | | | Value | | | | (In millions) | | | Level 1 | | $ | 25 | | | $ | (13 | ) | | $ | (24 | ) | | $ | — | | | $ | (12 | ) | Level 2 | | | 159 | | | | 234 | | | | 118 | | | | (27 | ) | | | 484 | | Level 3 | | | (21 | ) | | | 7 | | | | 1 | | | | — | | | | (13 | ) | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 163 | | | $ | 228 | | | $ | 95 | | | $ | (27 | ) | | $ | 459 | | | | | | | | | | | | | | | | | | | | | | |
A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG’s contracts are non exchange-tradednon-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers orover-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company’s prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote then the mid point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company’s derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate the Company’s transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 5%3% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG’s net exposure after cash collateral paid/received under a specific master agreement is an asset, the Company is usingcalculates credit reserve applying the counterparty’s default swap rate. If the net exposure after cash collateral paid/received under a specific master agreement is a liability, the Company is usingcalculates credit reserve applying NRG’s default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG’s liabilities or that a market participant would be willing to pay for NRG’s assets. As of December 31, 20082009, the credit reserve resulted in a $22$1 million decreaseincrease in fair value which is composed of a $10$1 million gainloss in other comprehensive income, or OCI and a $12$2 million gain in derivative revenue.revenue and cost of operations. 124
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 20082009 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange andover-the-counter price quotations, time value, volatility factors and credit exposure. It is possible however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
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The Company has elected to disclose derivative activityassets and liabilities on atrade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company’s derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company’s portfolio. As discussed in Item 7A6A— Commodity Price Risk, NRG measures the sensitivity of the Company’s portfolio to potential changes in market prices using Value at Risk, or VAR,VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG’s risk management policy places a limit onone-day holding period VAR,VaR, which limits the Company’s net open position. As the Company’strade-by-trade derivative accounting results in agross-up of the Company’s derivative assets and liabilities, the net derivative assets and liability position is a better indicator of ourNRG’s hedging activity. As of December 31, 2008,2009, NRG’s net derivative asset was $996$459 million, an increasea decrease to total fair value of $1,488$537 million as compared to December 31, 2007.2008. This increasedecrease was primarily driven by the acquisition of Reliant Energy’s retail portfolio offset by increase in fair value due to the decreases in gas and power prices as well as the roll-off of trades that settled during the period. Based on a sensitivity analysis using simplified assumptions, the impact of a $1 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $489 million in the net value of derivatives as of December 31, 2009. Critical Accounting Policies and Estimates NRG’s discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the US.U.S. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles, or GAAP, requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed. On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. NRG’s significant accounting policies are summarized in Item 1514 — Note 2,Summary of Significant Accounting Policies, to the Consolidated Financial Statements. The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company’s 125
financial position and results of operations, and that require the most difficult, subjectiveand/or complex judgments by management regarding estimates about matters that are inherently uncertain. | | | | | Accounting Policy | | | | Judgments/Uncertainties Affecting Application | | Derivative Financial Instruments | | • | | Assumptions used in valuation techniques | | | • | | Assumptions used in forecasting generation | | | • | | Market maturity and economic conditions | | | • | | Contract interpretation | | | • | | Market conditions in the energy industry, especially the effects of price volatility on contractual commitments | Income Taxes and Valuation Allowance for Deferred Tax Assets | | • | | Ability to withstand legal challenges of tax authority decisions to withstand legal challenges or appeals | | | • | | Anticipated future decisions of tax authorities | | | • | | Application of tax statutes and regulations to transactions |
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| | | | | Accounting Policy
| | | | Judgments/Uncertainties Affecting Application | | | | • | | Ability to utilize tax benefits through carrybackscarry backs to prior periods and carryforwardscarry forwards to future periods | Impairment of Long Lived Assets | | • | | Recoverability of investment through future operations | | | • | | Regulatory and political environments and requirements | | | • | | Estimated useful lives of assets | | | • | | Environmental obligations and operational limitations | | | • | | Estimates of future cash flows | | | • | | Estimates of fair value (fresh start) | | | • | | Judgment about triggering events | Goodwill and Other Intangible Assets | | • | | Estimated useful lives for finite-lived intangible assets | | | • | | Judgment about impairment triggering events | | | • | | Estimates of reporting unit’s fair value | | | • | | Fair value estimate of certain power sales and fuel contracts using forward pricing curves as of the closing date over the life of each contractintangible assets acquired in business combinations | Contingencies | | • | | Estimated financial impact of event(s) | | | • | | Judgment about likelihood of event(s) occurring | | | • | | Regulatory and political environments and requirements | Accrued Unbilled Revenues of Reliant Energy | | Estimates of unbilled volumes |
Derivative Financial Instruments The Company follows the guidance of SFAS 133,ASC 815, to account for derivative financial instruments. SFAS 133ASC 815 requires the Company tomark-to-market all derivative instruments on the balance sheet, and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, NRG may apply hedge accounting to the Company’s derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure,exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivatives instruments accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged item, or deferred and recorded as a component of OCI, and subsequently recognized in earnings when the hedged transactions occur. 126
For purposes of measuring the fair value of derivative instruments, NRG uses quoted exchange prices and broker quotes. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. In order to qualify derivative instruments for hedged transactions, NRG estimates the forecasted generation occurring within a specified time period. Judgments related to the probability of forecasted generation occurring are based on available baseload capacity, internal forecasts of sales and generation, and historical physical delivery on similar contracts. The probability that hedged forecasted generation will occur by the end of a specified time period could change the results of operations by requiring amounts currently classified in OCI to be reclassified into earnings, creating increased variability in ourthe Company’s earnings. These estimations are considered to be critical accounting estimates. 122
Certain derivative financial instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered Normal Purchase and Normal Sales, or NPNS. The availability of this exception is based upon the assumption that NRG has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on available baseload capacity, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment, and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings. Income Taxes and Valuation Allowance for Deferred Tax Assets As of December 31, 2008,2009, NRG had a valuation allowance of approximately $359$233 million. This amount is comprised of U.S. domestic capital loss carryforwards and non-depreciable property of approximately $292$154 million, foreign net operating loss carryforwards of approximately $66$78 million and foreign capital loss carryforwards of approximately $1 million. In assessing the recoverability of NRG’s deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected capital gains and available tax planning strategies. As of December 31, 2007, cumulative net operating losses of $245 million had been fully utilized with the exception of state NOLs. The utilization of the Company’s NOLs depends on several factors, such as NRG’s ability to utilize tax benefits through carryforwards to future periods, the application of tax statutes and regulations to transactions.
NRG continues to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company’s significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2000. Evaluation of Assets for Impairment and Other Than Temporary Decline in Value In accordance with SFAS No. 144,ASC-360,Accounting for the Impairment or Disposal of Long-Lived AssetsProperty, Plant, and Equipment, or SFAS 144,ASC 360, NRG evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events are: | | | | • | Significant decrease in the market price of a long-lived asset; | | | • | Significant adverse change in the manner an asset is being used or its physical condition; | | | • | Adverse business climate; | | | • | Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset; | | | • | Current-period loss combined with a history of losses or the projection of future losses; and | | | • | Change in the Company’s intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life. |
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such 127
assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to the Company. Generally, fair value will be determined using valuation
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techniques such as the present value of expected future cash flows. NRG uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company’s estimates, and the impact of such variations could be material. For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assetsheld-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value under SFAS 144,ASC 360, whether in conjunction with an asset to be held and used or with an assetheld-for-sale, and the evaluation of asset impairment are, by their nature subjective. NRG considers quoted market prices in active markets to the extent they are available. In the absence of such information, the Company may consider prices of similar assets, consult with brokers, or employ other valuation techniques. NRG will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in the Company’s estimates, and the impact of such variations could be material. For the years ended December 31, 2008, and 2007, there were reductions of $23 million and $11 million, respectively, in income from continuing operation due to impairment of an investment in commercial paper. The Company recorded these impairments as a reduction to interest income. For the year ended December 31, 2006, there wasThere were no reductionimpairment charges on this investment in income from continuing operations due to an impairment.2009. NRG is also required to evaluate its equity-method and cost-method investments to determine whether or not they are impaired. Accounting Principles Board Opinion No. 18,ASC-323,The EquityInvestments-Equity Method of Accounting for Investments in Common Stockand Joint Ventures, or APB18,ASC 323, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under APB 18ASC 323 is whether the value is considered an “other than a temporary” decline in value. The evaluation and measurement of impairments under APB 18ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with SFAS 144.ASC 360. Similarly, the estimates that NRG makes with respect to its equity and cost-method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of SFAS 144,ASC 360, NRG would record its proportionate share of that impairment loss and would evaluate its investment for an other than temporary decline in value under APB 18.ASC 323. Goodwill and Other Intangible Assets As part of the acquisition of Texas Genco in 2006, NRG recorded goodwill and intangible assets at its Texas segment reporting unit. The Company also recorded intangible assets in connection with the Reliant Energy acquisition in 2009, measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. See Item 14 — Note 3,Business Acquisitions, to the Consolidated Financial Statements for a discussion of the Reliant Energy acquisition fair value measurements. The Company applied SFAS No. 141,ASC 805,Business Combinations,or SFAS 141,ASC 805, and SFAS 142ASC 350,Intangibles — Goodwill and Other, or ASC 350, to account for these intangibles.its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. However, goodwill and all intangible assets not subject to amortization are tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We testThe Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of ourthe Company’s operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. If it is determined that the fair value of a reporting unit is below its carrying amount, where necessary the Company’s goodwilland/or intangible asset with indefinite lives will be impaired at that time. 128
The Company performed its annual goodwill impairment assessment as of December 31, 20082009, for its Texas reporting unit, or NRG Texas, which is at the operating segment level. The impairment assessment included bothCompany determined the fair value of this reporting unit using primarily an income approach and
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then applied an overall market approaches, represented by discounted cash flow and earnings multiple methodologiesapproach reasonableness test to reconcile that consideredfair value with NRG’s overall market capitalization. Significant inputs to the following: Income approachdetermination of fair value were as follows:
| | | | • | For the three solid-fuel baseload plants that drive a majority of the value in the reporting unit, and for the region’s Elbow Creek, Langford and Cedar Bayou facilities that recently commenced operations, the Company applied a discounted cash flow valuationmethodology to their long-term budgets in accordance with the guidance in paragraphs B152 and B155 of SFAS 142. This approach is consistent with that used to determine fair value at December 31, 2008 and 2007. These budgets are based on the Company’s views of power and fuel prices, which consider market prices in the near term and the Company’s fundamental view for the region’s major solid fuel baseload plants that utilizedlonger term as some relevant market prices are illiquid beyond 24 months. Hedging is included to the Company’s six-year budget dataextent of contracts already in place. Projected generation in the long-term budgets is based on management’s estimate of supply and a market-derived earnings multiple terminal value, with such terminal value assesseddemand within thesub-markets for reasonableness by capitalizingeach plant and the final year’s cash flow with adjustments for expected inflation;physical and economic characteristics of each plant; | | | • | For the reporting unit’s remaining gas plants, the Company applied a discounted cash flow valuation formarket-derived earnings multiple to the tax benefit associatedgas plants’ aggregate estimated 2009 earnings before interest, taxes, depreciation and amortization, in accordance with the amortization of tax basis of the region’s intangible assets;guidance in ASC-350-20-35-24. This approach is consistent with that used to determine fair values at December 31, 2008 and 2007; | | | • | The potential impact of carbon legislation was estimated using a market approach valuationdiscounted cash flow methodology applied to the Company’s view of the region’s gas plants using market-derived earnings multiplesimpact of comparable power generators, with adjustments for the region’s expected capital expenditure requirements;potential legislation that is based on recent proposals to Congress. |
Market approach
| | | | • | an overall market approach reasonableness test that reconciled NRG’s current market value based uponIf fair value of a reporting unit exceeds its carrying value, goodwill of the reporting unit is not considered impaired. Under the average percent of total company value represented by NRG Texas, as measured by four different earnings measures, each calculated over three different historical time periods. This market approach reasonableness test also considered sensitivity testing under a number of different implied control premium scenarios, including one with no premium. |
The income approach methodologies were consistent withdescribed above, the approach for determiningCompany estimated the fair value of NRG Texas’ invested capital to exceed its carrying value by approximately 25% at December 31, 2009. This estimate of fair value is affected by assumptions about projected power prices, generation, fuel costs, capital expenditure requirements and environmental regulations, and the Company believes that the most significant impact arises from future power prices. Assuming all other factors are held constant, a hypothetical $1 drop in the Company’s long-term natural gas price view would not have caused the fair value of NRG Texas to fall below its carrying value at December 31, 2007 and 2006. Significant assumptions and judgments impacting the Company’s goodwill impairment assessment included management’s projections of operating results and capital expenditure requirements, risk-adjusted discount rates, market performance, and other factors. Under all methodologies, the calculated NRG Texas equity value exceeded the NRG Texas book value, and the Company concluded that goodwill was not impaired as of December 31, 2008.2009.
In connection with the Texas Genco acquisition, the Company recognized the estimated fair value of certain power sale contracts and fuel contracts acquired. NRG estimated their fair value using forward pricing curves as of the closing date of the acquisition over the life of each contract. These contracts had net negative fair values at the closing date of the acquisition and were reflected as assumed contracts in the consolidated balance sheets. Assumed contracts are amortized to revenues and fuel expense as applicable based on the estimated realization ofTo reconcile the fair value establisheddetermined under the income approach with NRG’s market capitalization, the Company considered historical and future budgeted earnings measures to estimate the average percentage of total company value represented by NRG Texas, and applied this percentage to an adjusted business enterprise value of NRG. To derive this adjusted business enterprise value, the Company applied a range of control premiums based on recent market transactions to the business enterprise value of NRG on a non-controlling, marketable basis, and also made adjustments for some non-operating assets and for some of the significant factors that impact NRG differently from NRG Texas, such as environmental capital expenditures outside of the Texas region, or limitations on the closing date overCompany’s Capital Allocation Plans under NRG’s debt. The Company was able to reconcile the contractual lives.proportional value of NRG Texas to NRG’s market capitalization at a value that would not indicate an impairment.
Contingencies NRG records a loss contingency when management determines it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 1514 — Note 21,22,Commitments and Contingencies,to the Consolidated Financial Statements. 129
Accrued Unbilled Revenues Accrued unbilled revenues related to the Reliant Energy segment are critical accounting estimates as volumes are not precisely known at the end of each reporting period and the revenue amounts are material. Accrued unbilled revenues were $308 million as of December 31, 2009, which represents 3% of the Company’s consolidated revenues for the year ended December 31, 2009, and 7% of Reliant Energy’s revenues for the eight-month period ended December 31, 2009. Accrued unbilled revenues are based on Reliant Energy’s estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. Recent Accounting Developments See Item 1514 — Note 2,Summary of Significant Accounting Policies,to the Consolidated Financial Statements for a discussion of recent accounting developments.
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| | Item 7A6A — | Quantitative and Qualitative Disclosures about Market Risk |
NRG is exposed to several market risks in the Company’s normal business activities. Market risk is the potential loss that may result from market changes associated with the Company’s merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk and currency exchange risk. In order to manage these risks the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in theover-the-counter financial markets to: | | | | • | Manage and hedge fixed-price purchase and sales commitments; | | | • | Manage and hedge exposure to variable rate debt obligations; | | | • | Reduce exposure to the volatility of cash market prices;prices, and | | | • | Hedge fuel requirements for the Company’s generating facilities. |
Commodity Price Risk Commodity price risks result from exposures to changes in spot prices, forward prices, volatility in commodities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. A number of factors influence the level and volatility of prices for energy commodities and related derivative products. These factors include: | | | | • | Seasonal, daily and hourly changes in demand; | | | • | Extreme peak demands due to weather conditions; | | | • | Available supply resources; | | | • | Transportation availability and reliability within and between regions; and | | | • | Changes in the nature and extent of federal and state regulations. |
As partNRG’s portfolio consists of NRG’s overall portfolio,generation assets and full requirement load serving obligations. NRG manages the commodity price risk of the Company’s merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases ofand fuel. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as New York Mercantile Exchange, or NYMEX, Intercontinental Exchange, or ICE, and Chicago Climate Exchange, or CCX, as well asover-the-counter financial markets. The portion of forecasted transactions hedged may vary based upon management’s assessment of market, weather, operation and other factors.
While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company’s best estimates to determine the fair value of commodity andthose derivative contracts held and sold. These estimates consider various factors, including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. contracts. 130
However, it is likely that future market prices could vary from those used in recordingmark-to-market derivative instrument valuation, and such variations could be material. NRG measures the risk of the Company’s portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VAR. VARVaR. VaR is a statistical model that attempts to predict risk of loss based on market price and volatility. Currently, the company estimates VARVaR using a Monte Carlo simulation based methodology. NRG’s total portfolio includes mark-to-market and non mark-to-market energy assets and liabilities. NRG uses a diversified VARVaR model to calculate an estimate of the potential loss in the fair value of the Company’s energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions. The key assumptions for the Company’s diversified model include: (i) a lognormal
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distribution of prices,prices;(ii) one-day holding period,period; (iii) a 95% confidence interval,interval; (iv) a rolling36-month forward looking period,period; and (v) market implied volatilities and historical price correlations. As of December 31, 2008,2009, the VARVaR for NRG’s commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the diversified VARVaR model was $43$38 million. The following table summarizes average, maximum and minimum VARVaR for NRG for the year ended December 31, 20082009, and 2007:2008: | | | | | | | | | VAR | | In millions | | | | | VaR | | | In millions | As of December 31, 2009 | | | $ | 38 | | Average | | | | 41 | | Maximum | | | | 55 | | Minimum | | | | 28 | | As of December 31, 2008 | | $ | 43 | | | $ | 43 | | Average | | | 50 | | | | 50 | | Maximum | | | 65 | | | | 65 | | Minimum | | | 35 | | | | 35 | | As of December 31, 2007(a) | | $ | 64 | | | Average | | | 28 | | | Maximum | | | 64 | | | Minimum | | | 14 | | |
| | | (a) | | Prior to December 4, 2007, NRG’s VAR measurement was based on a rolling24-month forward looking period |
Due to the inherent limitations of statistical measures such as VAR,VaR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VARVaR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value ofmark-to-market energy assets and liabilities could differ from the calculated VAR,VaR, and such changes could have a material impact on the Company’s financial results. In order to provide additional information for comparative purposes to NRG’s peers, the Company also uses VARVaR to estimate the potential loss of derivative financial instruments that are subject tomark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VARVaR for the derivative financial instruments calculated using the diversified VARVaR model as of December 31, 2008,2009, for the entire term of these instruments entered into for both asset management and trading, was approximately $35$24 million primarily driven byasset-backed transactions. Interest Rate Risk NRG is exposed to fluctuations in interest rates through the Company’s issuance of fixed rate and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG’s risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations. In JanuaryMay 2009, NRG entered into a series of forward-starting interest rate swaps. These interest rate swaps become effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company will pay its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its 131
counterparties are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which mature on February 1, 2013, is $900 million. In 2006, the Company entered into a series of new interest rate swaps. These interest rate swaps became effective on February 15, 2006, andwhich are intended to hedge the risk associated with floating interest rates. For each of the interest rate swaps, NRG pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the equivalent of a floating interest payment based on a3-month LIBOR rate calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made quarterly, and the LIBOR is determined in advance of each interest period. While the notional value of each of the swaps does not vary over time, the swaps are designed to mature sequentially. The total notional amount of these swaps as of December 31, 20082009, was $1.9$1.7 billion.
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The maturities and notional amounts of each tranche of these swaps in connection with the Senior Credit Facility are as follows: | | | | | Maturity | | Notional Value | | | March 31, 2009 | | $ | 150 million | | March 31, 2010 | | $ | 190 million | | March 31, 2011 | | $ | 1.55 billion | |
In addition to those listeddiscussed above, the Company had the following additional interest rate swaps outstanding as of December 31, 2008:2009: | | | | | | | | | | | Notional Value | | | Maturity | | | Floating to fixed interest rate swap for NRG Peaker Financing LLC | | $ | 266251 million | | | | June 10, 2019 | | Fixed to floating interest rate swap for Senior notes,Notes, due 2014 | | $ | 400 million | | | | December 15, 2013 | |
If all of the above swaps had been discontinued on December 31, 2008,2009, the Company would have owed the counterparties approximately $156$104 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant. NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of December 31, 2008,2009, a 1% change in interest rates would result in a $12.8$10 million change in interest expense on a rolling twelve month basis. As of December 31, 2008,2009, the Company’s long-term debt fair value was $7.5$8.2 billion and the carrying amount was $8.0$8.3 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company’s long-term debt by $401$415 million. Liquidity Risk Liquidity risk arises from the general funding needs of NRG’s activities and in the management of the Company’s assets and liabilities. NRG’s liquidity management framework is intended to maximize liquidity access and minimize funding costs. Through active liquidity management, the Company seeks to preserve stable, reliable and cost-effective sources of funding. This enables the Company to replace maturing obligations when due and fund assets at appropriate maturities and rates. To accomplish this task, management uses a variety of liquidity risk measures that take into consideration market conditions, prevailing interest rates, liquidity needs, and the desired maturity profile of liabilities. Based on a sensitivity analysis for power and gas positions under marginable contracts, a $1 per MMBtu increase or decreasechange in natural gas prices across the term of the marginable contracts for power and gas positions would cause a change in margin collateral outstandingposted of approximately $72$128 million as of December 31, 2008. In addition,2009, and a 0.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $82$51 million as of December 31, 2008.2009. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2008.2009. Currently, NRG is exposed to additional margin if natural gas prices decrease. Under the second lien, NRG is required to post certain letter of credits as credit support for changes in commodity prices. As of December 31, 2008, $19 million in2009, no letters of credit are outstanding to second lien counterparties. With changes in commodity prices, the letters of credit could grow to $87$64 million, the cap under the agreements. 132
Credit Risk Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process,process; (ii) a daily monitoring of counterparties’ credit limits,limits; (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives, prepayment arrangements, or prepayment
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arrangements,volumetric limits; (iv) the use of payment netting agreements,agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a diversified portfolio of counterparties, including tennine participants under its first and second lien structure. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.
A sharp economic downturn in the US and overseas markets during the latter part of 2008 was prompted by a combination of factors: tight credit markets, speculation and fear over the health of the US and global financial systems, and weaker economic activity in general prompting fears of an economic recession. Under the current market dynamics, the Company has heightened its management and mitigation of counterparty credit risk by using credit limits, netting agreements, collateral thresholds, volumetric limits and other mitigation measures, where available. NRG avoids concentration of counterparties whenever possible and applies credit policies that include an evaluation of counterparties’ financial condition, collateral requirements and the use of standard agreements that allow for netting and other security.
As of December 31, 2008,2009, total credit exposure to substantially all wholesale counterparties was $2.0$1.3 billion and NRG held collateral (cash and letters of credit) against those positions of $788$186 million resulting in a net exposure of $1.2$1.1 billion. Total credit exposure is discounted at the risk free rate. The following table highlights the credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit risk is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark to marketmark-to-market and normal purchase and saleNPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables. | | | | | | | Net Exposure(a)
| | Category | | (% of Total) | | | Coal producers | | | 16 | % | Financial institutions | | | 5869 | % | Utilities, energy merchants, marketers and marketersother | | | 2125 | | Coal suppliers | | | 3 | | ISOs | | | 53 | | | | | | | Total as of December 31, 20082009 | | | 100 | % | | | | | |
| | | | | | | Net Exposure(a)
| | Category | | (% of Total) | | | Investment grade | | | 8190 | % | Non-Investment gradeNon-rated | | | 8 | | Non-ratedNon- Investment grade | | | 112 | | | | | | | Total as of December 31, 20082009 | | | 100 | % | | | | | |
| | | (a) | | Credit exposure excludes California tolling, uranium, coal transportation/railcar leases, New England Reliability Must-Run,RMR, certain cooperative load contracts and Texas Westmoreland coal contracts. The aforementioned exposures were excluded for various reasons including regulatory support liens held against the contracts which serve to reduce the risk of loss, or credit risks for certain contracts are not readily measurable due to a lack of market reference prices. |
NRG has credit risk exposure to certain wholesale counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $241$351 million. No counterparty represents more than 20% of total net credit exposure. Approximately 80%82% of NRG’s positions relating to credit risk roll-off by the end of 2011.2012. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate anya material adverse effectimpact on the Company’s financial position or results of operations as a result offrom nonperformance by any of NRG’s counterparties. NRG is exposed to retail credit risk through its competitive electricity supply business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and anyin-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
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As of December 31, 2009, the Company’s credit exposure to C&I customers was diversified across many customers and various industries. No one customer represented more than 2% of total exposure and the majority of the customers have investment grade credit quality, as determined by NRG. NRG is also exposed to credit risk relating to its 1.5 million Mass customers, which may result in a write-off of a bad debt. The current economic conditions may affect the Company’s customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense. Certain of the Company’s hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements. Other agreements contain provisions that require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. The collateral required forout-of-the-money positions and net accounts payable for contracts that have adequate assurance clauses that are in a net liability position as of December 31, 2009, was $80 million. The collateral required forout-of-the-money positions and net accounts payable for contracts with credit rating contingent features that are in a net liability position as of December 31, 2009, was $49 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $3 million as of December 31, 2009. Currency Exchange Risk NRG may be subject to foreign currency risk as a result of the Company entering into purchase commitments with foreign vendors for the purchase of major equipment associated withRepoweringNRG initiatives. To reduce the risks to such foreign currency exposure, the Company may enter into transactions to hedge its foreign currency exposure using currency options and forward contracts. At December 31, 2008,2009, no foreign currency options and forward contracts were outstanding. In connection with the MIBRAG sale transaction, NRG entered into a foreign currency forward contract to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in exchange for $255 million on June 15, 2009. For the year ended December 31, 2009, NRG recorded an exchange loss of $24 million on the contract within “Other income/(loss), net.” As a result of the Company’s limited foreign currency exposure to date, the effect of foreign currency fluctuations has not been material to the Company’s results of operations, financial position and cash flows. The effects of a hypothetical simultaneous 10% appreciation in the USU.S. dollar from year-end 20072008 levels against all other currencies of countries in which the Company has continuing operations would result in an immaterial impact to NRG’s consolidated statements of operations and approximately $58$79 million in pre-tax unrealized income reflected in the currency translation adjustment component of OCI. | | Item 87 — | Financial Statements and Supplementary Data |
The financial statements and schedules are listed in Part IV, Item 1514 of thisForm 10-K. | | Item 98 — | Changes in and Disagreements with Accountants on Accounting and Financial Disclosures |
None. | | Item 9A8A — | Controls and Procedures |
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures Under the supervision and with the participation of NRG’s management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined inRules 13a-15(e) or15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, the Company’s principal executive officer, principal financial officer and principal accounting 134
officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this annual report onForm 10-K. Management’s report on the Company’s internal control over financial reporting and the report of the Company’s independent registered public accounting firm are incorporated under the caption “Management’s Report on Internal Control over Financial Reporting” and under the caption “Report of Independent Registered Public Accounting Firm,” of the Company’s 20082009 Annual Report to Shareholders. Changes in Internal Control over Financial Reporting Except for the remediation of the material weakness discussed below, thereThere were no changes in the Company’s internal control over financial reporting (as such term is defined inRule 13a-15(f) under the Exchange Act) that occurred in the fourth quarter of 20082009 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Material Weakness Related to Operating Revenues
Subsequent to the filing of the September 30, 2008Form 10-Q, the Company identified a material weakness in our internal control over financial reporting related to the accounting for option premiums on certain derivative instruments. This material weakness resulted from the operational ineffectiveness of reconciliation and review controls specifically related to our accounting for premiums on energy options.
The material weakness resulted in an error to operating revenues of $78 million in the third quarter of 2008. In thisForm 10-K, we have revised our unaudited quarterly financial data for the quarter ended September 30, 2008. For further information, see Item 15 — Note 27,Unaudited Quarterly Financial Data, to the Consolidated Financial Statements.
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In connection with this material weakness, we reevaluated our disclosure controls and procedures as of September 30, 2008. Based on this reevaluation, and solely as a result of this material weakness, the Company’s principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were not effective as of September 30, 2008.
Remediation of Material Weakness in Internal Control
During the fourth quarter, a number of remedial actions were taken to address the material weakness, which included:
| | | | • | Reviewing and documenting all mark-to-market logic in our power marketing trading activity system, including any manual adjustments related thereto; | | | • | Formalizing and documenting energy options accounting; | | | • | Formalizing the analysis and review by management of realized and unrealized gain/(loss) derivative accounts; | | | • | Expanding the communication process between accounting, risk management and commercial operations groups to understand derivative accounting results and changes in the commercial operations portfolio; and | | | • | Establishing ongoing training and education in the Company’s accounting group on accounting for derivative option premiums |
We have completed the process of implementing the aforementioned enhancements, and believe that we have fully remediated the material weakness in our internal control over financial reporting with respect to the appropriate accounting for option premiums on certain derivative instruments as of December 31, 2008.
Inherent Limitations over Internal Controls NRG’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. The 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 our assets; | | | 2. | Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and | | | 3. | Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements. |
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. 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. | | Item 9B8B — | Other Information |
None.
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PART III | | Item 109 — | Directors, Executive Officers and Corporate Governance |
NRG Energy, Inc. has adopted a code of ethics entitled “NRG Code of Conduct” that applies to directors, officers and employees, including the chief executive officer and senior financial officers of NRG Energy, Inc. It may be accessed through the Corporate Governance section of NRG Energy Inc.’s website athttp://www.nrgenergy.com/investor/corpgov.htm.NRG Energy, Inc. also elects to disclose the information required byForm 8-K, Item 5.05, “Amendments to the registrant’s code of ethics, or waiver of a provision of the code of ethics,” through the Company’s website, and such information will remain available on this website for at least a12-month period. A copy of the “NRG Energy, Inc. Code of Conduct” is available in print to any shareholder who requests it. Other information required by this Item will be incorporated by reference to the similarly named section of NRG’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders. | | Item 1110 — | Executive Compensation |
Other information required by this Item will be incorporated by reference to the similarly named section of NRG’s definitiveDefinitive Proxy Statement for its 20092010 Annual Meeting of Stockholders. | | Item 1211 — | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Other information required by this Item will be incorporated by reference to the similarly named section of NRG’s definitiveDefinitive Proxy Statement for its 20092010 Annual Meeting of Stockholders. | | Item 1312 — | Certain Relationships and Related Transactions, and Director Independence |
Other information required by this Item will be incorporated by reference to the similarly named section of NRG’s definitiveDefinitive Proxy Statement for its 20092010 Annual Meeting of Stockholders. | | Item 1413 — | Principal AccountantAccounting Fees and Services |
Other information required by this Item will be incorporated by reference to the similarly named section of NRG’s definitiveDefinitive Proxy Statement for its 20092010 Annual Meeting of Stockholders.
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PART IV | | Item 1514 — | Exhibits and Financial Statement Schedules |
(a)(1) Financial Statements The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP are included herein:
Consolidated Statement of Operations — Years ended December 31, 2008, 2007 and 2006
Consolidated Balance Sheet — December 31, 2008 and 2007
Consolidated Statement of Cash Flows — Years ended December 31, 2008, 2007 and 2006
Consolidated Statement of Stockholders’ Equity and Comprehensive Income/(Loss) — Years ended December 31, 2008, 2007 and 2006
Notes to Consolidated Financial Statements
| | | The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP are included herein: | | | Consolidated Statements of Operations — Years ended December 31, 2009, 2008 and 2007 | | | Consolidated Balance Sheets — December 31, 2009 and 2008 | | | Consolidated Statements of Cash Flows — Years ended December 31, 2009, 2008 and 2007 | | | Consolidated Statement of Stockholders’ Equity and Comprehensive Income/(Loss) — Years ended December 31, 2009, 2008 and 2007 | | | Notes to Consolidated Financial Statements |
(a)(2) Financial Statement Schedule The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.
Schedule II — Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.
| | | The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 14(d) of this report and should be read in conjunction with the Consolidated Financial Statements. | | | Schedule II — Valuation and Qualifying Accounts | | | All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted. |
(a)(3)Exhibits:See Exhibit Index submitted as a separate section of this report. (b) Exhibits | | (b) | ExhibitsSee Exhibit Index submitted as a separate section of this report. |
See Exhibit Index submitted as a separate section of this report.(c) Not applicable
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING NRG Energy Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange ActRule 13a-15(f). Under the supervision and with the participation of the Company’s management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company’s evaluation under the framework in Internal Control — Integrated Framework, the Company’s management concluded that its internal control over financial reporting was effective as of December 31, 2008.2009. The effectiveness of the Company’s internal control over financial reporting as of December 31, 20082009 has been audited by KPMG LLP, the Company’s independent registered public accounting firm, as stated in its report which is included in thisForm 10-K.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders
NRG Energy, Inc.: We have audited NRG Energy, Inc.’s internal control over financial reporting as of December 31, 2008,2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NRG Energy, Inc.’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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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, NRG Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008,2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 20082009 and 2007,2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income / (loss), and cash flows for each of the years in the three-year period ended December 31, 2008,2009, and our report dated February 12, 200923, 2010 expressed an unqualified opinion on those consolidated financial statements. /s/ KPMG LLP
KPMG LLP Philadelphia, Pennsylvania February 12, 200923, 2010
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders
NRG Energy, Inc.: We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 20082009 and 2007,2008, and the related consolidated statements of operations, consolidated statement of stockholders’ equity and comprehensive income/income / (loss), and consolidated statements of cash flows for each of the years in the three-year period ended December 31, 2008.2009. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule “Schedule II. Valuation and Qualifying Accounts.” These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Energy, Inc. and subsidiaries as of December 31, 20082009 and 2007,2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008,2009, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presentspresent fairly, in all material respects, the information set forth therein. As discussed in Note 2 to the consolidated financial statements, in order to comply with the requirements of U.S. generally accepted accounting principles, the Company adopted Statement of Financial Accounting Standards (SFAS) 141R,Business Combinations(incorporated into Accounting Standards Codification (ASC) Topic 805,Business Combinations), SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, Consolidated Financial Statements(incorporated into ASC Topic 810,Consolidation), Financial Accounting Standards Board Staff Position (FSP FAS) 141R-1,Accounting for Assets and Liabilities Assumed in a Business Combination That Arise from Contingencies(incorporated into ASC Topic 805,Business Combinations), and FSP Accounting Principles Board (APB)No. 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlements) (incorporated into ASC Topic 825,Financial Instruments), effective January 1, 2009; SFAS No. 157,Fair Value Measurements(incorporated into ASC Topic 820,Fair Value Measurements and Disclosures), effective January 1, 2008; and FASB Interpretation No. 48, Accounting“Accounting for Uncertainty in Income Taxes — an Interpretation of SFAS No. 109,109” (incorporated into ASC Topic 740,Income Taxes), effective January 1, 2007; Emerging Issues Task Force IssueNo. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry, and SFAS No. 123R, Share Based Payments, and related interpretations effective January 1, 2006; and SFAS No 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of SFAS No. 87, 88, 106 and 132R, effective December 31, 2006.2007. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of NRG Energy, Inc.’s and subsidiaries internal control over financial reporting as of December 31, 2008,2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 12, 200923, 2010 expressed an unqualified opinion on the effectivenesseffective operation of the Company’s internal control over financial reporting. /s/ KPMG LLP
KPMG LLP Philadelphia, Pennsylvania February 12, 200923, 2010
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, | | | For the Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | | | (In millions except per share amounts) | | | | | (In millions, except per share amounts) | | | 2009 | | 2008 | | 2007 | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 6,885 | | | $ | 5,989 | | | $ | 5,585 | | | $ | 8,952 | | | $ | 6,885 | | | $ | 5,989 | | | | | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Cost of operations | | | 3,598 | | | | 3,378 | | | | 3,265 | | | | 5,323 | | | | 3,598 | | | | 3,378 | | Depreciation and amortization | | | 649 | | | | 658 | | | | 590 | | | | 818 | | | | 649 | | | | 658 | | General and administrative | | | 319 | | | | 309 | | | | 276 | | | Selling, general and administrative | | | | 550 | | | | 319 | | | | 309 | | Acquisition-related transaction and integration costs | | | | 54 | | | | — | | | | — | | Development costs | | | 46 | | | | 101 | | | | 36 | | | | 48 | | | | 46 | | | | 101 | | | | | | | | | | | | | | | | | Total operating costs and expenses | | | 4,612 | | | | 4,446 | | | | 4,167 | | | | 6,793 | | | | 4,612 | | | | 4,446 | | Gain on sale of assets | | | — | | | | 17 | | | | — | | | | — | | | | — | | | | 17 | | | | | | | | | | | | | | | | | Operating Income | | | 2,273 | | | | 1,560 | | | | 1,418 | | | | 2,159 | | | | 2,273 | | | | 1,560 | | | | | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | | | | | | | | | | | | | Equity in earnings of unconsolidated affiliates | | | 59 | | | | 54 | | | | 60 | | | | 41 | | | | 59 | | | | 54 | | Gains on sales of equity method investments | | | — | | | | 1 | | | | 8 | | | | 128 | | | | — | | | | 1 | | Other income, net | | | 17 | | | | 55 | | | | 156 | | | Other income/(loss), net | | | | (5 | ) | | | 17 | | | | 55 | | Refinancing expenses | | | — | | | | (35 | ) | | | (187 | ) | | | (20 | ) | | | — | | | | (35 | ) | Interest expense | | | (620 | ) | | | (689 | ) | | | (590 | ) | | | (634 | ) | | | (583 | ) | | | (702 | ) | | | | | | | | | | | | | | | | Total other expenses | | | (544 | ) | | | (614 | ) | | | (553 | ) | | | (490 | ) | | | (507 | ) | | | (627 | ) | | | | | | | | | | | | | | | | Income From Continuing Operations Before Income Taxes | | | 1,729 | | | | 946 | | | | 865 | | | | 1,669 | | | | 1,766 | | | | 933 | | Income tax expense | | | 713 | | | | 377 | | | | 322 | | | | 728 | | | | 713 | | | | 377 | | | | | | | | | | | | | | | | | Income From Continuing Operations | | | 1,016 | | | | 569 | | | | 543 | | | | 941 | | | | 1,053 | | | | 556 | | Income from discontinued operations, net of income taxes | | | 172 | | | | 17 | | | | 78 | | | | — | | | | 172 | | | | 17 | | | | | | | | | | | | | | | | | Net Income | | | 1,188 | | | | 586 | | | | 621 | | | | 941 | | | | 1,225 | | | | 573 | | Less: Net loss attributable to noncontrolling interest | | | | (1 | ) | | | — | | | | — | | | | | | | | | | | Net Income attributable to NRG Energy, Inc. | | | | 942 | | | | 1,225 | | | | 573 | | | | | | | | | | | Dividends for preferred shares | | | 55 | | | | 55 | | | | 50 | | | | 33 | | | | 55 | | | | 55 | | | | | | | | | | | | | | | | | Income Available for Common Stockholders | | $ | 1,133 | | | $ | 531 | | | $ | 571 | | | $ | 909 | | | $ | 1,170 | | | $ | 518 | | | | | | | | | | | | | | | | | Earnings per share attributable to NRG Energy, Inc. Common Stockholders | | | | | | | | | | | | | | Weighted average number of common shares outstanding — basic | | | 235 | | | | 240 | | | | 258 | | | | 246 | | | | 235 | | | | 240 | | Income from continuing operations per weighted average common share — basic | | $ | 4.09 | | | $ | 2.14 | | | $ | 1.90 | | | $ | 3.70 | | | $ | 4.25 | | | $ | 2.09 | | Income from discontinued operations per weighted average common share — basic | | | 0.73 | | | | 0.07 | | | | 0.31 | | | | — | | | | 0.73 | | | | 0.07 | | | | | | | | | | | | | | | | | Net Income per Weighted Average Common Share — Basic | | $ | 4.82 | | | $ | 2.21 | | | $ | 2.21 | | | $ | 3.70 | | | $ | 4.98 | | | $ | 2.16 | | | | | | | | | | | | | | | | | Weighted average number of common shares outstanding — diluted | | | 275 | | | | 288 | | | | 301 | | | | 271 | | | | 275 | | | | 288 | | Income from continuing operations per weighted average common share — diluted | | $ | 3.66 | | | $ | 1.95 | | | $ | 1.78 | | | $ | 3.44 | | | $ | 3.80 | | | $ | 1.90 | | Income from discontinued operations per weighted average common share — diluted | | | 0.63 | | | | 0.06 | | | | 0.26 | | | | — | | | | 0.63 | | | | 0.06 | | | | | | | | | | | | | | | | | Net Income per Weighted Average Common Share — Diluted | | $ | 4.29 | | | $ | 2.01 | | | $ | 2.04 | | | $ | 3.44 | | | $ | 4.43 | | | $ | 1.96 | | | | | | | | | | | | | | | | | Amounts Attributable to NRG Energy, Inc.: | | | | | | | | | | | | | | Income from continuing operations, net of income taxes | | | | 942 | | | | 1,053 | | | | 556 | | Income from discontinued operations, net of income taxes | | | | — | | | | 172 | | | | 17 | | | | | | | | | | | Net Income | | | $ | 942 | | | $ | 1,225 | | | $ | 573 | | | | | | | | | | |
See notes to Consolidated Financial Statements.
137141
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | | | | 2008 | | 2007 | | | 2009 | | 2008 | | | | (In millions) | | | (In millions) | | | ASSETS | ASSETS | ASSETS | Current Assets | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 1,494 | | | $ | 1,132 | | | $ | 2,304 | | | $ | 1,494 | | Funds deposited by counterparties | | | 754 | | | | — | | | | 177 | | | | 754 | | Restricted cash | | | 16 | | | | 29 | | | | 2 | | | | 16 | | Accounts receivable — trade, less allowance for doubtful accounts of $3 and $1 | | | 464 | | | | 482 | | | Current portion of note receivable— affiliate and capital leases | | | 68 | | | | 30 | | | Accounts receivable — trade, less allowance for doubtful accounts of $29 and $3 | | | | 876 | | | | 464 | | Current portion of note receivable — affiliate and capital leases | | | | 32 | | | | 68 | | Inventory | | | 455 | | | | 451 | | | | 541 | | | | 455 | | Derivative instruments valuation | | | 4,600 | | | | 1,034 | | | | 1,636 | | | | 4,600 | | Deferred income taxes | | | — | | | | 124 | | | Cash collateral paid in support of energy risk management activities | | | 494 | | | | 85 | | | | 361 | | | | 494 | | Prepayments and other current assets | | | 147 | | | | 144 | | | | 279 | | | | 147 | | Current assets — discontinued operations | | | — | | | | 51 | | | | | | | | | | | | | | Total current assets | | | 8,492 | | | | 3,562 | | | | 6,208 | | | | 8,492 | | | | | | | | | | | | | Property, Plant and Equipment | | | | | | | | | | | | | | | | | In service | | | 13,084 | | | | 12,678 | | | | 14,083 | | | | 13,084 | | Under construction | | | 804 | | | | 337 | | | | 533 | | | | 804 | | | | | | | | | | | | | Total property, plant and equipment | | | 13,888 | | | | 13,015 | | | | 14,616 | | | | 13,888 | | Less accumulated depreciation | | | (2,343 | ) | | | (1,695 | ) | | | (3,052 | ) | | | (2,343 | ) | | | | | | | | | | | | Net property, plant and equipment | | | 11,545 | | | | 11,320 | | | | 11,564 | | | | 11,545 | | | | | | | | | | | | | Other Assets | | | | | | | | | | | | | | | | | Equity investments in affiliates | | | 490 | | | | 425 | | | | 409 | | | | 490 | | Capital leases and note receivable, less current portion | | | 435 | | | | 491 | | | Note receivable — affiliate and capital leases, less current portion | | | | 504 | | | | 435 | | Goodwill | | | 1,718 | | | | 1,786 | | | | 1,718 | | | | 1,718 | | Intangible assets, net of accumulated amortization of $335 and $372 | | | 815 | | | | 873 | | | Intangible assets, net of accumulated amortization of $648 and $335 | | | | 1,777 | | | | 815 | | Nuclear decommissioning trust fund | | | 303 | | | | 384 | | | | 367 | | | | 303 | | Derivative instruments valuation | | | 885 | | | | 150 | | | | 683 | | | | 885 | | Other non-current assets | | | 125 | | | | 190 | | | | 148 | | | | 125 | | Non-current assets — discontinued operations | | | — | | | | 93 | | | | | | | | | | | | | | Total other assets | | | 4,771 | | | | 4,392 | | | | 5,606 | | | | 4,771 | | | | | | | | | | | | | Total Assets | | $ | 24,808 | | | $ | 19,274 | | | $ | 23,378 | | | $ | 24,808 | | | | | | | | | | | | |
See notes to Consolidated Financial Statements.
138142
NRG ENERGY, INC.LIABILITIES AND SUBSIDIARIES STOCKHOLDERS’ EQUITY
CONSOLIDATED BALANCE SHEETS — (Continued)
| | | | | | | | | | | | As of December 31, | | | | | | | | | | | | 2008 | | 2007 | | | As of December 31, | | | | (In millions, except share
| | | 2009 | | 2008 | | | | data) | | | (In millions, except share data) | | | LIABILITIES AND STOCKHOLDERS’ EQUITY | LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | Current Liabilities | | | | | | | | | | | | | | | | | Current portion of long-term debt and capital leases | | $ | 464 | | | $ | 466 | | | $ | 571 | | | $ | 464 | | Accounts payable — trade | | | 447 | | | �� | 381 | | | | 693 | | | | 447 | | Accounts payable — affiliates | | | 4 | | | | 3 | | | | 4 | | | | 4 | | Derivative instruments valuation | | | 3,981 | | | | 917 | | | | 1,473 | | | | 3,981 | | Deferred income taxes | | | 201 | | | | — | | | | 197 | | | | 201 | | Cash collateral received in support of energy risk management activities | | | 760 | | | | 14 | | | | 177 | | | | 760 | | Accrued interest expense | | | 178 | | | | 185 | | | | 207 | | | | 178 | | Other accrued expenses | | | 215 | | | | 189 | | | | 298 | | | | 215 | | Other current liabilities | | | 331 | | | | 85 | | | | 142 | | | | 331 | | Current liabilities — discontinued operations | | | — | | | | 37 | | | | | | | | | | | | | | Total current liabilities | | | 6,581 | | | | 2,277 | | | | 3,762 | | | | 6,581 | | | | | | | | | | | | | Other Liabilities | | | | | | | | | | | | | | | | | Long-term debt and capital leases | | | 7,704 | | | | 7,895 | | | | 7,847 | | | | 7,697 | | Nuclear decommissioning reserve | | | 284 | | | | 307 | | | | 300 | | | | 284 | | Nuclear decommissioning trust liability | | | 218 | | | | 326 | | | | 255 | | | | 218 | | Postretirement and other benefit obligations | | | 277 | | | | 263 | | | | 287 | | | | 277 | | Deferred income taxes | | | 1,190 | | | | 843 | | | | 1,783 | | | | 1,190 | | Derivative instruments valuation | | | 508 | | | | 759 | | | | 387 | | | | 508 | | Out-of-market contracts | | | 291 | | | | 628 | | | | 294 | | | | 291 | | Other non-current liabilities | | | 392 | | | | 149 | | | | 519 | | | | 392 | | Non-current liabilities — discontinued operations | | | — | | | | 76 | | | | | | | | | | | | | | Total non-current liabilities | | | 10,864 | | | | 11,246 | | | | 11,672 | | | | 10,857 | | | | | | | | | | | | | Total Liabilities | | | 17,445 | | | | 13,523 | | | | 15,434 | | | | 17,438 | | | | | | | | | | | | | Minority Interest | | | 7 | | | | — | | | 3.625% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs) | | | 247 | | | | 247 | | | | 247 | | | | 247 | | Commitments and Contingencies | | | | | | | | | | | | | | | | | Stockholders’ Equity | | | | | | | | | | | | | | | | | 4% convertible perpetual preferred stock; $0.01 par value; 420,000 shares issued and outstanding (at liquidation value of $420, net of issuance costs) | | | 406 | | | | 406 | | | 5.75% convertible perpetual preferred stock; $0.01 par value, 1,841,680 shares issued and outstanding at December 31, 2008, (at liquidation value of $462, net of issuance costs) and 2,000,000 shares issued and outstanding at December 31, 2007 (at liquidation value of $500, net of issuance costs) | | | 447 | | | | 486 | | | Common Stock; $0.01 par value; 500,000,000 shares authorized; 263,599,200 and 261,285,529 shares issued and 234,356,717 and 236,734,929 shares outstanding at December 31, 2008 and 2007 | | | 3 | | | | 3 | | | Additionalpaid-in-capital | | | 4,363 | | | | 4,092 | | | 4% convertible perpetual preferred stock; $0.01 par value; 154,057 shares issued and outstanding at December 31, 2009 (at liquidation value of $154, net of issuance costs) and 420,000 shares issued and outstanding at December 31, 2008 (at liquidation value of $420, net of issuance costs) | | | | 149 | | | | 406 | | 5.75% convertible perpetual preferred stock; $0.01 par value, 1,841,680 shares issued and outstanding at December 31, 2008 (at liquidation value of $460, net of issuance costs) | | | | — | | | | 447 | | Common stock; $0.01 par value; 500,000,000 shares authorized; 295,861,759 and 263,599,200 shares issued and 253,995,308 and 234,356,717 shares outstanding at December 31, 2009 and 2008 | | | | 3 | | | | 3 | | Additionalpaid-in capital | | | | 4,948 | | | | 4,350 | | Retained earnings | | | 2,403 | | | | 1,270 | | | | 3,332 | | | | 2,423 | | Less treasury stock, at cost — 29,242,483 and 24,550,600 shares at December 31, 2008 and 2007 | | | (823 | ) | | | (638 | ) | | Accumulated other comprehensive income/(loss) | | | 310 | | | | (115 | ) | | Less treasury stock, at cost - 41,866,451 and 29,242,483 shares at December 31, 2009 and 2008 | | | | (1,163 | ) | | | (823 | ) | Accumulated other comprehensive income | | | | 416 | | | | 310 | | Noncontrolling interest | | | | 12 | | | | 7 | | | | | | | | | | | | | Total Stockholders’ Equity | | | 7,109 | | | | 5,504 | | | | 7,697 | | | | 7,123 | | | | | | | | | | | | | Total Liabilities and Stockholders’ Equity | | $ | 24,808 | | | $ | 19,274 | | | $ | 23,378 | | | $ | 24,808 | | | | | | | | | | | | |
See notes to Consolidated Financial Statements.
139143
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME/(LOSS)INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated
| | | | | | | | | | | | | | | | | | | Accumulated
| | | | | | | | | | | | | | | | Additional
| | | | | | Other
| | Total
| | | | | | | | | | | Additional
| | | | | | Other
| | | | Total
| | | | Serial Preferred | | Common | | Paid-In
| | Retained
| | Treasury
| | Comprehensive
| | Stockholders’
| | | Serial Preferred | | Common | | Paid-In
| | Retained
| | Treasury
| | Comprehensive
| | Noncontrolling
| | Stockholders’
| | | | Stock | | Shares | | Stock | | Shares | | Capital | | Earnings | | Stock | | Income/(Loss) | | Equity | | | Stock | | Shares | | Stock | | Shares | | Capital | | Earnings | | Stock | | Income/(Loss) | | Interest | | Equity | | | | (In millions) | | | (In millions) | | | | Balances at December 31, 2005 | | $ | 406 | | | | 0.4 | | | $ | 3 | | | | 161 | | | $ | 2,429 | | | $ | 261 | | | $ | (663 | ) | | $ | (205 | ) | | $ | 2,231 | | | Net income | | | | | | | | | | | | | | | | | | | | | | | 621 | | | | | | | | | | | | 621 | | | Foreign currency translation adjustments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 60 | | | | 60 | | | Unrealized gain on derivatives, net of $135 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 405 | | | | 405 | | | Minimum pension liability, net of $3 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | 7 | | | | | | | | Comprehensive income for 2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,093 | | | Impact upon adoption of SFAS 158, net of $10 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 15 | | | | 15 | | | Reduction to tax valuation allowance | | | | | | | | | | | | | | | | | | | 17 | | | | | | | | | | | | | | | | 17 | | | Impact upon adoption of EITF04-6 | | | | | | | | | | | | | | | | | | | | | | | (93 | ) | | | | | | | | | | | (93 | ) | | Equity-based compensation | | | | | | | | | | | | | | | | | | | 14 | | | | | | | | | | | | | | | | 14 | | | Issuance of common stock to the public | | | | | | | | | | | | | | | 42 | | | | 986 | | | | | | | | | | | | | | | | 986 | | | Issuance of preferred stock | | | 486 | | | | 2.0 | | | | | | | | | | | | | | | | | | | | | | | | | | | | 486 | | | Issuance of common and treasury stock to the shareholders of Texas Genco | | | | | | | | | | | | | | | 71 | | | | 1,028 | | | | | | | | 663 | | | | | | | | 1,691 | | | Preferred stock dividends | | | | | | | | | | | | | | | | | | | | | | | (50 | ) | | | | | | | | | | | (50 | ) | | Purchase of treasury stock | | | | | | | | | | | | | | | (29 | ) | | | | | | | | | | | (732 | ) | | | | | | | (732 | ) | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2006 | | | 892 | | | | 2.4 | | | | 3 | | | | 245 | | | | 4,474 | | | | 739 | | | | (732 | ) | | | 282 | | | | 5,658 | | | $ | 892 | | | | 2.4 | | | $ | 3 | | | | 245 | | | $ | 4,506 | | | $ | 735 | | | $ | (732 | ) | | $ | 282 | | | $ | — | | | $ | 5,686 | | Net income | | | | | | | | | | | | | | | | | | | | | | | 586 | | | | | | | | | | | | 586 | | | | | | | | | | | | | | | | | | | | | | | | 573 | | | | | | | | | | | | | | | | 573 | | Foreign currency translation adjustments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 73 | | | | 73 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 73 | | | | | | | | 73 | | Unrealized loss on derivatives, net of $310 tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (474 | ) | | | (474 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (474 | ) | | | | | | | (474 | ) | Available-for-sale securities, net of $1 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | | 2 | | Defined benefit plan — prior service cost of $4 and net loss of $2, net of $2 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | | 2 | | | | | | | | | Comprehensive income for 2007 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 189 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 176 | | Equity-based compensation | | | | | | | | | | | | | | | 1 | | | | 9 | | | | | | | | | | | | | | | | 9 | | | | | | | | | | | | | | | | 1 | | | | 9 | | | | | | | | | | | | | | | | | | | | 9 | | Reduction to tax valuation allowance | | | | | | | | | | | | | | | | | | | 56 | | | | | | | | | | | | | | | | 56 | | | | | | | | | | | | | | | | | | | | 56 | | | | | | | | | | | | | | | | | | | | 56 | | Preferred stock dividends | | | | | | | | | | | | | | | | | | | | | | | (55 | ) | | | | | | | | | | | (55 | ) | | | | | | | | | | | | | | | | | | | | | | | (55 | ) | | | | | | | | | | | | | | | (55 | ) | Purchase of treasury stock | | | | | | | | | | | | | | | (9 | ) | | | | | | | | | | | (353 | ) | | | | | | | (353 | ) | | | | | | | | | | | | | | | (9 | ) | | | | | | | | | | | (353 | ) | | | | | | | | | | | (353 | ) | Retirement of treasury stock | | | | | | | | | | | | | | | | | | | (447 | ) | | | | | | | 447 | | | | | | | | — | | | | | | | | | | | | | | | | | | | | (447 | ) | | | | | | | 447 | | | | | | | | | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2007 | | | 892 | | | | 2.4 | | | | 3 | | | | 237 | | | | 4,092 | | | | 1,270 | | | | (638 | ) | | | (115 | ) | | | 5,504 | | | | 892 | | | | 2.4 | | | | 3 | | | | 237 | | | | 4,124 | | | | 1,253 | | | | (638 | ) | | | (115 | ) | | | — | | | | 5,519 | | Net income | | | | | | | | | | | | | | | | | | | | | | | 1,188 | | | | | | | | | | | | 1,188 | | | | | | | | | | | | | | | | | | | | | | | | 1,225 | | | | | | | | | | | | | | | | 1,225 | | Foreign currency translation adjustments, net of $22 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (112 | ) | | | (112 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (112 | ) | | | | | | | (112 | ) | Reclassification adjustment for translation loss realized upon sale of ITISA | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 15 | | | | 15 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 15 | | | | | | | | 15 | | Unrealized gain on derivatives, net of $369 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 580 | | | | 580 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 580 | | | | | | | | 580 | | Available-for-sale securities, net of $2 tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4 | ) | | | (4 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4 | ) | | | �� | | | | (4 | ) | Defined benefit plan — prior service credit of $1 and net loss of $55, net of $35 tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (54 | ) | | | (54 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (54 | ) | | | | | | | (54 | ) | | | | | | | | Comprehensive income for 2008 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,613 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,650 | | Equity-based compensation | | | | | | | | | | | | | | | 1 | | | | 25 | | | | | | | | | | | | | | | | 25 | | | | | | | | | | | | | | | | 1 | | | | 25 | | | | | | | | | | | | | | | | | | | | 25 | | Payment to settle CSF I CAGR | | | | | | | | | | | | | | | | | | | | (45 | ) | | | | | | | | | | | | | | | | | | | (45 | ) | Purchase of treasury stock | | | | | | | | | | | | | | | (5 | ) | | | | | | | | | | | (185 | ) | | | | | | | (185 | ) | | | | | | | | | | | | | | | (5 | ) | | | | | | | | | | | (185 | ) | | | | | | | | | | | (185 | ) | Reduction to tax valuation allowance | | | | | | | | | | | | | | | | | | | 162 | | | | | | | | | | | | | | | | 162 | | | | | | | | | | | | | | | | | | | | 162 | | | | | | | | | | | | | | | | | | | | 162 | | Preferred stock dividends | | | | | | | | | | | | | | | | | | | | | | | (55 | ) | | | | | | | | | | | (55 | ) | | | | | | | | | | | | | | | | | | | | | | | (55 | ) | | | | | | | | | | | | | | | (55 | ) | NINA contribution, net of $17 tax | | | | | | | | | | | | | | | | | | | 26 | | | | | | | | | | | | | | | | 26 | | | | | | | | | | | | | | | | | | | | 26 | | | | | | | | | | | | | | | | 7 | | | | 33 | | 5.75% preferred stock conversion to common stock | | | (39 | ) | | | (0.1 | ) | | | | | | | 1 | | | | 39 | | | | | | | | | | | | | | | | — | | | | (39 | ) | | | (0.1 | ) | | | | | | | 1 | | | | 39 | | | | | | | | | | | | | | | | | | | | — | | Other | | | | | | | | | | | | | | | | | | | 19 | | | | | | | | | | | | | | | | 19 | | | | | | | | | | | | | | | | | | | | 19 | | | | | | | | | | | | | | | | | | | | 19 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2008 | | $ | 853 | | | | 2.3 | | | $ | 3 | | | | 234 | | | $ | 4,363 | | | $ | 2,403 | | | $ | (823 | ) | | $ | 310 | | | $ | 7,109 | | | $ | 853 | | | | 2.3 | | | $ | 3 | | | | 234 | | | $ | 4,350 | | | $ | 2,423 | | | $ | (823 | ) | | $ | 310 | | | $ | 7 | | | $ | 7,123 | | Net income/(loss) | | | | | | | | | | | | | | | | | | | | | | | | 942 | | | | | | | | | | | | (1 | ) | | | 941 | | Foreign currency translation adjustments, net of $21 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 35 | | | | | | | | 35 | | Reclassification adjustment for translation loss realized upon sale of MIBRAG, net of tax benefit $13 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (22 | ) | | | | | | | (22 | ) | Unrealized gain on derivatives, net of $53 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 91 | | | | | | | | 91 | | Available-for-sale securities, net of $2 tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4 | | | | | | | | 4 | | Defined benefit plan — prior service credit of $1 and net loss of $8, net of $1 tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2 | ) | | | | | | | (2 | ) | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive income for 2009 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,047 | | Equity-based compensation | | | | | | | | | | | | | | | | | | | | 26 | | | | | | | | | | | | | | | | | | | | 26 | | Purchase of treasury stock | | | | | | | | | | | | | | | | (19 | ) | | | | | | | | | | | (500 | ) | | | | | | | | | | | (500 | ) | Preferred stock dividends | | | | | | | | | | | | | | | | | | | | | | | | (33 | ) | | | | | | | | | | | | | | | (33 | ) | ESPP share purchases | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | | | | | 2 | | NINA contribution, net of $16 tax | | | | | | | | | | | | | | | | | | | | 28 | | | | | | | | | | | | | | | | 6 | | | | 34 | | 5.75% preferred stock conversion to common stock | | | | (447 | ) | | | (1.9 | ) | | | | | | | 19 | | | | 447 | | | | | | | | | | | | | | | | | | | | — | | 4.00% preferred stock conversion to common stock | | | | (257 | ) | | | (0.3 | ) | | | | | | | 13 | | | | 257 | | | | | | | | | | | | | | | | | | | | — | | Shares loaned to affiliate of CS | | | | | | | | | | | | | | | | 12 | | | | (291 | ) | | | | | | | 291 | | | | | | | | | | | | — | | Shares returned from affiliate of CS | | | | | | | | | | | | | | | | (5 | ) | | | 131 | | | | | | | | (131 | ) | | | | | | | | | | | — | | Other | | | | | | | | | | | | | | | | | | | | (2 | ) | | | | | | | | | | | | | | | | | | | (2 | ) | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2009 | | | $ | 149 | | | | 0.1 | | | $ | 3 | | | | 254 | | | $ | 4,948 | | | $ | 3,332 | | | $ | (1,163 | ) | | $ | 416 | | | $ | 12 | | | $ | 7,697 | | | | | | | | | | | | | | | | | | | | | | | | |
See notes to Consolidated Financial Statements.Statements
140144
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | | | | (In millions) | | | (In millions) | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | | | | | | | | | | | | Net income | | $ | 1,188 | | | $ | 586 | | | $ | 621 | | | $ | 941 | | | $ | 1,225 | | | $ | 573 | | Adjustments to reconcile net income to net cash provided by operating activities | | | | | | | | | | | | | | Distributions less than equity in earnings of unconsolidated affiliates | | | (44 | ) | | | (33 | ) | | | (33 | ) | | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | Distributions and equity in earnings of unconsolidated affiliates | | | | (41 | ) | | | (44 | ) | | | (33 | ) | Depreciation and amortization | | | 649 | | | | 661 | | | | 607 | | | | 818 | | | | 649 | | | | 661 | | Provision for bad debts | | | | 61 | | | | — | | | | — | | Amortization of nuclear fuel | | | 39 | | | | 58 | | | | 47 | | | | 36 | | | | 39 | | | | 58 | | Amortization and write-off of financing costs and debt discount/premiums | | | 29 | | | | 66 | | | | 79 | | | Amortization of financing costs and debt discount/premiums | | | | 44 | | | | 37 | | | | 79 | | Amortization of intangibles and out-of-market contracts | | | (270 | ) | | | (156 | ) | | | (490 | ) | | | 153 | | | | (270 | ) | | | (156 | ) | Amortization of unearned equity compensation | | | 26 | | | | 19 | | | | 14 | | | | 26 | | | | 26 | | | | 19 | | Gains on sale of equity method investments | | | — | | | | (1 | ) | | | (8 | ) | | Loss/(gain) on disposals and sales of assets | | | 25 | | | | (17 | ) | | | 10 | | | | 17 | | | | 25 | | | | (17 | ) | Impairment charges and asset write downs | | | 23 | | | | 20 | | | | — | | | | — | | | | 23 | | | | 20 | | Changes in derivatives | | | (484 | ) | | | 77 | | | | (149 | ) | | | (225 | ) | | | (484 | ) | | | 77 | | Changes in deferred income taxes and liability for unrecognized tax benefits | | | 762 | | | | 359 | | | | 327 | | | | 689 | | | | 762 | | | | 359 | | Gain on legal settlement | | | — | | | | — | | | | (67 | ) | | Gain on sales of equity method investments | | | | (128 | ) | | | — | | | | (1 | ) | Gain on sale of discontinued operations | | | (273 | ) | | | — | | | | (76 | ) | | | — | | | | (273 | ) | | | — | | Gain on sale of emission allowances | | | (51 | ) | | | (31 | ) | | | (64 | ) | | | (4 | ) | | | (51 | ) | | | (31 | ) | Change in nuclear decommissioning trust liability | | | 34 | | | | 32 | | | | 12 | | | Gain recognized on settlement of pre-existing relationship | | | | (31 | ) | | | — | | | | — | | Changes in nuclear decommissioning trust liability | | | | 26 | | | | 34 | | | | 32 | | Changes in collateral deposits supporting energy risk management activities | | | (417 | ) | | | (125 | ) | | | 454 | | | | 127 | | | | (417 | ) | | | (125 | ) | Settlement of out-of-market power contracts | | | — | | | | — | | | | (1,073 | ) | | Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects | | | | | | | | | | | | | | Accounts receivable, net | | | 1 | | | | (102 | ) | | | 87 | | | Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects: Accounts receivable, net | | | | 88 | | | | 1 | | | | (102 | ) | Inventory | | | (5 | ) | | | (38 | ) | | | (50 | ) | | | (83 | ) | | | (5 | ) | | | (38 | ) | Prepayments and other current assets | | | (7 | ) | | | 22 | | | | 43 | | | | 26 | | | | (7 | ) | | | 22 | | Accounts payable | | | (31 | ) | | | 49 | | | | (73 | ) | | | (176 | ) | | | (31 | ) | | | 49 | | Option premiums collected | | | | (282 | ) | | | 268 | | | | 8 | | Accrued expenses and other current liabilities | | | 262 | | | | 106 | | | | 133 | | | | 48 | | | | (6 | ) | | | 98 | | Other assets and liabilities | | | (22 | ) | | | (35 | ) | | | 57 | | | | (24 | ) | | | (22 | ) | | | (35 | ) | | | | | | | | | | | | | | | | Net Cash Provided by Operating Activities | | | 1,434 | | | | 1,517 | | | | 408 | | | | 2,106 | | | | 1,479 | | | | 1,517 | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | | | | | | | | | | | | Acquisition of Texas Genco, WCP and Padoma, net of cash acquired | | | — | | | | — | | | | (4,333 | ) | | Acquisition of businesses, net of cash acquired | | | | (427 | ) | | | — | | | | — | | Capital expenditures | | | (899 | ) | | | (481 | ) | | | (221 | ) | | | (734 | ) | | | (899 | ) | | | (481 | ) | Decrease in restricted cash, net | | | 13 | | | | 12 | | | | 6 | | | Decrease in notes receivable | | | 10 | | | | 34 | | | | 27 | | | Increase in restricted cash, net | | | | 14 | | | | 13 | | | | 12 | | (Increase)/decrease in notes receivable | | | | (22 | ) | | | 10 | | | | 34 | | Decrease in trust fund balances | | | — | | | | 19 | | | | — | | | | — | | | | — | | | | 19 | | Purchases of emission allowances | | | (8 | ) | | | (161 | ) | | | (135 | ) | | | (78 | ) | | | (8 | ) | | | (161 | ) | Proceeds from sale of emission allowances | | | 75 | | | | 272 | | | | 146 | | | | 40 | | | | 75 | | | | 272 | | Investments in nuclear decommissioning trust fund securities | | | (616 | ) | | | (265 | ) | | | (227 | ) | | | (305 | ) | | | (616 | ) | | | (265 | ) | Proceeds from sales of nuclear decommissioning trust fund securities | | | 582 | | | | 233 | | | | 214 | | | | 279 | | | | 582 | | | | 233 | | Proceeds from sale of assets | | | 14 | | | | 2 | | | | 86 | | | Proceeds from sale of assets, net | | | | 6 | | | | 14 | | | | 2 | | Proceeds from sale of equity method investment | | | | 284 | | | | — | | | | — | | Equity investment in unconsolidated affiliate | | | (84 | ) | | | — | | | | — | | | | (6 | ) | | | (84 | ) | | | — | | Purchases of securities | | | — | | | | (49 | ) | | | — | | | | — | | | | — | | | | (49 | ) | Proceeds from sale of discontinued operations and assets, net of cash divested | | | 241 | | | | 57 | | | | 260 | | | | — | | | | 241 | | | | 57 | | Return of capital from equity method investments | | | — | | | | — | | | | 1 | | | Other | | | | (5 | ) | | | — | | | | — | | | | | | | | | | | | | | | | | Net Cash Used by Investing Activities | | | (672 | ) | | | (327 | ) | | | (4,176 | ) | | | (954 | ) | | | (672 | ) | | | (327 | ) | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | | | | | | | | | | | | Payment of dividends to preferred stockholders | | | (55 | ) | | | (55 | ) | | | (50 | ) | | | (33 | ) | | | (55 | ) | | | (55 | ) | Payment of financing element of acquired derivatives | | | (43 | ) | | | — | | | | (296 | ) | | Net payments to settle acquired derivatives that include financing elements | | | | (79 | ) | | | (43 | ) | | | — | | Payment for treasury stock | | | (185 | ) | | | (353 | ) | | | (732 | ) | | | (500 | ) | | | (185 | ) | | �� | (353 | ) | Proceeds from sale of minority interest in subsidiary | | | 50 | | | | — | | | | — | | | Funded letter of credit | | | — | | | | — | | | | 350 | | | Installment proceeds from sale of noncontrolling interest in subsidiary | | | | 50 | | | | 50 | | | | — | | Payment to settle CSF I CAGR | | | | — | | | | (45 | ) | | | — | | Proceeds from issuance of common stock, net of issuance costs | | | 9 | | | | 7 | | | | 986 | | | | 2 | | | | 9 | | | | 7 | | Proceeds from issuance of preferred shares, net of issuance costs | | | — | | | | — | | | | 486 | | | Proceeds from issuance of long-term debt | | | 20 | | | | 1,411 | | | | 8,619 | | | | 892 | | | | 20 | | | | 1,411 | | Payment of deferred debt issuance costs | | | (4 | ) | | | (5 | ) | | | (199 | ) | | | (31 | ) | | | (4 | ) | | | (5 | ) | Payments for short and long-term debt | | | (234 | ) | | | (1,819 | ) | | | (5,111 | ) | | | (644 | ) | | | (234 | ) | | | (1,819 | ) | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Financing Activities | | | (442 | ) | | | (814 | ) | | | 4,053 | | | Net Cash Used by Financing Activities | | | | (343 | ) | | | (487 | ) | | | (814 | ) | | | | | | | | | | | | | | | | Change in cash from discontinued operations | | | 43 | | | | (25 | ) | | | 2 | | | | — | | | | 43 | | | | (25 | ) | Effect of exchange rate changes on cash and cash equivalents | | | (1 | ) | | | 4 | | | | 4 | | | | 1 | | | | (1 | ) | | | 4 | | | | | | | | | | | | | | | | | Net Increase in Cash and Cash Equivalents | | | 362 | | | | 355 | | | | 291 | | | | 810 | | | | 362 | | | | 355 | | Cash and Cash Equivalents at Beginning of Period | | | 1,132 | | | | 777 | | | | 486 | | | | 1,494 | | | | 1,132 | | | | 777 | | | | | | | | | | | | | | | | | Cash and Cash Equivalents at End of Period | | $ | 1,494 | | | $ | 1,132 | | | $ | 777 | | | $ | 2,304 | | | $ | 1,494 | | | $ | 1,132 | | | | | | | | | | | | | | | | |
See notes to Consolidated Financial Statements.
141145
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | | Note 1 — | Nature of Business |
General NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the US.U.S., as well a major retail electricity franchise in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the USU.S. and select international markets.markets, and supply of electricity and energy services to retail electricity customers in the Texas market. As of December 31, 2008,2009, NRG had a total global generation portfolio of 189187 active operating fossil fuel and nuclear generation units, at 4844 power generation plants, with an aggregate generation capacity of approximately 24,00524,115 MW, and approximately 550400 MW under construction which includes partners’partner interests of 275200 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in twooperating renewable facilities with an aggregate generation capacity of 365 MW, consisting of three wind farms representing an aggregate generation capacity of 270345 MW which(which includes partner interestsinterest of 75 MW) and a solar facility with an aggregate generation capacity of 20 MW. Within the US,U.S., NRG has one of the largestlarge and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,92523,110 MW of fossil fuel and nuclear generation capacity in 177179 active generating units at 43 plants and ownership interests in two wind farms representing 195 MW of wind generation capacity. These42 plants. The Company’s power generation facilities are primarily locatedmost heavily concentrated in Texas (approximately 11,01011,340 MW, including the 195345 MW from the twothree wind farms), the Northeast (approximately 7,0207,015 MW), South Central (approximately 2,8452,855 MW), and West (approximately 2,130 MW)2,150 MW, including 20 MW from a solar farm) regions of the US, andU.S., with approximately 115 MW of additional generation capacity from the Company’s thermal assets. In addition, through certain foreign subsidiaries, NRG has investments in power generation projects located in Australia and Germany with approximately 1,005 MW of generation capacity. On May 1, 2009, NRG acquired Reliant Energy, which is the second largest electricity provider to Mass customers in Texas. Reliant Energy is also the largest electricity and energy services provider, based on load, to C&I customers in Texas. Based on metered locations, as of December 31, 2009, Reliant Energy had approximately 1.5 million Mass customers and approximately 0.1 million C&I customers. Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service. NRG was incorporated as a Delaware corporation on May 29, 1992. NRG’s common stock is listed on the New York Stock Exchange under the symbol “NRG”. The Company’s headquarters and principal executive offices are located at 211 Carnegie Center, Princeton, New Jersey 08540. NRG’s telephone number is(609) 524-4500. The address of the Company’s website iswww.nrgenergy.com. NRG’s recent annual reports, quarterly reports, current reports, and other periodic filings are available free of charge through the Company’s website. | | Note 2 — | Summary of Significant Accounting Policies |
Principles of Consolidation and Basis of Presentation The consolidated financial statements include NRG’s accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist in entities, such as a variable interest entity, through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of FASB Interpretation, or FIN, No. 46R,ASC 810,Consolidation of Variable Interest Entities,Consolidations,or FIN 46R,ASC 810, to consolidate variable interest entities, or VIEs, for which the Company is the primary beneficiary. FIN 46RASC 810 requires a variable interest holder to consolidate a VIE if that party will absorb a majority of the expected losses of the VIE, receive the majority of the 146
expected residual returns of the VIE, or both. This party is considered the primary beneficiary. Conversely, NRG will not consolidate a VIE in which it has a majority ownership interest when the Company is not considered the primary beneficiary. In determining the primary beneficiary, NRG thoroughly evaluates the VIE’s design, capital structure, and relationships among variable interest holders. If a primary beneficiary cannot be determined by a qualitative analysis, a quantitative analysis allocating the expected cash flows among the variable interest holders is used in the determination. As discussed in Note 14,16,Investments Accounted for by the Equity Method, NRG has investments in partnerships, joint ventures and projects, one of which is a VIE for which the Company is not the primary beneficiary. Accounting policies for all of NRG’s operations are in accordance with accounting principles generally accepted in the US.U.S. Upon its emergence from bankruptcy on December 5, 2003, the Company qualified for and
142
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
adopted fresh start reporting, or Fresh Start, under StatementASC 852,Reorganizations, or ASC 852. These financial statements and notes reflect the Company’s evaluation of Position90-7,Financial Reporting by Entities in Reorganization underevents occurring subsequent to the Bankruptcy Code.balance sheet date through February 23, 2010, the date the financial statements were issued. Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase. Funds Deposited by Counterparties Funds deposited by counterparties consist of cash held by NRG as a result of collateral posting obligations from hedgethe Company’s counterparties due to positions in support of energy risk management activities, and at December 31, 2008, it isNRG’s hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company’s intention, to limitare not available for the usepayment of these funds.NRG’s general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. No such restrictions were imposed bySince collateral requirements fluctuate daily and the Company in prior periods, andcannot predict if any collateral will be held for more than twelve months, the amount offunds deposited by counterparties are classified as a current asset on the Company’s balance sheet, with an offsetting liability for this cash collateral held at December 31, 2007 was immaterial.received within current liabilities. Changes in funds deposited by counterparties are closely associated with the Company’s operating activities, and are classified as an operating activity in the Company’s consolidated statements of cash flows. Restricted Cash Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company’s projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements. Trade Receivables and Allowance for Doubtful Accounts Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its Reliant Energy business, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. Reliant Energy writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible. Inventory Inventory is valued at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost will be recovered with a normal profit in the ordinary course of business, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at a weighted average cost, since the Company expects to recover these costs in the ordinary course of business. The Company removes these 147
inventories when they are used for repairs, maintenance or capital projects. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows. Property, Plant and Equipment Property, plant and equipment are stated at cost; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. NRG also classifies nuclear fuel related to the Company’s 44% ownership interest in STP as part of the Company’s property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation other than nuclear fuel is computed using the straight-line method, while nuclear fuel is amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in other income/(expense)cost of operations in the consolidated statements of operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Asset Impairments Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with SFAS 144.ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques. Investments accounted for by the equity method are reviewed for impairment in accordance with APB 18,ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value. Discontinued Operations Long-lived assets or disposal groups are classified as discontinued operations when all of the required criteria specified in SFAS 144ASC 360 are met. These criteria include, among others, existence of a qualified plan to dispose of an asset or disposal group, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management. In addition, upon completion of the transaction, the operations and cash flows of the disposal group must be eliminated from ongoing operations of the Company, and the disposal group must not have any significant continuing involvement with the Company. Discontinued operations are reported at the lower of the asset’s carrying amount or fair value less cost to sell. Project Development Costs and Capitalized Interest Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. Interest incurred on funds borrowed to finance capital projects is capitalized, if material, until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2009, 2008, and 2007, and 2006 was $37 million, $45 million, $11 million and $5$11 million, respectively. When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project’s related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. 148
Debt Issuance Costs Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. Intangible Assets Intangible assets represent contractual rights held by NRG. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, trade names, emission allowances, power and fuel contracts when specific rights and contracts are acquired. In addition, NRG also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on a contractedexpected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. NRG had no intangible assets with indefinite lives recorded as of December 31, 2008.2009. Emission allowancesheld-for-sale, which are included in other non-current assets on the Company’s consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360. Goodwill In accordance with SFAS 142,ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, typically during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable. Goodwill impairment is determined using a two step process: | | | | Step one — | Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two. | | | Step two — | Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds fair value, an impairment charge is recognized for the sum of such excess. |
Income Taxes NRG accounts for income taxes using the liability method in accordance with SFAS 109,ASC 740,Income Taxes, or ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences. NRG has two categories of income tax expense or benefit — current and deferred, as follows: | | | | • | Current income tax expense or benefit consists solely of regular tax less applicable tax credits, and | | | • | Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income. |
NRG reports some of the Company’s revenues and expenses differently for financial statement purposes than for income tax return purposes resulting in temporary and permanent differences between the Company’s financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company’s consolidated balance sheets. NRG measures the Company’s deferred income tax assets and deferred income tax liabilities using income tax rates that are 149
currently in effect. A valuation allowance is recorded to reduce the Company’s net deferred tax assets to an amount that is more-likely-than-not to be realized. In January 2007, theThe Company adopted FIN No. 48,Accountingaccounts for Uncertaintyuncertain tax positions in Income Taxes — an interpretation of FASB Statement No. 109, or FIN 48,accordance with ASC 740, which applies to all tax positions related to income taxes subject to SFAS 109.taxes. Under FIN 48,ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Revenue Recognition NRG is primarily a power generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which the Company’s ownership interest is 50% or less, which are accounted for under the equity method of accounting. NRG also produces thermal energy for sale to customers, principally through steam and chilled water facilities.
Energy — Both physical and financial transactions are entered into to optimize the financial performance of NRG’s generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company’s consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with Emerging Issues Task Force,ASC 815,Derivatives and Hedging, or EITF, IssueNo. 02-3,Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,orEITF 02-3.ASC 815. Capacity —Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Sale of Emission Allowances —NRG records the Company’s bank of emission allowances as part of the Company’s intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company’s emission bank to intangible assetsheld-for-sale as part of the Company’s asset optimization strategy. for trading purposes. NRG records the sale of emission allowances on a net basis within other revenue in the Company’s consolidated statements of operations. Contract Amortization —LiabilitiesAssets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market is amortized as an increase to revenue over the term of each underlying contract based on actual generationand/or contracted volumes. Retail revenues —Gross revenues for energy sales and services to Mass customers and to C&I customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $251 million for the eight-month period ended December 31, 2009. These revenues represent a sale of excess supply to third parties in the market. As of December 31, 2009, Reliant Energy recorded unbilled revenues of $308 million for energy sales and services. Accrued unbilled revenues are based on Reliant Energy’s estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. Cost of Energy for Reliant Energy Reliant Energy records cost of energy for electricity sales and services to retail customers based on estimated supply volumes for the applicable reporting period. A portion of its cost of energy ($69 million as of December 31, 2009) consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, Reliant Energy considers the effects of historical customer volumes, weather factors and usage by customer class. Reliant Energy estimates its transmission and distribution delivery fees using the same method that it uses for electricity sales and services to retail customers. In addition, Reliant Energy estimates ERCOT ISO fees based on historical trends, estimates supply volumes and initial ERCOT 150
ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period. Derivative Financial Instruments NRG accounts for derivative financial instruments under SFAS 133. SFAS 133ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges are either: | | | | • | Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or | | | • | Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings. |
NRG’s primary derivative instruments are power sales contracts, fuels purchase contracts, other energy related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, NRG assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Hedge accounting will also be discontinued on contracts related to commodity price risk previously accounted for as cash flow hedges when it is probable that delivery will not be made against these contracts. In this case, the gain or loss previously deferred in OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative in OCI will be frozen until the underlying hedged item is delivered.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under SFAS 133,ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings. NRG’s trading activities include contracts entered into that profit from market price changes as opposed to hedging an exposure, and are subject to limits in accordance with the Company’s risk management policy.Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. These trading activities are a complement to NRG’s energy marketing portfolio. Foreign Currency Translation and Transaction Gains and Losses The local currencies are generally the functional currency of NRG’s foreign operations. Foreign currency denominated assets and liabilities are translated atend-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the determination of the Company’s statements of operations for the period, but are accumulated and reported as a separate component of stockholders’ equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company’s statements of operations. For the years ended December 31, 2009, 2008, 2007 and 2006,2007, amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company’s cumulative translation adjustment balances as of December 31, 2009, 2008, and 2007 were $21 million, $58 million and $59 million, respectively. Concentrations of Credit Risk Financial instruments which potentially subject NRG to concentrations of credit risk consist primarily of cash, trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Cash and cash equivalents and funds deposited by counterparties are predominantly held in money market funds invested in 151
treasury securities, or treasury repurchase agreements.agreements or government agency debt. Trust funds are held in accounts managed by experienced investment advisors. AccountsCertain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, NRG believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of the Company’s customer base. See Note 5,Accounting for DerivativeFair Value of Financial Instruments, and Hedging Activities,for a further discussion of derivative concentrations. Fair Value of Financial Instruments The carrying amount of cash and cash equivalents, funds deposited by counterparties, trust funds, receivables, accounts payables, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. The carrying amounts of long-term receivables usually approximate fair value, as the effective rates for these instruments are comparable to market rates at year-end, including current portions. Any differences are disclosed in Note 4,5,Fair Value of Financial Instruments.The fair value of long-term debt is based on quoted market prices for those instruments that are publicly traded, or estimated based on the income approach valuation technique for non-publicly traded debt. For the years ended December 31, 2009, 2008, and 2007, the Company recorded an unrealized gain of $3 million, and impairment charges of $23 million and $11 million respectively, related to an investment in commercial paperpaper. As of $23 million and $11 million, respectively; reducing itsDecember 31, 2009 the net carrying value to approximately $7of the investment was $9 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Asset Retirement Obligations NRG accounts for its asset retirement obligations, or AROs, in accordance with SFAS No. 143,ASC410-20, AssetAccounting for Asset Retirement Obligations,, or SFAS 143, and FIN No. 47,Accounting for Conditional Asset Retirement Obligations, or FIN 47.ASC410-20. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 and FIN 47ASC410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timingand/or method of settlement may be conditional on a future event. SFAS 143 and FIN 47 requireASC410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made. Upon initial recognition of a liability for an ARO, NRG capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. NRG’s AROs are primarily related to the future dismantlement of equipment on leased property and environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities. In addition, NRG has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations. See Note 6,13,Nuclear Decommissioning Trust Fund,Asset Retirement Obligations,for a further discussion of NRG’s nuclear decommissioning obligations.
The following table represents the balance of ARO obligations as of December 31, 2008 and 2007, along with the additions, reductions and accretion related to the Company’s ARO obligations for the year ended December 31, 2008:
| | | | | | | Total | | | | (In millions) | | | Balance as of December 31, 2007 | | $ | 409 | | Additions | | | 1 | | Revisions in estimated cashflows | | | (41 | ) | Accretion — Expense | | | 7 | | Accretion — Other | | | 17 | | | | | | | Balance as of December 31, 2008 | | $ | 393 | | | | | | |
AROs. Pensions NRG offers pension benefits through either a defined benefit pension plan or a cash balance plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. Effective December 31, 2006, NRG accounts for pension and other postretirement benefits in accordance with SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R), or SFAS 158.ASC 715. NRG recognizes the funded status of the Company’s defined benefit plans in the statement of financial position and records an offset to other comprehensive income. In addition, NRG also recognizes on an after taxafter-tax basis, as a component of other comprehensive income, gains and losses as well as all prior service costs that have not been included as part of the Company’s net periodic benefit cost. The determination of NRG’s obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. NRG’s actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company. As of December 31, 2008, NRG measuredmeasures the fair value of its pension assets in accordance with SFAS 157,ASC 820,Fair Value Measurements and Disclosures., or ASC 820.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Stock-Based Compensation NRG accounts for its stock-based compensation in accordance with SFAS No. 123 (Revised 2004),Share-Based Payment, or SFAS 123R.ASC 718. The fair value of the Company’s non-qualified stock options and performance units are estimated on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses the Company’s common stock price on the date of grant as the fair value of the Company’s restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of NRG’s historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award. Investments Accounted for by the Equity Method NRG has investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NRG from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of international projects, are reflected as equity in earnings of unconsolidated affiliates. On January 1, 2006, NRG adopted EITF IssueNo. 04-6,Accounting for Stripping Costs Incurred during Production in the Mining Industry, orEITF 04-6.EITF 04-6 provides that costs incurred to remove overburden and waste material to access coal seams, or stripping costs; during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. MIBRAG, in which NRG holds a 50% equity investment, has mining operations which were negatively affected by this pronouncement. The adoption ofEITF 04-6 did not have a material impact on NRG’s consolidated results of operations, but did have a material impact on NRG’s consolidated financial position. Upon adoption ofEITF 04-6 on January 1, 2006, NRG’s investment in MIBRAG was reduced by 50% of the above mentioned asset, or approximately $93 million after-tax, with an offsetting charge to retained earnings.
Issuance of Subsidiary’s Stock The Company accounts for issuance of its subsidiaries’ stock in accordance with SEC Staff Accounting Bulletin Topic 5H,Accounting For Sales Of Stock By A Subsidiary, or Topic 5H. Topic 5H precludes recognizing any gain on issuanceASC 810, which requires an entity to account for a decrease in its ownership interest of a subsidiary’s stock into earnings whensubsidiary that does not result in a change of control of the subsidiary is a development stage entity.as an equity transaction. In March 2008, NRG formed NINA, an NRG development stage subsidiary focused on developing, financing, and investing in nuclear projects in North America. TANE has partnered with NRG on the NINA venture, receiving a 12% equity ownership in NINA in exchange for $300 million to be invested in NINA in six annual installments of $50 million, the last three of which are subject to certain restrictions. NRG continues to control NINA through its voting interest. Any change in NRG’s proportionate share of NINA’s equity resulting from cash invested by TANE directly into NINA is accounted for by the Company as an equity transaction in consolidation, and not a gain on sale, for as long as NINA remains a development stage entity. there is no change in control of NINA. Accordingly, uponreceipt of TANE’s initial $50 million installment contributioncontributions results in April 2008, $44 million, or 88%, was recorded asincreases in additional paid in capital while the remaining $6 million, or 12%, was recorded as minorityand noncontrolling interest on the Company’s consolidated balance sheet. Gross Receipts and Sales Taxes In connection with its Reliant Energy business, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the eight-month period ended December 31, 2009, Reliant Energy’s revenues and cost of operations included gross receipts taxes of $55 million. Additionally, Reliant Energy records sales taxes collected from its taxable customers and remitted to the various governmental entities on a net basis, thus, there is no impact on the Company’s consolidated statement of operations. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the USU.S. requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial
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statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. In recording transactions and balances resulting from business operations, NRG uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, and the valuation of energy commodity contracts, environmental liabilities, and legal costs incurred in connection with recorded loss contingencies, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. 153
Reclassifications Certain prior-year amounts have been reclassified for comparative purposes. Recent Accounting Developments The Company partially adoptedSFAS 168 —In June 2009, the Financial Accounting Standards Board, or FASB, issued SFAS No. 157,168,Fair Value MeasurementsThe FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, or SFAS 157, on January168. Effective July 1, 2008, delaying application for non-financial assets and non-financial liabilities as permitted. This statement defines fair value,2009, this guidance establishes a framework for measuring fair value, and expands disclosures about fair value measurements. In February 2008, the FASB issued FASB Staff Position,Accounting Standards Codification, or FSP,No. FAS 157-1,ApplicationASC, as the source of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13, which amends SFAS 157 to exclude SFAS Statement No. 13,Accounting for Leases, or SFAS 13, and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. In February 2008,authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. In addition, SFAS 168 also issued FSPNo. FAS 157-2,Effective Datespecifies that rules and interpretive releases of FASB Statement No. 157, which permitted delayed applicationthe SEC under authority of this statementfederal securities laws are also sources of authoritative U.S. GAAP for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair valueSEC registrants. All guidance contained in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The partial adoptionASC carries an equal level of SFAS 157 on January 1, 2008 did not have a material impact on the Company’s consolidated financial position, statement of operations, and cash flows. The Company adopted the remaining portion of SFAS 157 for non-financial assets and non-financial liabilities on January 1, 2009, with no impact on the Company’s consolidated financial position, statement of operations, and cash flows.
authority. The Company adopted SFAS No. 159,The Fair Value Option168 for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115,the quarterly reporting period ending September 30, 2009. SFAS 168 has been incorporated into the ASC as ASC-105,Generally Accepted Accounting Principles,or SFAS 159, on January 1, 2008. This statement provides entities with an option to measure and report selected financial assets and liabilities at fair value. The Company does not intend to apply this standard to any of its eligible assets or liabilities; therefore, there was no impact on NRG’s consolidated financial position, results of operations, or cash flows.ASC 105. Certain U.S. GAAP standards and interpretations were adopted by the Company in 2009 prior to the July 1, 2009, effective date of the ASC, and were subsequently incorporated into one or more ASC topics. Further, certain U.S. GAAP standards were ratified by the FASB in 2009 prior to July 1, 2009, but are not yet effective and have therefore not yet been incorporated into the ASC. This report retains the original title of these standards and interpretations, and references the ASC topic or topics in which they have been, or are expected to be, incorporated. SFAS 141R —The Company adopted FSPFIN 39-1,Amendment of FASB Interpretation No. 39, or FSPFIN 39-1, which amends FIN 39,Offsetting of Amounts Related to Certain Contracts, on January 1, 2008. FSPFIN 39-1 impacts entities that enter into master netting arrangements as part of their derivative transactions. Under the guidance in this FSP, entities may choose to offset derivative positions in the financial statements against the fair value of amounts recognized as cash collateral paid or received under those arrangements. The Company chose not to offset positions as defined in this FSP; therefore there was no impact on NRG’s consolidated financial position, results of operations, or cash flows. In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations, or SFAS 141R. This statement applies141R, on January 1, 2009. The provisions of SFAS 141R are applied prospectively to all business combinations for which the acquisition date is on oroccurs after the beginning of an entity’s first annual reporting period beginning on or after December 15, 2008.January 1, 2009. The statement establishes principles and requires an acquirer to recognize and measure in its financial statements the identifiable
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
assets acquired, the liabilities assumed, and any minoritynoncontrolling interest in the acquiree at fair value.value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are required to be expensed as incurred. On May 1, 2009, NRG adoptedacquired all of the Texas electric retail business operations, or Reliant Energy, of Reliant Energy, Inc., now known as RRI. As discussed in Note 3,Business Acquisitions, to the Consolidated Financial Statements, the Company has applied the provisions of SFAS 141R onto the Reliant Energy acquisition, as well as all other business acquisitions completed in 2009. As discussed further in Note 19,Income Taxes, any reductions after January 1, 2009, with no immediate impact on the Company’s results of operations, financial position and cash flows. However, any future reductions to existing net deferred tax assets or valuation allowances andor changes to uncertain tax benefits, as they relate to Fresh Start or previously completed acquisitions, occurring after January 1, 2009 will be recorded to income tax expense rather than APICadditional paid-in capital or goodwill, respectively.goodwill. SFAS 141R has been incorporated into ASC-805,Business Combinations, or ASC 805. FSPFAS 141R-1 —In December 2007,April 2009, the FASB issued FSP No. FAS 141(R)-1,Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, or FSPFAS 141R-1, which the Company adopted effective January 1, 2009. This FSP amends and clarifies SFAS 141R,to address application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The provisions of FSPFAS 141R-1 are applied prospectively to assets or liabilities arising from contingencies in business combinations for which the acquisition date occurs after January 1, 2009. Accordingly, the Company has applied the provisions of FSPFAS 141R-1 to the Reliant Energy acquisition as well as all other business acquisitions completed in 2009. The provisions of FSPFAS 141R-1 have been incorporated into ASC 805. SFAS 160 —The Company adopted SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements — anStatements-an amendment of ARB No. 51, Consolidated Financial Statements, or SFAS 160. This Statement amends ARB No. 51 to establish160, on January 1, 2009. SFAS 160 establishes accounting and reporting standards for the minority interest in a subsidiary and for the deconsolidation of a subsidiary. It also amends certain of ARB No. 51’s consolidation procedures for consistency with the requirements of SFAS 141R. This Statement shall be effective andstatement is applied prospectively for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008,from the date of adoption, except for the presentation and disclosure requirements, which shall be applied retrospectively. NRG adoptedAccordingly, the Company has conformed its financial statement presentation and disclosures to the requirements of SFAS 160. SFAS 160 on January 1, 2009, with no material impact on the Company’s consolidated financial position, statement of operations, and cash flows.has been incorporated into ASC-810,Consolidation, or ASC 810. 154
ASUNo. 2010-02 -In March 2008,January 2010 the FASB issued ASUNo. 2010-02,Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary—a Scope Clarification,or ASU2010-02. ASU2010-02 amends ASC 810,Consolidationto resolve a conflict between the consolidation guidance in the Accounting Standards Codification and other sections of U.S. GAAP when there is a decrease in ownership of a subsidiary. Entities are required to apply the amendments in ASU2010-02 retrospectively for the first reporting period in which they applied SFAS No. 161,Disclosures About Derivative Instruments and Hedging Activities, or SFAS 161. SFAS 161 requires entities to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. SFAS 161160. Although ASU2010-02 is effective for financial statements issued for fiscal yearsthe Company beginning in the fourth quarter of 2009, no decrease in ownership transactions resulting in a change in control within the scope of ASU2010-02 and interim periods beginning after November 15, 2008, with early application encouraged. NRG adopted SFAS 161 on January 1,related guidance had occurred as of December 31, 2009, withtherefore there was no impact on the Company’s results of operations, financial position, or cash flows. In April 2008, the FASB issued FSPNo. FAS 142-3,Determination of the Useful Life of Intangible Assets,or FSPFAS 142-3. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. FSPAPBFAS 142-314-1 — is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years, with early adoption prohibited. NRGThe Company adopted FSPFAS 142-3 on January 1, 2009, with no impact on the Company’s results of operations, financial position and cash flows.
In May 2008, the FASB issued FSP No. APB14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),or FSP APB14-1.14-1, Thison January 1, 2009, applying it retrospectively to all periods presented. FSP APB14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) do not fall within the scope of paragraph 12 of Accounting Principles Board Opinion No. 14,Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants,and specifies that issuers of such instruments should separately account for the liability component and the equity componentscomponent represented by the embedded conversion option in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Upon settlement, the entity shall allocate consideration transferred and transaction costs incurred to the extinguishment of the liability component and the reacquisition of the equity component. The provisions of FSP APB14-1 does not applyhave been incorporated into ASC-470,Debt, or ASC 470, and ASC-825,Financial Instruments, or ASC 825.
During the third quarter 2006, NRG’s unrestricted wholly-owned subsidiaries CSF I and CSF II issued notes and preferred interests, or CSF Debt, which included embedded derivatives, or CSF CAGRs, requiring NRG to embedded conversion options that must be separatelypay to CS at maturity, either in cash or stock at NRG’s option, the excess of NRG’s then current stock price over a threshold price. The CSF Debt and CSF CAGRs are accounted for as derivatives under SFAS 133.the guidance in ASC 470. Upon adoption of FSP APB14-1, is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years and isthe fair value of the CSF CAGRs at the date of issuance was determined to be applied retrospectively. NRG adopted$32 million and has been recorded as a debt discount to the CSF Debt, with a corresponding credit to Additional Paid-in Capital. This debt discount will be amortized over the terms of the underlying CSF Debt. The cumulative effect of the change in accounting principle for periods prior to December 31, 2006, was recorded as a $28 million decrease to Long-Term Debt, a $32 million increase to Additional Paid-In Capital, and a $4 million decrease to Retained Earnings on the Condensed Consolidated Balance Sheet as of December 31, 2006. In addition, in August 2008 the Company paid $45 million to CS for the benefit of CSF I to early settle the CSF CAGR in the Company’s CSF I notes and preferred interests, which was reclassified from interest expense to Additional Paid-In Capital upon the adoption of FSP APB14-1. The following table summarizes the effect of the adoption of FSP APB14-1 on income and per-share amounts for all periods presented: | | | | | | | | | | | | | | | | | | | For the Year Ended
| | | December 31, | | | 2009 | | 2008 | | 2007 | | | | | (In millions, except per share amounts) | | Increase/(decrease): | | | | | | | | | | | | | | | | | Interest Expense | | $ | 6 | | | $ | (37 | ) | | $ | 13 | | | | | | Income From Continuing Operations | | | (6 | ) | | | 37 | | | | (13 | ) | | | | | Net Income attributable to NRG Energy, Inc. | | | (6 | ) | | | 37 | | | | (13 | ) | | | | | Basic Earnings Per Share | | $ | (0.03 | ) | | $ | 0.16 | | | $ | (0.05 | ) | | | | | Diluted Earnings Per Share | | $ | (0.02 | ) | | $ | 0.14 | | | $ | (0.05 | ) | | | | |
FSPFAS 157-4 —In April 2009, the FASB issued FSPNo. FAS 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,or FSPFAS 157-4. FSPFAS 157-4 provides additional guidance for estimating fair value in accordance with ASC-820,Fair Value Measurements and Disclosure, or ASC 820, when the volume and level of activity for the asset or liability have significantly decreased, includes guidance on identifying circumstances that indicate a transaction is not orderly, and requires disclosures about inputs and valuation techniques used to measure fair value. This FSP applies to all assets and liabilities within the scope of accounting pronouncements that require or permit fair value measurements. FSPFAS 157-4 is effective for interim and annual reporting periods ending after 155
June 15, 2009, and is applied prospectively. The Company’s adoption of FSPFAS 157-4 beginning with the interim reporting period ended June 30, 2009, did not have a material impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSPFAS 157-4 have been incorporated into ASC 820. FSPFAS 107-1 and APB28-1 —In April 2009, the FASB issued FSPNo. FAS 107-1 and APB28-1,Interim Disclosures about Fair Value of Financial Instruments,orFSP 107-1 and APB28-1. This FSP requires disclosures about fair value of financial instruments for interim and annual reporting periods of publicly traded companies ending after the FSP’s effective date of June 15, 2009. The Company’s adoption of FSPFAS 107-1 and APB28-1 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSPFAS 107-1 and APB28-1 have been incorporated in ASC-270,Interim Reporting, or ASC 270, and ASC-825,Financial Instruments,or ASC 825. FSPFAS 115-2 andFAS 124-2 —In April 2009, the FASB issued FSPNo. FAS 115-2 andFAS 124-2,Recognition and Presentation ofOther-Than-Temporary Impairments,or FSPFAS 115-2 andFAS 124-2. This FSP amends theother-than-temporary impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure ofother-than-temporary impairments on debt and equity securities in the financial statements. This FSP does not amend existing recognition and measurement guidance related toother-than-temporary impairments of equity securities. FSPFAS 115-2 andFAS 124-2 are effective for interim and annual reporting periods ending after June 15, 2009, and disclosure requirements apply only to periods ending after the FSP’s effective date. The Company’s adoption of FSPFAS 115-2 andFAS 124-2 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSPFAS 115-2 andFAS 124-2 have been incorporated in ASC-320,Investments — Debt and Equity Securities, or ASC 320. SFAS 165 —In May 2009, the FASB issued SFAS No. 165,Subsequent Events, or SFAS 165. SFAS 165 incorporates the accounting and disclosure requirements related to subsequent events found in auditing standards into U.S. GAAP, effectively making management directly responsible for subsequent events accounting and disclosures. SFAS 165 also requires disclosure of the date through which subsequent events have been evaluated. SFAS 165 is effective for interim and annual reporting periods ending after June 15, 2009, and shall be applied prospectively. The Company’s adoption of SFAS 165 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. SFAS 165 has been incorporated in ASC-855,Subsequent Events, or ASC 855. SFAS 167/ASUNo. 2009-17 —In June 2009, the FASB issued SFAS No. 167,Amendments to FASB Interpretation No. 46(R), or SFAS 167. This guidance amends ASC 810 by altering how a company determines when an entity that is insufficiently capitalized or not controlled through its voting interests should be consolidated. The previous ASC 810 guidance required a quantitative analysis of the economic risk/rewards of a VIE to determine the primary beneficiary. FAS 167 now specifies that a qualitative analysis be performed, requiring the primary beneficiary to have both the power to direct the activities of a VIE that most significantly impact the entities’ economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. In December 2009 the FASB issued ASUNo. 2009-17, Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities, or ASU2009-17. ASU2009-17 formally incorporates the provisions of SFAS 167 into ASC 810 and is effective for NRG as of January 1, 2010. The Company’s adoption of ASU2009-17 on January 1, 2010 did not have an impact on its results of operations, financial position, or cash flows. ASU2009-15/EITF 09-1 —In July 2009, the FASB ratified EITF IssueNo. 09-1,Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing,orEITF 09-1. This Issue applies to equity-classified share lending arrangements on an entity’s own shares, when executed in contemplation of a convertible debt offering or other financing.EITF 09-1 addresses how to account for the share-lending arrangement and the effect, if any, that the loaned shares have onearnings-per-share calculations. The share lending arrangement is required to be measured at fair value and recognized as an issuance cost associated with nothe convertible debt offering or other financing.Earnings-per-share calculations would not be affected by the loaned shares unless the share borrower defaults on the arrangement and does not return the shares. If counterparty default is probable, the share lender is required to recognize an expense equal to the then fair value of the unreturned 156
shares, net of the fair value of probable recoveries. The Company will applyEITF 09-1 for share lending agreements entered into after June 15, 2009, and will applyEITF 09-1 on a retrospective basis for arrangements outstanding as of January 1, 2010. This statement did not have a material impact on the Company’s results of operations, financial position and cash flows. In October 2009, the FASB issued Accounting Standards Update, or ASUNo. 2009-15,Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or ASU2009-15, which formally incorporated the provisions ofEITF 09-1 into ASC 470. ASU2009-05 —In August 2009, the FASB issued ASUNo. 2009-05,Fair Value Measurement and Disclosures: Measuring Liabilities at Fair Value, or ASU2009-5. This ASU, which amends ASC 820 and ASC 825, provides clarification on measuring liabilities at fair value when a quoted price in an active market is not available. The Company’s adoption of ASU2009-5 beginning with the interim period ended September 30, 2009, did not have an impact on the Company’s results of operations, financial position or cash flows. ASU2010-06 —In June 2008,January 2010, the EITFFASB issued ASUNo. 2010-06,Fair Value Measurement and Disclosures: Improving Disclosures about Fair Value Measurements, or ASU2010-6, intending to improve disclosures about fair value measurements. The guidance requires entities to disclose significant transfers in and out of fair value hierarchy levels and the reasons for the transfers and to present information about purchases, sales, issuances and settlements separately in the reconciliation of fair value measurements using significant unobservable inputs (Level 3). Additionally, the guidance clarifies that a reporting entity should provide fair value measurements for each class of assets and liabilities and disclose the inputs and valuation techniques used for fair value measurements using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). This guidance is effective for interim and annual periods beginning after December 15, 2009 except for the disclosures about purchases, sales, issuances and settlements in the Level 3 reconciliation, which will be effective for interim and annual periods beginning after December 15, 2010. As this guidance provides only disclosure requirements, the adoption of this standard will not impact the Company’s results of operations, cash flows or financial position. Other —The following accounting standards were adopted on January 1, 2009, with no impact on the Company’s results of operations, financial position, or cash flows: • FSPNo. FAS 142-3,Determination of the Useful Life of Intangible Assets,which has been incorporated in ASC-275,Risks and Uncertainties,or ASC 275, and ASC-350,Intangibles — Goodwill and Other, or ASC 350. • FSPNo. FAS 157-2,Effective Date of FASB Statement No. 157, which has been incorporated in ASC 820. • SFAS No. 161,Disclosures About Derivative Instruments and Hedging Activities,which has been incorporated in ASC-815,Derivatives and Hedging,or ASC 815. • FSP No. FAS 132(R)-1,Employers’ Disclosures about Postretirement Benefit Plan Assets, which has been incorporated in ASC-715,Compensation-Retirement Benefits,or ASC 715. • EITFNo. 07-5,Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock,which has been incorporated in ASC 718,Compensation-Equity Compensation,orEITF 07-5.EITF 07-5 clarifies that contingent ASC 718, and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables.EITF 07-5 is effective for financial statements issued for fiscal years beginning after December 15,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2008, and interim periods within those fiscal years. NRG adopted• EITF 07-5 on January 1, 2009, with no impact on the Company’s results of operations, financial position, or cash flows.
In September 2008, the FASB issued FSPNo. FAS 133-1 andFIN 45-4,Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and Financial Interpretation Number 45; and Clarification of the Effective Date of FASB Statement No. 161, or FSPFAS 133-1 andFIN 45-4. This FSP amends FAS 133, and FIN No. 45Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,or FIN 45, to require additional disclosures about credit derivatives, credit derivatives embedded in a hybrid instrument, and the current status of the payment or performance risk of a guarantee. FSPFAS 133-1 andFIN 45-4 is effective for the financial statements of reporting periods (annual or interim) ending after November 15, 2008. NRG currently has no credit derivative contracts, so the amendments in this FSP related to FAS 133 will not impact NRG. The clarification to SFAS 161 is also not applicable to NRG, as it only affects non-calendar year filers. NRG adopted the provisions of this FSP related to FIN 45 on January 1, 2009, with no impact on the Company’s results of operations, financial position, or cash flows.
In September 2008, the EITF issuedEITF 08-5,Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement,orEITF 08-5.EITF 08-5 requires issuers of liability instruments with third-party credit enhancements to exclude the effect of the credit enhancement when measuring the liability’s fair value. The effect of initially applying the requirements is includedwhich has been incorporated in the change in the instrument’s fair value in the period of adoption. Entities are required to disclose the valuation technique used to measure the liabilities and to discuss any changes in the valuation techniques used to measure those liabilities in earlier periods. Entities will also need to disclose the existence of a third-party credit enhancement on the entity’s issued debt.EITF 08-5 is effective on a prospective basis in the first reporting period beginning on or after December 15, 2008, with earlier application permitted. NRG adoptedEITF 08-5 on January 1, 2009, with no impact on the Company’s results of operations, financial position, or cash flows.ASC 820.
In October 2008, the FASB issued FSP• EITFNo. FAS 157-3,Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,or FSPFAS 157-3. This FSP clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSPFAS 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued. Revisions resulting from a change in the valuation technique or its application shall be accounted for as a change in accounting estimate under SFAS No. 154,Accounting Changes and Error Corrections,or SFAS 154. The disclosure provisions of SFAS 154 for a change in accounting estimate are not required for revisions resulting from a change in valuation technique or its application. Although effective for the year ended December 31, 2008, FSPFAS 157-3 did not have an impact on the Company’s results of operations, financial position, or cash flows.
In November 2008, the EITF issuedEITF 08-6,Equity Method Investment Accounting Considerations, orEITF 08-6.EITF 08-6 addresses questions about the potential effect of FAS 141Rwhich has been incorporated in ASC-323,Investments-Equity Method and FAS 160 on equity-method accounting under APB 18.EITF 08-6 generally continues existing practices under APB 18, including the use of a cost-accumulation approach to initial measurement of the investment. This EITF does not require the investor to perform a separate impairment test on the underlying assets of an equity method investment. However, an equity-method investor is required to recognize its proportionate share of impairment charges recognized by the investee, adjusted for basis differences, if any, between the investee’s carrying amount for the impaired assets and the cost allocated to such assets by the investor. The investor is also required to perform an overall other-than-temporary impairment test of its investment in accordance with APB 18.EITF 08-6 is effective for fiscal years beginning on Joint Ventures,or after December 15, 2008 and interim periods within those fiscal years, and shall be applied prospectively. Early application is not permitted. The Company adoptedEITF 08-6 on January 1, 2009, with no impact on the Company’s results of operations, financial position, or cash flows.
In December 2008, the FASB issued FSPNo. FAS 140-4 and FIN 46(R)-8,Disclosures by Public Entities (Enterprises) about Transfers of Financial assets and Interests in Variable Interest Entities, orFSPFAS 140-4 andASC 323.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
FIN 46R-8. This FSP amends FASB Statement No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,to require public entities to provide additional disclosures about transfers of financial assets. It also amends FIN 46R to require public enterprises, including sponsors that have a variable interest in a VIE, to provide additional disclosures about their involvement with such VIEs. FSPFAS 140-4 andFIN 46R-8 is effective immediately. NRG does not engage in transfers of financial assets within the scope of FAS 140, so the amendments in this FSP related to FAS 140 will not impact NRG. The additional disclosure requirements related to FIN 46R have been adopted by NRG and included in the December 31, 2008 financial statements, with no impact on the Company’s results of operations, financial position, or cash flows.
In December 2008, the FASB also issued FSP No. FAS 132(R)-1Employers’ Disclosures about Postretirement Benefit Plan Assets,or FSP 132R-1. This FSP amends FASB Statement No. 132 (revised 2003),Employers’ Disclosures about Pensions and Other Postretirement Benefits,to provide guidance and additional transparency on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan, including the concentrations of risk in those plans. The effective date of FSPFAS 132R-1 is for fiscal years beginning after December 15, 2009. The enhanced disclosure requirements are relevant to NRG but will not be effective until the first interim period of 2010, and will not have an impact on the Company’s results of operations, financial position, or cash flows.
| | Note 3 — | Business Acquisitions |
Acquisition of Reliant Energy General On May 1, 2009, NRG, through its wholly-owned subsidiary NRG Retail LLC, acquired Reliant Energy, which consisted of the entire Texas electric retail business operations of RRI, including the exclusive use of the trade name “Reliant” and related branding rights. Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service. Reliant Energy is the second largest electricity provider to Mass customers in Texas, with approximately 1.5 million Mass customers as of December 31, 2009. Reliant Energy is also the largest electricity and energy services provider, based on load, to C&I customers in Texas with approximately 0.1 million C&I customers, based on metered locations as of December 31, 2009. These customers include refineries, chemical plants, manufacturing facilities, hospitals, universities, government agencies, restaurants, and other facilities. With its complementary generation portfolio, the Texas region is a supplier of power to Reliant Energy, thereby creating the potential for a more stable, reliable and competitive business that benefits Texas consumers. By backing Reliant Energy’s load-serving requirements with NRG’s generation and risk management practices, the need to sell and buy power from other financial institutions and intermediaries that trade in the ERCOT market may be reduced, resulting in reduced transaction costs and credit exposures. This combination of generation and retail allows for a reduction in actual and contingent collateral, initially through offsetting transactions and over time by reducing the need to hedge the retail power supply through third parties. In addition, with Reliant Energy’s base of retail customers, NRG now has a customer interface with the scale that is important to the successful deployment of consumer facing energy technologies and services. Credit Support On May 1, 2009, NRG arranged with Merrill Lynch Commodities, Inc. and certain of its affiliates, or Merrill Lynch, the former credit provider of RRI, to provide continuing credit support to Reliant Energy after closing the acquisition. In connection with entering into a transitional credit sleeve facility, or CSRA, NRG contributed $200 million of cash to Reliant Energy. In conjunction with the CSRA, NRG Power Marketing LLC, or PML, and Reliant Energy Power Supply LLC, or REPS, wholly-owned subsidiaries of NRG, modified or novated certain transactions with counterparties to transfer PML’sin-the-money transactions to REPS and moved $522 million of cash collateral held by NRG to Merrill Lynch, thereby reducing Merrill Lynch’s actual and contingent collateral supporting Reliant Energyout-of-money positions. Through October 5, 2009, these trades with counterparties were still open, thus there was no impact on NRG’s consolidated financial statements, and NRG continued to record unrealized and realized gains/losses for these novated trades in its Texas and Northeast segments. The monthly fee for the CSRA was 5.875% on an annualized basis of the predetermined exposure. Additionally, on May 1, 2009, NRG entered into a $50 million working capital facility with Merrill Lynch in connection with the acquisition of Reliant Energy. The facility required that the Company comply with all terms of the CSRA. NRG initially drew $25 million under the facility, which accrued interest at the prime rate. The $25 million outstanding under this facility was repaid, and the facility was terminated on October 5, 2009. See further discussion below. Reliant Energy conducts its business through RERH Holdings, LLC and subsidiaries, or RERH, Reliant Energy Texas Retail, LLC, and Reliant Energy Services Texas, LLC. Through October 5, 2009, the obligations of Reliant Energy under the CSRA were secured by first liens on substantially all of the assets of RERH, and the obligations of RERH under the CSRA were non-recourse to NRG and its other non-pledgor subsidiaries. The Company executed an amendment of the existing CSRA with Merrill Lynch, or CSRA Amendment, which became effective October 5, 2009. In connection with the CSRA Amendment, the Company recorded refinancing expense of $20 million in its results of operations for the year ended December 31, 2009, primarily related to the write-off of previously deferred financing costs. The CSRA Amendment removed the first liens associated with the CSRA, and RERH subsequently became a guarantor of the Company’s obligations under its Senior Notes. See Note 29,Condensed Consolidating Financial Information, for further discussion of NRG’s guarantees under its Senior Notes. 158
In connection with the CSRA Amendment, NRG net settled certain REPS transactions with counterparties and received $165 million in net cash consideration. Merrill Lynch returned $250 million of previously posted cash collateral and released liens on $322 million of unrestricted cash held at Reliant Energy. See Note 6,Accounting for Derivative Instruments and Hedging Activities, for the accounting impact of these settlements. Pursuant to the CSRA Amendment, the Company was required to post collateral for any net liability derivatives and other static margin associated with supply for Reliant Energy. In connection with this amendment, NRG posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued letters of credit of $206 million, and received $45 million in counterparty collateral. The funds posted by the Company were sourced from a portion of the proceeds from the June 5, 2009 issuance of the 2019 Senior Notes. See Note 12,Debt and Capital Leases, for further discussion of the 2019 Senior Notes. Under the amended CSRA, the parties had agreed to settle any outstanding wholesale obligations under the CSRA Amendment by January 29, 2010. As of that date, there was one remaining wholesale counterparty, for which NRG provided Merrill Lynch with a $10 million letter of credit to protect them from any potential liability. The parties continue to work to settle all outstanding obligations, including C&I counterparties, by April 30, 2010. Acquisition method of accounting The acquisition of Reliant Energy is accounted for under the acquisition method of accounting in accordance with ASC 805. Accordingly, NRG has conducted an assessment of net assets acquired and has recognized provisional amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition are expensed as incurred. The initial accounting for the business combination is not complete because the evaluations necessary to assess the fair values of certain net assets acquired and the amount of goodwill (if any) to be recognized are still in process. The provisional amounts recognized are subject to revision until the evaluations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments will affect the final balance of goodwill. NRG paid RRI $287.5 million in cash at closing, funded from NRG’s cash on hand. NRG also made payments to RRI of $78 million as remittances of acquired net working capital. In addition, the Company expects to remit approximately $4 million of acquired net working capital to RRI by the second quarter 2010, bringing the total cash consideration to approximately $370 million. NRG also recognized a $31 million non-cash gain on the settlement of a pre-existing relationship, representing thein-the-money value to NRG of an agreement that permits Reliant Energy to call on certain NRG gas plants when necessary for Reliant Energy to meet its load obligations. NRG has recorded this gain within Operating Revenues in its consolidated statement of operations. This non-cash gain is considered a component of consideration in accordance with ASC 805, and together with cash consideration, brings total consideration to approximately $401 million. The following table summarizes the provisional values assigned to the net assets acquired, including cash acquired of $6 million, as of the acquisition date: | | | | | | | (In millions) | | Assets | | | | | Current and non-current assets | | $ | 635 | | Property, plant and equipment | | | 72 | | Intangible assets subject to amortization: | | | | | In-market customer contracts | | | 790 | | Customer relationships | | | 399 | | Trade names | | | 178 | | In-market energy supply contracts | | | 54 | | Other | | | 6 | | Derivative assets | | | 1,942 | | Deferred tax asset, net | | | 14 | | Goodwill | | | — | | | | | | | Total assets acquired | | $ | 4,090 | | | | | | |
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| | | | | | | (In millions) | | Liabilities | | | | | Current and non-current liabilities | | $ | 550 | | Derivative liabilities | | | 2,996 | | Out-of-market energy supply and customer contracts | | | 143 | | | | | | | Total liabilities assumed | | $ | 3,689 | | | | | | | Net assets acquired | | $ | 401 | | | | | | |
Current assets include accounts receivable with a preliminary fair value of $569 million and gross contractual amounts of $589 million at the time of acquisition. The Company has collected substantially all of the fair value of the contractual cash flows; any difference between fair value and the amount collected will be an adjustment to the acquired working capital payment due to RRI. The Company, through its acquisition of Reliant Energy, is subject to material contingencies relating to Excess Mitigation Credits (see Note 22,Commitments and Contingencies) and Retail Replacement Reserve (see Note 23,Regulatory Matters). Due to the number of variables and assumptions involved in assessing the possible outcome of these matters, sufficient information does not exist to reasonably estimate the fair value of these contingent liabilities. These material contingencies have been evaluated in accordance with ASC-450,Contingencies,or ASC 450, and related guidance, and no provisional amounts for these matters have been recorded at the acquisition date. In addition, NRG provided certain indemnities in connection with the acquisition. See Note 26,Guarantees,for further discussion. Measurement period adjustments The following measurement period adjustments to the provisional amounts, attributable to refinement of the underlying appraisal assumptions, were recognized during 2009 subsequent to the acquisition date: | | | | | | | Increase/(Decrease) | | | | (In millions) | | | Assets | | | | | Intangible assets subject to amortization: | | | | | In-market customer contracts | | $ | 57 | | Customer relationships | | | (82 | ) | In-market energy supply contracts | | | 17 | | Deferred tax asset, net | | | 3 | | | | | | | Total assets acquired | | | (5 | ) | | | | | | Liabilities | | | | | Out-of-market energy supply and customer contracts | | | (5 | ) | | | | | | Total liabilities assumed | | | (5 | ) | | | | | | Net assets acquired | | $ | — | | | | | | |
Fair value measurements The provisional fair values of the intangible assets/liabilities and property, plant and equipment at the acquisition date were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. Significant inputs were as follows: | | | | • | Customer contracts— The fair values of the customer contracts, representing those with Reliant Energy’s C&I customers, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on contract type, discounted utilizing a current market interest rate consistent with the overall credit quality of the portfolio. The fair values also accounted for Reliant Energy’s historical costs to acquire customers. The above/below market cash flows were estimated by comparing the expected cash flows to be generated based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected |
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| | | | | volumes. The estimated current market contract prices were derived considering current market costs, such as price of energy, transmission and distribution costs, and miscellaneous fees, plus a normal profit margin. The customer contracts are amortized to revenues, over a weighted average amortization period of five years, based on expected volumes to be delivered for the portfolio. |
| | | | • | Customer relationships— The customer relationships, reflective of Reliant Energy’s Mass customer base, were valued using a variation of the income approach. Under this approach, the Company estimated the present value of expected future cash flows resulting from the existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, software, workforce and trade names) utilized in the business, discounted at an independent power producer peer group’s weighted average cost of capital. The customer relationships are amortized to depreciation and amortization expense, over a weighted-average amortization period of eight years, based on the expected discounted future net cash flows by year. | | | • | Trade names — The trade names were valued using a “relief from royalty” method, an approach under which fair value is estimated to be the present value of royalties saved because NRG owns the intangible asset and therefore does not have to pay a royalty for its use. The trade names were valued in two parts based on Reliant Energy’s two primary customer segments — Mass customers and C&I customers. The avoided royalty revenues were discounted at an independent power producer peer group’s weighted average cost of capital. The remaining useful life of the trade names were determined by considering various factors, such as turnover and name changes in the independent power producer and utility industries, the current age of the Reliant brand, management’s intent to continue using the name at the current time, and feedback from external consultants regarding their experience with similar trade names. The trade names are amortized to depreciation and amortization expense, on a straight-line basis, over 15 years. | | | • | Energy supply contracts— The fair values of the in-market andout-of-market energy supply contracts were determined in accordance with ASC 820. These contracts are amortized over periods ranging through 2016, based on the expected delivery under the respective contracts. | | | • | Property, plant and equipment— The fair value of property, plant and equipment was valued using a cost approach, which estimates value by determining the current cost of replacing an asset with another of equivalent economic utility. The cost to replace a given asset reflects the estimated reproduction or replacement cost for the property, less an allowance for loss in value due to depreciation. |
The fair values of derivative assets and liabilities as of the acquisition date were determined in accordance with ASC 820. The breakdown of Level 1, 2 and 3 is as follows: | | | | | | | | | | | | | | | | | | | Fair Value | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | | (In millions) | | | Derivative assets | | $ | 534 | | | $ | 1,375 | | | $ | 33 | | | $ | 1,942 | | | | | | | | | | | | | | | | | | | Derivative liabilities | | $ | 534 | | | $ | 2,357 | | | $ | 105 | | | $ | 2,996 | | | | | | | | | | | | | | | | | | |
Amortization of acquired intangible assets andout-of-market contracts See Note 11,Goodwill and Other Intangibles, for the estimated remaining amortization related to acquired intangible assets andout-of-market contracts, including Customer contracts, Customer relationships, Trade names and Energy supply contracts, for 2010 — 2014. Supplemental Pro-Forma Information Since the acquisition date, Reliant Energy contributed $4.2 billion of operating revenues and $1.0 billion in net income attributable to NRG. See Note 18,Segment Reporting, for more information on the Company’s segment results. 161
The following supplemental pro-forma information represents the results of operations as if NRG and Reliant Energy had combined at the beginning of the respective reporting periods: | | | | | | | | | | | For the Year Ended
| | | December 31, | | | 2009 | | 2008 | | | (In millions, except
| | | per share amounts) | | Operating revenues | | $ | 10,799 | | | $ | 15,124 | | Net income attributable to NRG Energy, Inc. | | | 945 | | | | 419 | | Earnings per share attributable to NRG common stockholders: | | | | | | | | | Basic | | $ | 3.71 | | | $ | 1.55 | | Diluted | | $ | 3.45 | | | $ | 1.48 | |
The supplemental pro-forma information has been adjusted to include the pro-forma impact of amortization of intangible assets andout-of-market contracts, and depreciation of property, plant and equipment, based on the preliminary purchase price allocations. The pro-forma data has also been adjusted to eliminate the non-recurring transaction costs incurred by NRG. Transactions between NRG and Reliant Energy have not been eliminated. The pro-forma results are presented for illustrative purposes only and do not reflect the realization of potential cost savings, or any related integration costs. Certain cost savings may result from the acquisition; however, there can be no assurance that these cost savings will be achieved. Other Acquisitions The Company also completed the following acquisitions during the fourth quarter of 2009, for combined consideration totaling $68 million: Bluewater Wind LLC — On November 9, 2009, NRG, through its wholly-owned subsidiary NRG Bluewater Holdings LLC, acquired all the subsidiaries of Bluewater Wind LLC (such subsidiaries, together with NRG Bluewater Holdings LLC, NRG Bluewater). NRG Bluewater, a developer of off-shore wind energy, has a number of projects that are in various stages of development along the eastern seaboard and the Great Lakes region of the U.S. FSE Blythe 1, LLC — On November 20, 2009, NRG, through its wholly owned subsidiary NRG Solar LLC, acquired FSE Blythe 1, LLC, or Blythe Solar, from First Solar, Inc. On December 18, 2009, construction was completed and commercial operations began for Blythe Solar’s 20 MW utility-scale photovoltaic, or PV, solar facility located in Riverside County in southeastern California. The Blythe Solar PV field provides electricity to Southern California Edison under a20-year PPA. | | Note 4 — | Discontinued Operations Business Acquisitions and Dispositions |
Discontinued Operations NRG has classifiedclassifies material business operations and gains/(losses) recognized on sales as discontinued operations for projectsbusinesses that were sold or have met the required criteria for such classification. The financial results for the affected businesses have been accounted for as discontinued operations. SFAS 144ASC 360 requires that discontinued operations be valued on anasset-by-asset basis at the lower of carrying amount or fair value, less costs to sell. In applying the provisions of SFAS 144,ASC 360, the Company’s management considers cash flow analyses, bids, and offers related to those assets and businesses. In accordance with the provisions of SFAS 144,ASC 360, assets held by discontinued operations are not depreciated commencing with their classification as such. The assets and liabilities of the discontinued operations are reported in NRG’s balance sheets as discontinued operations.
The following table summarizes NRG’s discontinued operations for all periods presentedreflect the disposal of ITISA, reported in the Company’s consolidated financial statements:
| | | | | | | | | | | Initial Discontinued
| | | | | | | Operations
| | | Project
| | Segment | | Treatment Date | | Disposal Date | | Audrain | | Corporate | | Fourth Quarter 2005 | | Second Quarter 2006 | Flinders | | International | | Second Quarter 2006 | | Third Quarter 2006 | Resource Recovery | | Corporate | | Third Quarter 2006 | | Fourth Quarter 2006 | ITISA | | International | | Fourth Quarter 2007 | | Second Quarter 2008 |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As of December 31, 2008, there were no assets and liabilities classified as discontinued operations. The following table summarizes the major classes of assets and liabilities classified as discontinued operations as of December 31, 2007.
| | | | | | | As of December 31, | | | | 2007 | | | | (In millions) | | | Cash and cash equivalents | | $ | 43 | | Restricted cash | | | 4 | | Receivables, net | | | 4 | | | | | | | Current assets — discontinued operations | | $ | 51 | | | | | | | Property, plant and equipment, net | | $ | 61 | | Other non-current assets | | | 32 | | | | | | | Non-current assets — discontinued operations | | $ | 93 | | | | | | | Current portion of long-term debt | | $ | 10 | | Accounts payable — trade | | | 4 | | Other current liabilities | | | 23 | | | | | | | Current liabilities — discontinued operations | | $ | 37 | | | | | | | Long-term debt | | $ | 51 | | Minority interest | | | 1 | | Other non-current liabilities | | | 24 | | | | | | | Non-current liabilities — discontinued operations | | $ | 76 | | | | | | |
Summarized results of discontinued operations for the years ended December 31, 2008, 2007, and 2006 were as follows:
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2008 | | | 2007 | | | 2006 | | | | (In millions) | | | Operating revenues | | $ | 20 | | | $ | 50 | | | $ | 227 | | Operating costs and other expenses | | | 9 | | | | 27 | | | | 224 | | | | | | | | | | | | | | | Pre-tax income from operations of discontinued components | | | 11 | | | | 23 | | | | 3 | | Income tax expense | | | 3 | | | | 6 | | | | 1 | | | | | | | | | | | | | | | Income from operations of discontinued components | | | 8 | | | | 17 | | | | 2 | | | | | | | | | | | | | | | Disposal of discontinued components — pre-tax gain | | | 273 | | | | — | | | | 80 | | Income tax expense | | | 109 | | | | — | | | | 4 | | | | | | | | | | | | | | | Gain on disposal of discontinued components, net of income taxes | | | 164 | | | | — | | | | 76 | | | | | | | | | | | | | | | Income from discontinued operations, net of income taxes | | $ | 172 | | | $ | 17 | | | $ | 78 | | | | | | | | | | | | | | |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The pre-tax gain on disposal of the Company’s discontinued operations for the years ended December 31, 2008, 2007 and 2006 were as follows:
| | | | | | | | | | | | | | | | | Year Ended December | | | | | | 2008 | | | 2007 | | | 2006 | | | Segment | | | | | | (In millions) | | | | | ITISA | | $ | 273 | | | $ | — | | | $ | — | | | International | Resource Recovery | | | — | | | | — | | | | 5 | | | Corporate | Flinders | | | — | | | | — | | | | 60 | | | International | Audrain | | | — | | | | — | | | | 15 | | | Corporate | | | | | | | | | | | | | | | | Total pre-tax gain on disposal of discontinued operations | | $ | 273 | | | $ | — | | | $ | 80 | | | | | | | | | | | | | | | | | | |
ITISA — The assets and liabilities reported in the balance sheet as of December 31, 2007 as discontinued operations represent those of ITISA.international segment. On April 28, 2008, NRG completed the sale of its 100% interest in Tosli Acquisition B.V, which held all NRG’s interest in ITISA, to Brookfield Renewable Power Inc. (previously Brookfield Power Inc.), a wholly-owned subsidiary of Brookfield Asset Management Inc. In addition, the purchase price adjustment contingency under the sale agreement was resolved on August 7, 2008. In connection with the sale, NRG received $300 million of cash proceeds from Brookfield, and removed $163 million of assets, including $59 million of cash, $122 million of liabilities, including $63 million of debt, and $15 million in foreign currency translation adjustment from its 2008 consolidated balance sheet. The Company recorded a pre-tax gain on the disposal of ITISA of $273 million in the
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year ended December 31, 2008. Summarized results of ITISA, reflected within discontinued operations for the years ended December 31, 2008, and 2007, were as follows: | | | | | | | | | | | Year Ended December 31, | | | | 2008 | | | 2007 | | | | (In millions) | | | Operating revenues | | $ | 20 | | | $ | 50 | | Operating costs and other expenses | | | 9 | | | | 27 | | | | | | | | | | | Pre-tax income from operations of discontinued components | | | 11 | | | | 23 | | Income tax expense | | | 3 | | | | 6 | | | | | | | | | | | Income from operations of discontinued components | | | 8 | | | | 17 | | | | | | | | | | | Disposal of discontinued components — pre-tax gain | | | 273 | | | | — | | Income tax expense | | | 109 | | | | — | | | | | | | | | | | Gain on disposal of discontinued components, net of income taxes | | | 164 | | | | — | | | | | | | | | | | Income from discontinued operations, net of income taxes | | $ | 172 | | | $ | 17 | | | | | | | | | | |
Other Dispositions Resource RecoveryMIBRAG — In 2006,On June 10, 2009, NRG completed the sale of the Company’s Newport and Elk River Resource Recovery facilities, Becker Ash Disposal facility as well as the Company’s ownership interest in NRG Processing Solutions LLC, to Resource Recovery Technologies, LLC for total proceeds of approximately $22 million.
Flinders — In 2006, NRG completed the sale of the Company’s 100% owned Flinders power station and related assets, or Flinders, located near Port Augusta, Australia, which consisted of two coal-fueled plants — Northern and Playford, with a combined generation capacity of approximately 760 MW, to Babcock & Brown Power Pty, a subsidiary of Babcock & Brown. Proceeds from the sale were approximately $242 million (AU$317 million). The sale resulted in the elimination of approximately $370 million (AU$485 million) of consolidated liabilities, including approximately $183 million (AU$240 million) of non-recourse debt obligations and approximately $92 million (AU$121 million) in non-current liabilities related to obligations for the purchase of electricity and the supply of fuel to the Osborne power station that were guaranteed by NRG.
Audrain — In 2006, NRG completed the sale of Audrain generating station, a gas-fired peaking facility in Vandalia, Missouri, to AmerenUE, a subsidiary of Ameren Corporation. The proceeds from the sale were $115 million, plus AmerenUE’s assumption of $240 million of non-recourse capital lease obligations and assignment of a $240 million note receivable. Of the $115 million in cash proceeds, approximately $20 million was paid to NRG and the balance was paid to the lenders of NRG Financial I LLC.
Acquisition of Texas Genco LLC, or Texas Genco
On February 2, 2006, NRG acquired Texas Genco, which subsequently is being managed and accounted for as a separate business segment referred to as NRG’s Texas region. As such, the results of Texas Genco have been included in NRG’s consolidated financial statements since February 2, 2006. The purchase price of approximately $6.2 billion consisted of approximately $4.4 billion in cash, the issuance of approximately 71 million shares of NRG’s common stock valued at approximately $1.7 billion, and acquisition costs of approximately $0.1 billion. The value of NRG’s common stock issued to the sellers was based on NRG’s average stock price immediately before and after the closing date of February 2, 2006. The acquisition also included the assumption of approximately $2.7 billion of Texas Genco debt.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The acquisition of Texas Genco was funded at closing with a combination of: (i) cash proceeds received upon the issuance and sale in a public offering of approximately 42 million shares of NRG’s common stock at a price of $24.38 per share; (ii) cash proceeds received upon the issuance and sale of $1.2 billion aggregate principal amount of 7.25% Senior Notes due 2014 and $2.4 billion aggregate principal amount of 7.375% Senior Notes due 2016; (iii) cash proceeds received upon the issuance and sale in a public offering of 2,000,000 shares of mandatory convertible preferred stock at a price of $250 per share; (iv) funds borrowed under a new senior secured credit facility; and (v) cash on hand.
The acquisition of Texas Genco was accounted for using the purchase method of accounting and, accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on the estimated fair value of such assets and liabilities as of February 2, 2006. The excess of the purchase price over the fair value of the net tangible and identified intangible assets acquired was $1,782 million and was recorded as goodwill.
Acquisition of Remaining 50% interest in WCP
On March 31, 2006, NRG completed a purchase and sale agreement for projects co-owned with Dynegy, Inc. Under the agreements, NRG acquired Dynegy’sits 50% ownership interest in WCP for $205Mibrag B.V. to a consortium of Severoćeské doly Chomutov, a member of the CEZ Group, and J&T Group. Mibrag B.V.’s principal holding was MIBRAG, which was jointly owned by NRG and URS Corporation. As part of the transaction, URS Corporation also entered into an agreement to sell its 50% stake in MIBRAG.
For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40 U.S.$/EUR), net of transaction costs. During the year ended December 31, 2009, NRG recognized an after-tax gain of $128 million. Prior to completion of the sale, NRG continued to record its share of MIBRAG’s operations to Equity in earnings of unconsolidated affiliates. In connection with the transaction, NRG entered into a foreign currency forward contract to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in cash andexchange for $255 million on June 15, 2009. For the assumptionyear ended December 31, 2009, NRG recorded an exchange loss of a $1$24 million liability,on the contract within Other (loss)/income, net. NRG provided certain indemnities in connection with NRG becomingits share of the sole owner of WCP’s 1,825 MW of generation capacity in Southern California. In addition, NRG sold to Dynegy the Company’s 50% ownership interest in Rocky Road Power LLC, or Rocky Road, a 330 MW gas-fueled, simple cycle peaking plant located in Dundee, Illinois. NRG sold Rocky Roadtransaction. See Note 26,Guarantees, for a fair value sale price of $45 million, paying Dynegy a net purchase price of $160 million at closing. Prior to the purchase, NRG had an existing investment in WCP accounted for as an equity method investment.further discussion. Other Business Events
Red Bluff and Chowchilla — On January 3, 2007, NRG completed the sale of the Company’s Red Bluff and Chowchilla II power plants to an entity controlled by Wayzata Investment Partners LLC. These power plants, located in California, are fueled by natural gas, with generating capacity of 45 MW and 49 MW, respectively.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | Note 45 — | Fair Value of Financial Instruments |
The estimated carrying values and fair values of NRG’s recorded financial instruments related to continuing operations are as follows: | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | Carrying Amount | | | Fair Value | | | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | | (In millions) | | | Cash and cash equivalents | | $ | 1,494 | | | $ | 1,132 | | | $ | 1,494 | | | $ | 1,132 | | Funds deposited by counterparties | | | 754 | | | | — | | | | 754 | | | | — | | Restricted cash | | | 16 | | | | 29 | | | | 16 | | | | 29 | | Cash collateral paid in support of energy risk management activities | | | 494 | | | | 85 | | | | 494 | | | | 85 | | Investment in available-for-sale securities (classified within other non-current assets): | | | | | | | | | | | | | | | | | Debt securities | | | 7 | | | | 32 | | | | 7 | | | | 32 | | Marketable equity securities | | | 2 | | | | 7 | | | | 2 | | | | 7 | | Trust fund investments | | | 305 | | | | 390 | | | | 305 | | | | 390 | | Notes receivable | | | 156 | | | | 126 | | | | 166 | | | | 138 | | Derivative assets | | | 5,485 | | | | 1,184 | | | | 5,485 | | | | 1,184 | | Long-term debt, including current portion | | | 8,026 | | | | 8,180 | | | | 7,496 | | | | 8,164 | | Cash collateral received in support of energy risk management activities | | | 760 | | | | 14 | | | | 760 | | | | 14 | | Derivative liabilities | | | 4,489 | | | | 1,676 | | | | 4,489 | | | | 1,676 | |
| | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Carrying Amount | | Fair Value | | | 2009 | | 2008 | | 2009 | | 2008 | | | (In millions) | | Cash and cash equivalents | | $ | 2,304 | | | $ | 1,494 | | | $ | 2,304 | | | $ | 1,494 | | Funds deposited by counterparties | | | 177 | | | | 754 | | | | 177 | | | | 754 | | Restricted cash | | | 2 | | | | 16 | | | | 2 | | | | 16 | | Cash collateral paid in support of energy risk management activities | | | 361 | | | | 494 | | | | 361 | | | | 494 | | Investment inavailable-for-sale securities (classified within other non-current assets): | | | | | | | | | | | | | | | | | Debt securities | | | 9 | | | | 7 | | | | 9 | | | | 7 | | Marketable equity securities | | | 5 | | | | 2 | | | | 5 | | | | 2 | |
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| | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Carrying Amount | | Fair Value | | | 2009 | | 2008 | | 2009 | | 2008 | | | (In millions) | | Trust fund investments | | | 369 | | | | 305 | | | | 369 | | | | 305 | | Notes receivable | | | 231 | | | | 156 | | | | 238 | | | | 166 | | Derivative assets | | | 2,319 | | | | 5,485 | | | | 2,319 | | | | 5,485 | | Long-term debt, including current portion | | | 8,295 | | | | 8,019 | | | | 8,211 | | | | 7,475 | | Cash collateral received in support of energy risk management activities | | | 177 | | | | 760 | | | | 177 | | | | 760 | | Derivative liabilities | | $ | 1,860 | | | $ | 4,489 | | | $ | 1,860 | | | $ | 4,489 | |
For cash and cash equivalents, funds deposited by counterparties, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of marketable securities is based on quoted market prices for those instruments. Trust fund investments are comprised of various USU.S. debt and equity securities carried at fair market value. The fair value of notes receivable, debt securities and certain long-term debt are based on expected future cash flows discounted at market interest rates. The fair value of long-term debt is based on quoted market prices for these instruments that are publicly traded, or estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality. Adoption of SFAS No. 157Fair Value Accounting under ASC 820
The Company partially adopted SFAS 157 on January 1, 2008, delaying application for non-financial assets and non-financial liabilities as permitted. This statement establishes a framework for measuring fair value, and expands disclosures about fair value measurements.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SFAS 157ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
| | | | • | Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG’s financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments. | | | • | Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG’s financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forwards. | | | • | Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG’s financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models. |
In accordance with SFAS 157,ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. 164
Recurring Fair Value Measurements The following table presents assets and liabilities measured and recorded at fair value on the Company’s consolidated balance sheet on a recurring basis and their level within the fair value hierarchy as of December 31, 2008:2009: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value | | | Fair Value | | | | Level 1 | | Level 2 | | Level 3 | | Total | | | Level 1 | | Level 2 | | Level 3 | | Total | | | | (In millions) | | | (In millions) | | | As of December 31, 2008 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 1,494 | | | $ | — | | | $ | — | | | $ | 1,494 | | | $ | 2,304 | | | $ | — | | | $ | — | | | $ | 2,304 | | Funds deposited by counterparties | | | 754 | | | | — | | | | — | | | | 754 | | | | 177 | | | | — | | | | — | | | | 177 | | Restricted cash | | | 16 | | | | — | | | | — | | | | 16 | | | | 2 | | | | — | | | | — | | | | 2 | | Cash collateral paid in support of energy risk management activities | | | 494 | | | | — | | | | — | | | | 494 | | | | 361 | | | | — | | | | — | | | | 361 | | Investment in available-for-sale securities (classified within other non-current assets): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Debt securities | | | — | | | | — | | | | 7 | | | | 7 | | | | — | | | | — | | | | 9 | | | | 9 | | Marketable equity securities | | | 2 | | | | — | | | | — | | | | 2 | | | | 5 | | | | — | | | | — | | | | 5 | | Trust fund investments | | | 167 | | | | 107 | | | | 31 | | | | 305 | | | | 214 | | | | 118 | | | | 37 | | | | 369 | | Derivative assets | | | 2,168 | | | | 3,264 | | | | 53 | | | | 5,485 | | | | 489 | | | | 1,767 | | | | 63 | | | | 2,319 | | | | | | | | | | | | | | | | | | | | | Total assets | | $ | 5,095 | | | $ | 3,371 | | | $ | 91 | | | $ | 8,557 | | | $ | 3,552 | | | $ | 1,885 | | | $ | 109 | | | $ | 5,546 | | | | | | | | | | | | | | | | | | | | | Cash collateral received in support of energy risk management activities | | $ | 760 | | | $ | — | | | $ | — | | | $ | 760 | | | $ | 177 | | | $ | — | | | $ | — | | | $ | 177 | | Derivative liabilities | | | 2,186 | | | | 2,299 | | | | 4 | | | | 4,489 | | | | 501 | | | | 1,283 | | | | 76 | | | | 1,860 | | | | | | | | | | | | | | | | | | | | | Total liabilities | | $ | 2,946 | | | $ | 2,299 | | | $ | 4 | | | $ | 5,249 | | | $ | 678 | | | $ | 1,283 | | | $ | 76 | | | $ | 2,037 | | | | | | | | | | | | | | | | | | | | |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table reconciles, for the periodyear ended December 31, 2008,2009, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs: | | | | | | | | | | | | | | | | | | | Fair Value Measurement Using Significant
| | | | Unobservable Inputs | | | | (Level 3) | | | | | | | Trust Fund
| | | | | | | | | | Debt Securities | | | Investments | | | Derivatives | | | Total | | | | (In millions) | | | Year Ended December 31, 2008 | | | | | | | | | | | | | | | | | Beginning balance as of January 1, 2008 | | $ | 32 | | | $ | 37 | | | $ | 27 | | | $ | 96 | | Total gains and losses (realized/unrealized) Included in earnings | | | (23 | ) | | | — | | | | 5 | | | | (18 | ) | Included in nuclear decommissioning obligations | | | — | | | | (14 | ) | | | — | | | | (14 | ) | Included in other comprehensive income | | | — | | | | — | | | | 27 | | | | 27 | | Purchases/(sales), net | | | (2 | ) | | | 7 | | | | (10 | ) | | | (5 | ) | Transfer into Level 3 | | | — | | | | 1 | | | | — | | | | 1 | | | | | | | | | | | | | | | | | | | Ending balance as of December 31, 2008 | | $ | 7 | | | $ | 31 | | | $ | 49 | | | $ | 87 | | | | | | | | | | | | | | | | | | | The amount of the total gains or losses for the period included in earnings attributable to the change in unrealized gains and losses relating to assets still held as of December 31, 2008 | | $ | (23 | ) | | $ | — | | | $ | (50 | ) | | $ | (73 | ) | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | Fair Value Measurement Using Significant
| | | | Unobservable Inputs | | | | (Level 3) | | | | | | | Trust Fund
| | | | | | | | | | Debt Securities | | | Investments | | | Derivatives(a) | | | Total | | | | (In millions) | | | Beginning balance as of January 1, 2009 | | $ | 7 | | | $ | 31 | | | $ | 49 | | | $ | 87 | | Total gains and losses (realized/unrealized): | | | | | | | | | | | | | | | | | Included in OCI | | | 2 | | | | — | | | | — | | | | 2 | | Included in earnings | | | — | | | | — | | | | (97 | ) | | | (97 | ) | Included in nuclear decommissioning obligations | | | — | | | | 9 | | | | — | | | | 9 | | Purchases/(sales), net | | | — | | | | (3 | ) | | | 1 | | | | (2 | ) | Transfers, out of Level 3 | | | — | | | | — | | | | 34 | | | | 34 | | | | | | | | | | | | | | | | | | | Ending balance as of December 31, 2009 | | $ | 9 | | | $ | 37 | | | $ | (13 | ) | | $ | 33 | | | | | | | | | | | | | | | | | | | The amount of the total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held as of December 31, 2009 | | $ | — | | | $ | — | | | $ | 25 | | | $ | 25 | | | | | | | | | | | | | | | | | | |
| | | (a) | | Consists of derivatives assets and liabilities, net. |
Realized and unrealized gains and losses included in earnings that are related to the debt securities are recorded in other income, while those related to energy derivatives are recorded in operating revenues.revenues and cost of operations. Non-derivative fair value measurements NRG’s investment in debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued based on an auction process.third-party market value assessments. 165
The trust fund investments are held primarily to satisfy NRG’s nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, USU.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding USU.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Commingled funds, which are analogous to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair value of commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See also Note 6,7,Nuclear Decommissioning Trust Fund.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Derivative fair value measurements A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG’s contracts are non exchange-tradednon-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers orover-the-counter and on-line exchanges. For the majority of ourNRG markets, the Company receives quotes from multiple sources. To the extent that the CompanyNRG receives multiple quotes, NRGthe Company’s prices reflect the average of the bid-ask mid-point prices obtained from all sources that itNRG believes provide the most liquid market for the commodity. If the Company only receives one quote, then the mid pointmid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company’s derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities representrepresents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 5%3% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on creditpublished default swaps.probabilities. To the extent that NRG’s net exposure under a specific master agreement is an asset, the Company is usinguses the counterparty’s default swap rate. If the exposure under a specific master agreement is a liability, the Company is usinguses NRG’s default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG’s liabilities or that a market participant would be willing to pay for NRG’s assets. As of December 31, 20082009, the credit reserve resulted in a $22$1 million decreaseincrease in fair value which is composed of a $10$1 million loss in OCI and a $12$2 million lossgain in derivative revenue. revenue and cost of operations. The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 20082009, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange andover-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material. Under the guidance of FSPFIN 39-1,ASC 815, entities may choose to offset cash collateral paid or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in this FSP.ASC 815. As of December 31, 2008,2009, the Company recorded $494$361 million of cash collateral paid and $760$177 million of cash collateral received on its balance sheet. 166
Concentration of Credit Risk In addition to the credit risk discussion as disclosed in Note 2,Summary of Significant Accounting Policies, the following item is a discussion of the concentration of credit risk for the Company’s financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties’ credit limits; (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives, prepayment arrangements, or volumetric limits (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a diversified portfolio of counterparties, including nine participants under its first and second lien structure. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle. Since the credit crisis began in late 2008, NRG has taken several additional steps to mitigate credit risk including the use of netting arrangements, entering contracts with collateral thresholds, setting volumetric limits with certain counterparties and restricting trading relationships with counterparties where exposure was high or where credit quality of the counterparty had deteriorated. NRG avoids concentration of counterparties whenever possible and applies credit policies that include an evaluation of counterparties’ financial condition, collateral requirements and the use of standard agreements that allow for netting and other security. As of December 31, 2009, total credit exposure to substantially all counterparties was $1.3 billion and NRG held collateral (cash and letters of credit) against those positions of $186 million resulting in a net exposure of $1.1 billion. Total credit exposure is discounted at the risk free rate. The following table highlights the credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow,mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, includes amounts net of receivables or payables. | | | | | | | Net Exposure (a)
| | | | as of December 31, 2009
| | Category | | (% of Total) | | Financial institutions | | | 69 | % | Utilities, energy merchants, marketers and other | | | 25 | | Coal suppliers | | | 3 | | ISOs | | | 3 | | | | | | | Total as of December 31, 2009 | | | 100 | % |
| | | | | | | Net Exposure (a)
| | | | as of December 31, 2009
| | Category | | (% of Total) | | Investment grade | | | 90 | % | Non-rated | | | 8 | | Non-Investment grade | | | 2 | | | | | | | Total as of December 31, 2009 | | | 100 | % |
| | | (a) | | Credit exposure excludes California tolling, uranium, coal transportation, New England RMR, certain cooperative load contracts, and Texas Westmoreland coal contracts. The aforementioned exposures were excluded for various reasons including regulatory support or liens held against the contracts which serve to reduce the risk of loss, or credit risks for certain contracts are not readily measurable due to a lack of market reference prices. |
NRG has credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $351 million. Approximately 82% of NRG’s positions relating to credit risk roll-off by the end of 2012. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG 167
does not anticipate a material impact on the Company’s financial position or results of operations from nonperformance by any of NRG’s counterparties. NRG is exposed to retail credit risk through its competitive electricity supply business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and anyin-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements. As of December 31, 2009, the Company’s credit exposure to C&I customers was diversified across many customers and various industries. No one customer represented more than 2% of total exposure and the majority of the customers have investment grade credit quality, as determined by NRG. NRG is also exposed to credit risk relating to its 1.5 million Mass customers, which may result in a write-off of a bad debt. The current economic conditions may affect the Company’s customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense. | | Note 56 — | Accounting for Derivative Instruments and Hedging Activities |
SFAS 133ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a Normal Purchase Normal Sale, or NPNS, exception. If certain conditions are met, NRG may be able to designate certain derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives to OCI until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings. The ineffective portion of a hedging derivative instrument’s change in fair value is immediately recognized into earnings. For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established per SFAS 133,ASC 815, certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. SFAS 133ASC 815 applies to NRG’s energy related commodity contracts, interest rate swaps, and foreign exchange contracts.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As the Company engages principally in the trading and marketing of its generation assets mostand retail business, some of NRG’s commercial activities qualify for hedge accounting under the requirements of SFAS 133.ASC 815. In order for the generation assets to so qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company’s baseload plants. For this reason, the majority ofmany trades in support of NRG’s baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG’s peaking unitsunits’ asset optimization will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on amark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the supply contracts are recorded undermark-to-market accounting. All of NRG’s hedging and trading activities are in accordance with the Company’s risk management policy.Risk Management Policy. Derivative Financial Instruments
Energy-Related Commodities To manage the commodity price risk associated with the Company’s competitive supply activities and the price risk associated with wholesale and retail power sales from the Company’s electric generation facilities, NRG may enter into a variety of derivative and non-derivative hedging instruments, utilizing the following: | | | | • | Forward contracts, which commit NRG to sell or purchase energy commodities or purchase fuels in the future. | | | • | Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument. |
168
| | | | • | Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity. | | | • | Option contracts, which convey the right or obligation to buypurchase or sell a commodity. | | | • | Weather and hurricane derivative products used to mitigate a portion of Reliant Energy’s lost revenue due to weather. |
The objectives for entering into derivative contracts designated as hedges include: | | | | • | Fixing the price for a portion of anticipated future electricity sales through the use of various derivative instruments including gas collars and swaps at a level that provides an acceptable return on the Company’s electric generation operations. | | | • | Fixing the price of a portion of anticipated fuel purchases for the operation of NRG’s power plants. | | | • | Fixing the price of a portion of anticipated energy purchases to supply NRG’s load-servingReliant Energy’s customers. |
NRG’s trading activities are subject to limits in accordance with the Company’s Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. As of December 31, 2008,2009, NRG had hedge and non-hedge energy-related derivative financial instruments, and other energy-related contracts that did not qualify as derivative financial instruments extending through December 2026. As of December 31, 2008,2009, NRG’s derivative assets and liabilities consisted primarily of the following: | | | | • | Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG’s generation assets’ forecasted output or NRG’s retail load obligations through 2014.2015. | | | • | Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG’s generation assets into 2017. |
Also, as of December 31, 2008,2009, NRG had other energy-related contracts that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment under the guidelines established by SFAS 133ASC 815 as follows: | | | | • | Power sales and capacity contracts extending to 2025. | | | • | Coal purchase contracts extending through 2012 designated as normal purchases and disclosed as part of NRG’s contractual cash obligations. See also Note 21,Commitments and Contingencies, for further discussion. |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Also, as of December 31, 2008,2009, NRG had other energy-related contracts that did not qualify as derivatives under the guidelines established by SFAS 133ASC 815 as follows: | | | | • | Load-following forward electric sale contracts extending through 2026.2026; | | | • | Power Tolling contracts through 2017.2029; | | | • | Lignite purchase contract through 2018.2018; | | | • | Power transmission contracts through 2011.2015; | | | • | Natural gas transportation contracts and storage agreements through 2018.2018; and | | | • | Coal transportation contracts through 2016. |
Interest Rate Swaps NRG is exposed to changes in interest rates through the Company’s issuance of variable and fixed rate debt. In order to manage the Company’s interest rate risk, NRG enters into interest-rate swap agreements. In January 2006, in anticipation of the New Senior Credit Facility, NRG entered into a series of forward starting interest rate swaps intended to hedge the variability in cash flows associated with the debt issuance. These transactions were designated as cash flow hedges with any gains/losses deferred on the balance sheet in OCI. In February 2006, with the completion of the sale of the Senior Notes, the Company designated a fixed-to-floating interest rate swap as a hedge of fair value changes in the Senior Notes. This interest rate swap was previously designated as a hedge of NRG’s 8% Second Priority Notes, which were effectively replaced by the Senior Notes. As of December 31, 2008,2009, NRG had interest rate derivative instruments extending through June 2019, all of NRG’s interest rate swap arrangementswhich had been designated as either cash flow or fair value hedges. 169
Volumetric Underlying Derivative Transactions The following table summarizes the net notional volume buy/(sell) of NRG’s derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2009. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will bein-the-money at its expiration date. | | | | | | | | | | | Total Volume as
| Commodity | | Units | | of December 31, 2009 | | | | | (In millions) | | Emissions | | Short Ton | | | (2 | ) | Coal | | Short Ton | | | 55 | | Natural Gas | | MMBtu | | | (484 | ) | Oil | | Barrel | | | 1 | | Power(a) | | MWH | | | (41 | ) | Interest | | Dollar | | $ | 3,291 | |
| | | (a) | | Power volumes include capacity sales. |
Fair Value of Derivative Instruments The Company has elected to disclose derivative assets and liabilities on atrade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company’s derivative assets or liabilities are recorded on a separate line item on the balance sheet. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2008, NRG had interest rate2009, the Company recorded $361 million of cash collateral paid and $177 million of cash collateral received on its balance sheet. The following table summarizes the fair value within the derivative instruments extending through June 2019.instrument valuation on the balance sheet as of December 31, 2009: | | | | | | | | | | | Fair Value | | | | Derivatives Asset | | | Derivatives Liability | | | | (In millions) | | | Derivatives Designated as Cash Flow or Fair Value Hedges: | | | | | | | | | Interest rate contracts current | | $ | — | | | $ | 2 | | Interest rate contracts long-term | | | 8 | | | | 106 | | Commodity contracts current | | | 300 | | | | 12 | | Commodity contracts long-term | | | 508 | | | | 6 | | | | | | | | | | | Total Derivatives Designated as Cash Flow or Fair Value Hedges | | | 816 | | | | 126 | | Derivatives Not Designated as Cash Flow or Fair Value Hedges: | | | | | | | | | Commodity contracts current | | | 1,336 | | | | 1,459 | | Commodity contracts long-term | | | 167 | | | | 275 | | | | | | | | | | | Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | | | 1,503 | | | | 1,734 | | | | | | | | | | | Total Derivatives | | $ | 2,319 | | | $ | 1,860 | | | | | | | | | | |
Impact of Derivative Instruments on the Statement of Operations The following table summarizes the amount of gain/(loss) resulting from fair value hedges reflected in interest income/(expense) for interest rate contracts: | | | | | | | Years Ended
| Amount of gain/(loss) recognized | | December 31, 2009 | | | (In millions) | | Derivative | | $ | (6 | ) | Senior Notes (hedged item) | | $ | 6 | |
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The following table summarizes the location and amount of gain/(loss) resulting from cash flow hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | Location of
| | Amount of
| | | | Amount of
| | | Location of
| | Amount of
| | | gain/(loss)
| | gain
| | | | gain
| | | gain/(loss)
| | gain/(loss)
| | | recognized in
| | recognized in
| | | | recognized in OCI
| | | reclassified from
| | reclassified from
| | | income
| | income
| | | | (effective portion)
| | | Accumulated
| | Accumulated
| | | (ineffective
| | (ineffective
| | Year ended December 31, 2009 | | after tax | | | OCI into Income | | OCI into Income | | | portion) | | portion) | | | | (In millions) | | | Interest rate contracts | | $ | 36 | | | Interest expense | | $ | 1 | | | Interest expense | | $ | 4 | | Commodity contracts | | | 55 | | | Operating revenue | | | (472 | ) | | Operating revenue | | | 45 | | | | | | | | | | | | | | | | | | | Total | | $ | 91 | | | | | $ | (471 | ) | | | | $ | 49 | | | | | | | | | | | | | | | | | | |
The following table summarizes the amount of gain/(loss) recognized in income for derivatives not designated as cash flow or fair value hedges on commodity contracts: | | | | | | | Year ended
| Amount of gain/(loss) recognized in income or cost of operations for derivatives | | December 31, 2009 | | | (In millions) | | Location of gain/(loss) recognized in income for derivatives: | | | | | Operating revenues | | $ | (335 | ) | Cost of operations | | $ | 842 | |
Credit Risk Related Contingent Features Certain of the Company’s hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements. Other agreements contain provisions that require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. The collateral required forout-of-the-money positions and net accounts payable for contracts that have adequate assurance clauses that are in a net liability position as of December 31, 2009, was $80 million. The collateral required forout-of-the-money positions and net accounts payable for contracts with credit rating contingent features that are in a net liability position as of December 31, 2009, was $49 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $3 million as of December 31, 2009. As of January 29, 2010, Merrill Lynch was no longer providing credit support for any wholesale energy supply contracts relating to the retail business. Merrill Lynch continues to provide guaranties to certain C&I customers as part of the credit sleeve arrangement. If Merrill Lynch were to default, NRG would be required to post guaranties to replace Merrill. See Note 5,Fair Value of Financial Instruments, for discussion regarding concentration of credit risk. Accumulated Other Comprehensive Income Gains and losses attributable to hedge derivatives are reclassified from OCI to current period earnings due to the unwinding of previously deferred amounts. These amounts are recorded on the same line in the statement of operations in which the hedged transactions are recorded. Changes in the fair values of derivatives accounted for as hedges are also recorded in OCI.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes the effects of SFAS 133,ASC 815 on NRG’s accumulated other comprehensive incomeOCI balance attributable to hedged derivatives, for the years ended December 31, 2008, 2007 and 2006, net of tax: | | | | | | | | | | | | | | | Energy-Related
| | | | | | | | | | Commodities | | | Interest Rate | | | Total | | | | (In millions) | | | Accumulated OCI balance at December 31, 2005 | | $ | (204 | ) | | $ | 8 | | | $ | (196 | ) | Realized from OCI during period — due to unwinding of previously deferred amounts | | | 6 | | | | (2 | ) | | | 4 | | Changes in fair value of hedge contracts — gains | | | 391 | | | | 10 | | | | 401 | | | | | | | | | | | | | | | Accumulated OCI balance at December 31, 2006 | | | 193 | | | | 16 | | | | 209 | | Realized from OCI during period: — due to unwinding of previously deferred amounts | | | (50 | ) | | | (2 | ) | | | (52 | ) | Changes in fair value of hedge contracts — losses | | | (377 | ) | | | (45 | ) | | | (422 | ) | | | | | | | | | | | | | | Accumulated OCI balance at December 31, 2007 | | | (234 | ) | | | (31 | ) | | | (265 | ) | Realized from OCI during period — due to unwinding of previously deferred amounts | | | — | | | | (1 | ) | | | (1 | ) | Changes in fair value of hedge contracts — gains/(losses) | | | 640 | | | | (59 | ) | | | 581 | | | | | | | | | | | | | | | Accumulated OCI balance at December 31, 2008 | | $ | 406 | | | $ | (91 | ) | | $ | 315 | | | | | | | | | | | | | | | Gains/(losses) expected to unwind from OCI during next 12 months, net of $176 tax | | $ | 278 | | | $ | (1 | ) | | $ | 277 | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Energy
| | | Interest
| | | | | Year ended December 31, 2009 | | Commodities | | | Rate | | | Total | | | | (In millions) | | | Accumulated OCI balance at December 31, 2008 | | $ | 406 | | | $ | (91 | ) | | $ | 315 | | Realized from OCI during the period: | | | | | | | | | | | | | - Due to realization of previously deferred amounts | | | (335 | ) | | | 1 | | | | (334 | ) | - Due to discontinuance of cash flow hedge accounting | | | (137 | ) | | | — | | | | (137 | ) | Mark-to-market of cash flow hedge accounting contracts | | | 527 | | | | 35 | | | | 562 | | | | | | | | | | | | | | | Accumulated OCI balance at December 31, 2009 | | $ | 461 | | | $ | (55 | ) | | $ | 406 | | | | | | | | | | | | | | | Gains/(losses) expected to be realized from OCI during the next 12 months, net of $123 tax | | $ | 213 | | | $ | (3 | ) | | $ | 210 | | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | Energy
| | | Interest
| | | | | Year ended December 31, 2008 | | Commodities | | | Rate | | | Total | | | | (In millions) | | | Accumulated OCI balance at December 31, 2007 | | $ | (234 | ) | | $ | (31 | ) | | $ | (265 | ) | Realized from OCI during the period: | | | | | | | | | | | | | - Due to realization of previously deferred amounts | | | — | | | | (1 | ) | | | (1 | ) | Mark-to-market of cash flow hedge accounting contracts | | | 640 | | | | (59 | ) | | | 581 | | | | | | | | | | | | | | | Accumulated OCI balance at December 31, 2008 | | $ | 406 | | | $ | (91 | ) | | $ | 315 | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Energy
| | | Interest
| | | | | Year ended December 31, 2007 | | Commodities | | | Rate | | | Total | | | | (In millions) | | | Accumulated OCI balance at December 31, 2006 | | $ | 193 | | | $ | 16 | | | $ | 209 | | Realized from OCI during the period: | | | | | | | | | | | | | - Due to realization of previously deferred amounts | | | (50 | ) | | | (2 | ) | | | (52 | ) | Mark-to-market of cash flow hedge accounting contracts | | | (377 | ) | | | (45 | ) | | | (422 | ) | | | | | | | | | | | | | | Accumulated OCI balance at December 31, 2007 | | $ | (234 | ) | | $ | (31 | ) | | $ | (265 | ) | | | | | | | | | | | | | |
As of December 31, 2009, the net balance in OCI relating to ASC 815 was an unrecognized gain of approximately $406 million, which is net of $247 million in income taxes. As of December 31, 2008, the net balance in OCI relating to SFAS 133ASC 815 was an unrecognized gain of approximately $315 million, which iswas net of $194 million in income taxes. NRG expects $277 million of net deferred gains on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months. Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of July 31, 2008, ourthe Company’s regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar years 2012 and 2013. As a result, wethe Company de-designated ourits 2012 and 2013 ERCOT cash flow hedges as of this day. We will continueJuly 31, 2008 and prospectively marked these derivatives to monitor the correlations in this market, and if the regression analysis meetsmarket. On April 1, 2009, the required thresholds in the future, we may elect to re-designatecorrelation threshold for cash flow hedge accounting was achieved for these transactions, and accordingly, these hedges were re-designated as cash flow hedges. As discussed in Note 3,Business Acquisitions, in conjunction with the CSRA, PML and REPS modified or novated certain transactions with counterparties. The novated transactions are financial sales of natural gas to the counterparties covering the period from 2009 through 2012 to hedge NRG’s Texas baseload generation. A portion of these transactions were accounted for as cash flow hedges. The effective portion of the fair value of these transactions recorded in OCI was approximately $247 million. On the date of novation, NRG elected to de-designate these cash flow hedges and to recognize future changes in value in earnings prospectively. As the underlying baseload power generation is still probable, the gains through the date of novation related to the cash flow hedges remain frozen in OCI and will be amortized into income when the underlying power is generated. Approximately $240 million of the fair values of these transactions at the novation date were accounted for asmark-to-market transactions through the income statement both before and after the novations. As also discussed in Note 3,Business Acquisitions, on October 5, 2009, the Company amended the CSRA with Merrill Lynch. In connection with the CSRA amendment, NRG net settled certain REPS’out-of-money supply transactions with Merrill Lynch and paid $104 million in consideration. In addition, NRG net settled certainin-the-money REPS transactions with Morgan and received $269 million in consideration. As noted above, thein-the-money transaction was previously novated by NRG’s wholly owned subsidiary PML to REPS. As these transactions were net settled, the $245 million in OCI will continue to be frozen and will be amortized into income when the underlying power from the baseload plants are generated and the balance of $24 million of previously recorded unrealized revenue was recorded as a loss of $24 million in unrealized derivative revenue and a $24 million gain in realized or financial revenue. The net settlement on the Merrill Lynch transactions resulted in a realized loss of $104 million and an unrealized gain of $104 million due to the reversal of an unrealized loss.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Statement of Operations In accordance with SFAS 133,ASC 815, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings. The following table summarizes the pre-tax effects of economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activity on NRG’s statement of operations. These amounts are included within operating revenues.revenues and cost of operations. | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2008 | | | 2007 | | | 2006 | | | | (In millions) | | | Unrealized mark-to-market results | | | | | | | | | | | | | Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | | $ | (38 | ) | | $ | (128 | ) | | $ | 116 | | Reversal of previously recognized unrealized gains on settled positions related to trading activity | | | (32 | ) | | | (32 | ) | | | (26 | ) | Net unrealized gains on open positions related to economic hedges | | | 524 | | | | 20 | | | | 144 | | (Loss)/gain on ineffectiveness associated with open positions treated as cash flow hedges | | | (24 | ) | | | 14 | | | | 28 | | Net unrealized gains on open positions related to trading activity | | | 95 | | | | 49 | | | | 33 | | | | | | | | | | | | | | | Total unrealized mark-to-market results | | $ | 525 | | | $ | (77 | ) | | $ | 295 | | | | | | | | | | | | | | |
| | | | | | | | | | | Year ended
| | | | December 31, | | | | 2009 | | | 2008 | | | | (In millions) | | | Unrealizedmark-to-market results | | | | | | | | | Reversal of previously recognized unrealized gains on settled positions related to economic hedges | | $ | (68 | ) | | $ | (38 | ) | Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009 | | | 656 | | | | — | | Reversal of previously recognized unrealized gains on settled positions related to trading activity | | | (157 | ) | | | (32 | ) | Reversal of previously recognized unrealized losses due to the termination of positions related to the CSRA unwind | | | 80 | | | | — | | Net unrealized gains on open positions related to economic hedges | | | 22 | | | | 524 | | Gains/(losses) on ineffectiveness associated with open positions treated as cash flow hedges | | | 45 | | | | (24 | ) | Net unrealized (losses)/gains on open positions related to trading activity | | | (26 | ) | | | 95 | | | | | | | | | | | Total unrealized gains | | $ | 552 | | | $ | 525 | | | | | | | | | | |
| | | | | | | | | | | Year Ended
| | | | December 31, | | | | 2009 | | | 2008 | | | | (In millions) | | | Revenue/(expense) from operations - energy commodities | | $ | (290 | ) | | $ | 525 | | Cost of operations | | | 842 | | | | — | | | | | | | | | | | Total impact to statement of operations | | $ | 552 | | | $ | 525 | | | | | | | | | | |
The $22 million gain from economic hedge positions includes a gain of $217 million recognized in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation, offset by a loss of $29 million resulting from discontinued NPNS designated coal purchases due to expected lower coal consumption and accordingly could not assert taking physical delivery and a $166 million decrease in value of forward purchases and sales of natural gas, electricity and fuel due to decrease in forward power and gas prices. The Reliant Energy’s loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. The $656 million roll-off amounts were offset by realized losses at the settled prices and are reflected in revenue and cost of operations during the same period. For the year ended December 31, 2008, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $525 million iswas comprised of $500$524 million of fair value increases in forward sales of electricity and fuel, $70a $24 million loss from the reversal of mark-to-market gains, which ultimately settled as financial revenues, and $95 million of gains associated with our trading activity. The $500 million of fair value increases in forward sales of electricity and fuel includes a loss of approximately $24 million due to the ineffectiveness associated with financial forward contracted electric and gas sales. For the year ended December 31, 2007, the unrealized loss associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $77sales, $70 million is comprised of $34 million of fair value increases in forward sales of electricity and fuel, $160 million loss from the reversal ofmark-to-market gains which ultimately settled as financial and physical revenues of which $38 million was related to economic hedges and $49$32 million was related to trading activity. These decreases were partially offset by $95 million of gains associated with ouropen positions related to trading activity. The $34 million of fair value increases in forward sales of electricity and fuel includes approximately $14 million due to the ineffectiveness associated with financial forward contracted electric and gas sales.
For the year ended December 31, 2006, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $295 million is comprised of $172 million of fair value increases in forward sales of electricity and fuel, $90 million from the reversal of mark-to-market losses, which ultimately settled as financial revenues, and $33 million of gains associated with our trading activity. The $172 million of fair value increases in forward sales of electricity and fuel includes approximately $28 million due to the ineffectiveness associated with financial forward contracted electric and gas sales. NRG’s pre-tax earnings were also affected by a $3 million loss due to ineffectiveness associated with our fixed-to-floating interest rate swap designated as a hedge of fair value changes in the Senior Notes.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Discontinued Hedge Accounting —- During 2008,the first half of 2009, a relatively mild summer seasonsharp decline in the Northeastcommodity prices resulted in falling power prices and expected lower power generation for the remainder of 2008 and calendar year 2009. As such, NRG discontinued cash flow hedge accounting for certain 2009 contracts related to commodity price risk previously accounted for as cash flow hedges for 2008 and 2009.hedges. These contracts 173
were originally entered into as hedges of forecasted sales by baseload plants.plants in Texas and Northeast. As a result, $31$217 million of gain previously deferred in OCI was recognized in earnings for the year ended December 31, 2008.2009. During 2006, dueDiscontinued Normal Purchase and Sale for Coal Purchases- Due to a relatively mild summer seasonlower coal-fired generation during the first quarter 2009, the Company’s coal consumption was lower than forecasted. The Company net settled some of its coal purchases under NPNS designation and expected lower power generation for the remainder of 2006, NRG discontinued cash flow hedge accounting for certain contracts related to commodity prices previously accounted for as a cash flow hedge and determined forecasted sales werethus was no longer probable. These contracts were originally enteredable to assert physical delivery under these coal contracts. The forward positions previously treated as accrual accounting have been reclassified into as hedgesmark-to-market accounting during the first quarter and prospectively. The impact of forecasted sales by baseload plants. The decision not to deliver against these contracts was driven bydiscontinuance of coal NPNS designated transactions resulted in a derivative loss of $29 million that is reflected in the decline in natural gas and associated power prices, making it uneconomical to dispatch the units into the marketplace. As a result, approximately $5 millioncost of previously deferred revenue in OCI was recognized in earningsoperations for the year ended December 31, 2006.
Impact of Hedge Reset — NRG accounted for the Company’s Hedge Reset transaction as a net settlement of its current hedge positions and a subsequent reestablishment of new hedge positions. The impact of the net settlement reduced revenues by approximately $129 million.
As of December 31, 2006, the impact to NRG’s consolidated financial position and statement of operations from the Hedge Reset transaction was as follows:
| | | | | | | (In millions) | | | Settlement payment | | $ | (1,347 | ) | Reduction in derivative liability | | | 145 | | Reduction in out-of-market contracts | | | 1,073 | | | | | | | Net decrease in revenues | | $ | (129 | ) | | | | | |
Concentration of Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process, (ii) a daily monitoring of counterparties’ credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements, and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a diversified portfolio of counterparties, including ten participants under its first and second lien structure. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.
As of December 31, 2008, total credit exposure to substantially all counterparties was $2.0 billion and NRG held collateral (cash and letters of credit) against those positions of $788 million resulting in a net exposure of $1.2 billion. Total credit exposure is discounted at the risk free rate.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table represents the credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit risk is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark to market and NPNS and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.
| | | | | | | Net Exposure(a)
| | Category
| | (% of Total) | | | Coal producers | | | 16 | % | Financial institutions | | | 58 | | Utilities, energy, merchants and marketers | | | 21 | | ISOs | | | 5 | | | | | | | Total as of December 31, 2008 | | | 100 | % | | | | | |
| | | | | | | Net Exposure(a)
| | Category
| | (% of Total) | | | Investment grade | | | 81 | % | Non-Investment grade | | | 8 | | Non-rated | | | 11 | | | | | | | Total as of December 31, 2008 | | | 100 | % | | | | | |
| | | (a) | | Credit exposure excludes California tolling, uranium, coal transportation/railcar leases, New England Reliability Must-Run, cooperative load contracts and Texas Westmoreland coal contracts. |
NRG has credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $241 million. No counterparty represents more than 20% of total net credit exposure. Approximately 80% of NRG’s positions relating to credit risk roll-off by the end of 2011. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. NRG does not anticipate any material adverse effect on the Company’s financial position or results of operations as a result of nonperformance by any of NRG’s counterparties.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)2009.
| | Note 67 — | Nuclear Decommissioning Trust Fund |
NRG’s nuclear decommissioning trust fund assets, which are for the decommissioning of STP, are primarily comprised of securities classified asavailable-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rate base all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities. NRG accounts for thesethe nuclear decommissioning trust fund assets per SFAS 71,in accordance with ASC 980 —Accounting for the Effects of Certain Types of RegulationRegulated Operations, or ASC 980 because the Company’s nuclear decommissioning activities are regulatedsubject to approval by the PUCT. AlthoughPUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the owners of STP are responsible forratepayers per PUCT mandate. Since the management ofCompany is in compliance with PUCT rules and regulations regarding decommissioning STP,trusts and the cost of decommissioning is the responsibility of the Texas ratepayers. As such,ratepayers, not NRG, does not bear the cost for these decommissioning responsibilities, exceptall realized and unrealized gains or losses (includingother-than-temporary impairments) related to the extent that NRG has a prudence obligation with respectNuclear Decommissioning Trust Fund are recorded to the management of the trust funds or the future decommissioning of STP. Third party appraisals are periodically conducted to estimate the future decommissioning liability related to STP. These appraisals are then used to determine the adequacy of the existing decommissioning trust investments to cover that estimated future liability. Should there be a shortfall in the value of the assets in the trust relativeNuclear Decommissioning Trust Liability to the estimated liability, NRG has the ability to file a rate caseratepayers and are not included in net income or accumulated other comprehensive income, consistent with the PUCT to increase decommissioning reimbursements over time from retail customers.regulatory treatment. The following table summarizes the aggregate fair values ofand unrealized gains and losses (includingother-than-temporary impairments) for the securities held in the trust funds as of December 31, 2009 and 2008, and 2007:as well as information about the contractual maturities of those securities. The cost of securities sold is determined on the specific identification method. | | | | | | | | | | | As of December 31, | | | | 2008 | | | 2007 | | | | (In millions) | | | Cash and cash equivalents | | $ | 2 | | | $ | 4 | | US government and federal agency obligations | | | 21 | | | | 21 | | Federal agency mortgage-backed securities | | | 49 | | | | 59 | | Commercial mortgage-backed securities | | | 16 | | | | 22 | | Corporate debt securities | | | 37 | | | | 44 | | Marketable equity securities | | | 178 | | | | 234 | | | | | | | | | | | Total | | $ | 303 | | | $ | 384 | | | | | | | | | | |
Inventory consists of:
| | | | | | | | | | | As of December 31, | | | | 2008 | | | 2007 | | | | (In millions) | | | Fuel oil | | $ | 128 | | | $ | 140 | | Coal/Lignite | | | 189 | | | | 174 | | Natural gas | | | 11 | | | | 16 | | Spare parts | | | 127 | | | | 121 | | | | | | | | | | | Total Inventory | | $ | 455 | | | $ | 451 | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2009 | | | As of December 31, 2008 | | | | | | | | | | | | | Weighted-
| | | | | | | | | | | | | | | | | | | | | | average
| | | | | | | | | | | | | Fair
| | | Unrealized
| | | Unrealized
| | | maturities
| | | | | | Unrealized
| | | Unrealized
| | | | Value
| | | gains
| | | losses
| | | (years) | | | Fair Value
| | | gains
| | | losses
| | | | (In millions, except otherwise noted) | | | Cash and cash equivalents | | $ | 4 | | | $ | — | | | $ | — | | | | — | | | $ | 2 | | | $ | — | | | $ | — | | U.S. government and federal agency obligations | | | 23 | | | | 1 | | | | — | | | | 19 | | | | 21 | | | | 2 | | | | — | | Federal agency mortgage-backed securities | | | 60 | | | | 2 | | | | — | | | | 23 | | | | 49 | | | | 2 | | | | — | | Commercial mortgage-backed securities | | | 10 | | | | — | | | | 1 | | | | 29 | | | | 16 | | | | — | | | | 4 | | Corporate debt securities | | | 48 | | | | 3 | | | | 1 | | | | 10 | | | | 37 | | | | 1 | | | | 2 | | Marketable equity securities | | | 220 | | | | 89 | | | | 2 | | | | — | | | | 178 | | | | 41 | | | | 6 | | Foreign government fixed income securities | | | 2 | | | | — | | | | — | | | | 6 | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 367 | | | $ | 95 | | | $ | 4 | | | | | | | $ | 303 | | | $ | 46 | | | $ | 12 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
167174
The following tables summarize proceeds from sales ofNRG ENERGY, INC. AND SUBSIDIARIES available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method. | | | | | | | | | | | | | | | Year ended December 31, | | | | 2009 | | | 2008 | | | 2007 | | | | | | | (In millions) | | | | | | Realized gains | | $ | 2 | | | $ | 11 | | | $ | 6 | | Realized losses | | | (1 | ) | | | (33 | ) | | | (1 | ) | Proceeds from sale of securities | | | 279 | | | | 582 | | | | 233 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Inventory consists of: | | | | | | | | | | | As of December 31, | | | | 2009 | | | 2008 | | | | (In millions) | | | Fuel oil | | $ | 104 | | | $ | 128 | | Coal/Lignite | | | 288 | | | | 189 | | Natural gas | | | 9 | | | | 11 | | Spare parts | | | 137 | | | | 127 | | Other | | | 3 | | | | — | | | | | | | | | | | Total Inventory | | $ | 541 | | | $ | 455 | | | | | | | | | | |
| | Note 9 — | Capital Leases and Notes Receivable |
Notes receivable primarily consists of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. NRG’s notes receivable and capital leases as of December 31, 20082009, and 20072008 were as follows: | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | | | | 2008 | | 2007 | | | 2009 | | 2008 | | | | (In millions) | | | (In millions) | | | Capital Leases Receivable — non-affiliates | | | | | | | | | | | | | | | | | VEAG Vereinigte Energiewerke AG, due August 31, 2021, 11.00%(a) | | $ | 338 | | | $ | 395 | | | $ | 301 | | | $ | 338 | | Other | | | 9 | | | | — | | | | 5 | | | | 9 | | | | | | | | | | | | | Capital Leases — non-affiliates | | | 347 | | | | 395 | | | | 306 | | | | 347 | | | | | | | | | | | | | Notes Receivable — affiliates | | | | | | | | | | | | | | | | | GenConn Energy LLC, due April 30, 2009, LIBOR + 3.75%(b) — current | | | 36 | | | | — | | | | — | | | | 36 | | Kraftwerke Schkopau GBR, indefinite maturity date, 5.89%-7.00%(c) — non-current | | | 120 | | | | 126 | | | Kraftwerke Schkopau GBR, indefinite maturity date, 6.91%-7.00%(c) — non-current | | | | 122 | | | | 120 | | GCE Holding LLC which wholly-owns GenConn Energy LLC, indefinite maturity date, LIBOR +3%(d) | | | | 108 | | | | — | | | | | | | | | | | | | Notes Receivable — affiliates | | | 156 | | | | 126 | | | Notes receivable — affiliates | | | | 230 | | | | 156 | | | | | | | | | | | | | Subtotal — Capital leases and notes receivable | | | 503 | | | | 521 | | | | 536 | | | | 503 | | | | | | | | | | | | | Less current maturities: | | | | | | | | | | | | | | | | | Capital leases | | | 32 | | | | 30 | | | | 32 | | | | 32 | | Notes receivable — GenConn | | | 36 | | | | — | | | | — | | | | 36 | | | | | | | | | | | | | Subtotal — current maturities | | | 68 | | | | 30 | | | | 32 | | | | 68 | | | | | | | | | | | | | Total Capital leases and notes receivable — noncurrent | | $ | 435 | | | $ | 491 | | | $ | 504 | | | $ | 435 | | | | | | | | | | | | |
| | | (a) | | Saale Energie GmbH, or SEG, has sold 100% of its share of capacity from the Schkopau power plant to VEAG Vereinigte Energiewerke AG under a25-year contract, which is more than 83% of the useful life of the plant. This direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract. | | (b) | | In 2008, NRG has entered into a short-term $45 million note receivable facility with GenConn Energy LLC to fund project liquidity needs. | | (c) | | SEG entered into a note receivable with Kraftwerke Schkopau GBR, a partnership between Saale and E.On Kraftwerke GmbH. The note was used to fund SEG’s initial capital contribution to the partnership and to cover project liquidity shortfalls during construction of the Schkopau power plant. The note is subject to repayment upon the disposition of the Schkopau plant. | (d) | | NRG entered into a long-term $121.6 million note receivable facility with GCE Holding LLC to fund project liquidity needs. |
175
| | Note 910 — | Property, Plant, and Equipment |
NRG’s major classes of property, plant, and equipment as of December 31, 20082009 and 20072008 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | Depreciable
| | | As of December 31, | | Depreciable
| | | 2008 | | 2007 | | Lives | | | 2009 | | 2008 | | Lives | | | (In millions) | | | | | (In millions) | | | | Facilities and equipment | | $ | 12,193 | | | $ | 11,829 | | | | 1-40 Years | | | $ | 13,023 | | | $ | 12,193 | | | 1-40 Years | Land and improvements | | | 593 | | | | 584 | | | | | | | | 621 | | | | 593 | | | | Nuclear fuel | | | 225 | | | | 181 | | | | 5 Years | | | | 286 | | | | 225 | | | 5 Years | Office furnishings and equipment | | | 73 | | | | 84 | | | | 2-10 Years | | | | 153 | | | | 73 | | | 2-10 Years | Construction in progress | | | 804 | | | | 337 | | | | | | | | 533 | | | | 804 | | | | | | | | | | | | | | | Total property, plant and equipment | | | 13,888 | | | | 13,015 | | | | | | | | 14,616 | | | | 13,888 | | | | Accumulated depreciation | | | (2,343 | ) | | | (1,695 | ) | | | | | | | (3,052 | ) | | | (2,343 | ) | | | | | | | | | | | | | | Net property, plant and equipment | | $ | 11,545 | | | $ | 11,320 | | | | | | | $ | 11,564 | | | $ | 11,545 | | | | | | | | | | | | | | |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | Note 1011 — | Goodwill and Other Intangibles |
Goodwill— NRG’s goodwill arose in connection with the acquisitions of Texas Genco and Padoma.Padoma Wind Power LLC. As of December 31, 20082009 and 2007,2008, goodwill was approximately $1.7 billion and $1.8 billion, respectively.billion. In accordance with SFAS 141,ASC 805, goodwill associated with the Texas Genco acquisition decreased by $68 million during 2008 due to an adjustment to deferred tax liabilities originally established under the 2006 purchase price allocation. Goodwill is not amortized but instead tested for impairment in accordance with SFAS 142ASC 350 at thereporting-unit level. Goodwill is tested annually, typically during the fourth quarter, or more often if events or circumstances, such as adverse changes in the business climate, indicate there may be impairment. As of December 31, 2008,2009, there was no impairment to goodwill. As of December 31, 2009 and 2008, NRG had approximately $721 million and $786 million, respectively, of goodwill that is deductible for USU.S. income tax purposes in future periods. Intangible Assets— NRG acquiredThe Company’s intangible assets as part of December 31, 2009 reflect intangible assets acquired from the Company’sacquisition of Bluewater Wind and Blythe Solar in November 2009, the acquisition of Reliant Energy in May 2009, the acquisition of Texas Genco in February 2006 and established intangible assets uponthe adoption of Fresh Start reporting. Theseaccounting. For the Reliant Energy acquisition, the intangible assets include energy supply contracts, customer contracts, customer relationships, trade names, and other. The energy supply contracts consist of in-market andout-of-market contracts that are amortized based on the expected delivery under the respective contracts. The amortization expense associated with the energy supply contracts is recorded as part of cost of operations. The customer contracts are amortized to revenues, based on expected volumes to be delivered for the portfolio. The customer relationships are amortized to depreciation and amortization expense, based on the expected discounted future cash flow by year. The trade names are amortized to depreciation and amortization expense on a straight line basis over the estimated useful life. The intangible assets established with the Texas Genco acquisition and upon the adoption of Fresh Start reporting include SO2 and NOx emission allowances and certain in-market power, fuel (coal, gas, and nuclear) and water contracts. The emission allowances are amortized and recorded as a part of the cost of operations, with NOx emission allowances amortized on a straight line basis and SO2 emission allowances amortized based on units of production. The power contracts are amortized based on contracted volumes over the life of each contract and the fuel contracts are amortized over expected volumes over the life of each contract. The power contracts are amortized and recorded as part of revenues, while fuel and water contracts are amortized and recorded as part of the cost of operations. In 2009, NRG actively trades portionsbegan purchasing RGGI emission allowance credits, which are amortized based on units of the Company’s emission allowancesproduction and recorded as a part of the Company’s asset optimization strategy, with their respective costs expensed when sold. Emission allowances that the Company designates for such trading are reclassified to intangible assets held-for-sale on the balance sheet and are not amortized.of operations. 176
The following tables summarize the components of NRG’s intangible assets subject to amortization for the years ended December 200831, 2009 and 2007:2008: | | | | | | | | | | | | | | | | | | | | | | | | | | | Emission
| | | Contracts | | | | | | | | December 31, 2008 | | Allowances | | | Power | | | Fuel | | | Water | | | Other | | | Total | | | | (In millions) | | | January 1, 2008 | | $ | 916 | | | $ | 92 | | | $ | 171 | | | $ | 64 | | | $ | 2 | | | $ | 1,245 | | Additions | | | 6 | | | | — | | | | — | | | | — | | | | 3 | | | | 9 | | Transfer to held for sale | | | (6 | ) | | | — | | | | — | | | | — | | | | — | | | | (6 | ) | Fully amortized intangible assets | | | — | | | | (34 | ) | | | — | | | | (64 | ) | | | — | | | | (98 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted gross amount | | | 916 | | | | 58 | | | | 171 | | | | — | | | | 5 | | | | 1,150 | | Less accumulated amortization | | | (155 | ) | | | (58 | ) | | | (122 | ) | | | — | | | | — | | | | (335 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Net carrying amount | | $ | 761 | | | $ | — | | | $ | 49 | | | $ | — | | | $ | 5 | | | $ | 815 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Contracts | | | | | | | | | | | | | | | | Emission
| | | | | | Energy
| | | | | | | | | Customer
| | | Trade
| | | | | | | | December 31, 2009 | | Allowances | | | Power | | | Supply | | | Fuel | | | Customer | | | Relationships | | | Names | | | Other | | | Total | | | | (In millions) | | | January 1, 2009 | | $ | 916 | | | $ | 58 | | | $ | — | | | $ | 171 | | | $ | — | | | $ | — | | | $ | — | | | $ | 5 | | | $ | 1,150 | | Write-off of fully amortized intangible assets | | | (19 | ) | | | (58 | ) | | | — | | | | (88 | ) | | | — | | | | — | | | | — | | | | — | | | | (165 | ) | Acquisition of businesses | | | — | | | | — | | | | 54 | | | | — | | | | 790 | | | | 399 | | | | 178 | | | | 11 | | | | 1,432 | | Reclassification of NPNS contract to derivative | | | — | | | | — | | | | — | | | | (12 | ) | | | — | | | | — | | | | — | | | | — | | | | (12 | ) | Other | | | 22 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (2 | ) | | | 20 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted gross amount | | | 919 | | | | — | | | | 54 | | | | 71 | | | | 790 | | | | 399 | | | | 178 | | | | 14 | | | | 2,425 | | Less accumulated amortization(a) | | | (199 | ) | | | — | | | | (18 | ) | | | (48 | ) | | | (258 | ) | | | (117 | ) | | | (8 | ) | | | — | | | | (648 | ) | | | | | | | | | | | �� | | | | | | | | | | | | | | | | | | | | | | | | | | | Net carrying amount | | $ | 720 | | | $ | — | | | $ | 36 | | | $ | 23 | | | $ | 532 | | | $ | 282 | | | $ | 170 | | | $ | 14 | | | $ | 1,777 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
169
| | | (a) | | Includes annual amortization expense as described in the table below; netting of fully amortized intangible assets of $19 million and $58 million for emission allowances and power contracts, respectively; and decrease of accumulated amortization expense of $88 million as a result of the reclassification of NPNS contract to derivatives in fuel contracts. |
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Emission
| | Contracts | | | | | | | Emission
| | Contracts | | | | | | December 31, 2007 | | Allowances | | Power | | Fuel | | Water | | Other | | Total | | | December 31, 2008 | | | Allowances | | Power | | Fuel | | Water | | Other | | Total | | | | (In millions) | | | (In millions) | | | January 1, 2007 | | $ | 913 | | | $ | 92 | | | $ | 171 | | | $ | 64 | | | $ | — | | | $ | 1,240 | | | January 1, 2008 | | | $ | 916 | | | $ | 92 | | | $ | 171 | | | $ | 64 | | | $ | 2 | | | $ | 1,245 | | Additions | | | 5 | | | | — | | | | — | | | | — | | | | 2 | | | | 7 | | | | 6 | | | | — | | | | — | | | | — | | | | 3 | | | | 9 | | Sales | | | (1 | ) | | | — | | | | — | | | | — | | | | — | | | | (1 | ) | | Transfer to held for sale | | | (1 | ) | | | — | | | | — | | | | — | | | | — | | | | (1 | ) | | | (6 | ) | | | — | | | | — | | | | — | | | | — | | | | (6 | ) | Fully amortized intangible assets | | | | — | | | | (34 | ) | | | — | | | | (64 | ) | | | — | | | | (98 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted gross amount | | | 916 | | | | 92 | | | | 171 | | | | 64 | | | | 2 | | | | 1,245 | | | | 916 | | | | 58 | | | | 171 | | | | — | | | | 5 | | | | 1,150 | | Less accumulated amortization | | | (114 | ) | | | (92 | ) | | | (102 | ) | | | (64 | ) | | | — | | | | (372 | ) | | | (155 | ) | | | (58 | ) | | | (122 | ) | | | — | | | | — | | | | (335 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net carrying amount | | $ | 802 | | | $ | — | | | $ | 69 | | | $ | — | | | $ | 2 | | | $ | 873 | | | $ | 761 | | | $ | — | | | $ | 49 | | | $ | — | | | $ | 5 | | | $ | 815 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The following table presents NRG’s amortization of intangible assets for the years ended December 31, 2009, 2008 2007 and 2006:2007: | | | | | | | | | | | | | | | | | | | | | | | | | Amortization | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | | | | (In millions) | | | | | (In millions) | | | | | Emission allowances | | $ | 41 | | | $ | 40 | | | $ | 44 | | | $ | 63 | | | $ | 41 | | | $ | 40 | | Energy supply contracts | | | | 18 | | | | — | | | | — | | Fuel contracts | | | 20 | | | | 37 | | | | 65 | | | | 15 | | | | 20 | | | | 37 | | Customer contracts | | | | 258 | | | | — | | | | — | | Customer relationships | | | | 117 | | | | — | | | | — | | Trade names | | | | 8 | | | | — | | | | — | | Water contracts | | | — | | | | 36 | | | | 28 | | | | — | | | | — | | | | 36 | | | | | | | | | | | | | | | | | Total amortization in cost of operations | | $ | 61 | | | $ | 113 | | | $ | 137 | | | Total amortization | | | $ | 479 | | | $ | 61 | | | $ | 113 | | | | | | | | | | | | | | | | | Power contract amortization recorded as a reduction to operating revenues | | $ | — | | | $ | — | | | $ | 43 | | |
The following table presents estimated amortization related to NRG’s emission allowances, in-market energy supply and in-market contracts:fuel contracts, customer contracts, customer relationships and trade names: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Contracts | | | | | | | | | | Emission
| | | | | | | Emission
| | Energy
| | | | | | Customer
| | Trade
| | | | Year Ended December 31, | | Allowances | | Fuel | | Total | | | Allowances | | Supply | | Fuel | | Customer | | Relationships | | Names | | Total | | | | (In millions) | | | (In millions) | | | 2009 | | $ | 40 | | | $ | 26 | | | $ | 66 | | | 2010 | | | 52 | | | | 6 | | | | 58 | | | $ | 89 | | | $ | 3 | | | $ | 6 | | | $ | 225 | | | $ | 81 | | | $ | 12 | | | $ | 416 | | 2011 | | | 52 | | | | 2 | | | | 54 | | | | 82 | | | | 4 | | | | 2 | | | | 152 | | | | 57 | | | | 12 | | | | 309 | | 2012 | | | 45 | | | | 2 | | | | 47 | | | | 76 | | | | 5 | | | | 2 | | | | 105 | | | | 44 | | | | 12 | | | | 244 | | 2013 | | | 20 | | | | 2 | | | | 22 | | | | 77 | | | | 6 | | | | 2 | | | | 50 | | | | 31 | | | | 12 | | | | 178 | | 2014 | | | | 80 | | | | 6 | | | | 2 | | | | — | | | | 24 | | | | 12 | | | | 124 | |
177
The following table presents the weighted average remaining amortization period is 3.4 years for fuel contracts. Emission allowances are amortized based on a mix of a straight line and actual emissions emitted fromrelated to NRG’s intangible assets purchased in 2009 through the respective plants.Reliant Energy acquisition: | | | | | | | | | | | | | | | | | | | | | | | Contracts | | | | | | | | | Energy
| | | | Customer
| | Trade
| | | In years | | Supply | | Customer | | Relationships | | Names | | Total | | Weighted average remaining amortization period | | | 4.4 | | | | 2.0 | | | | 3.1 | | | | 7.7 | | | | 3.3 | |
Intangible assets held for sale — NRG records the Company’s bank of emission allowancesheld-for-use as part of the Company’s intangible assets. From time to time, management may authorize the transfer from the Company’s emission bank to intangible assetsheld-for-sale. Emission allowancesheld-for-sale as part of are included in other non current assets on the Company’s asset optimization strategy.consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31, 2008,2009, the value of emission allowancesheld-for-sale is $4$7 million and is managed within the Corporate segment. Once transferred toheld-for-sale, these emission allowances transferred are prohibited from moving back toheld-for-use. Out-of-market contracts —Due to Fresh Start accounting, as well as the acquisition of Blythe Solar, Reliant Energy and Texas Genco, NRG acquired certainout-of-market contracts. These are primarily customer contracts, energy supply, power, gas swaps, and certain coal contracts and are classified as non-current liabilities on NRG’s consolidated balance sheet. Both theThe gas swap, power and powercustomer contracts are amortized to revenues, while the energy supply and coal contracts are amortized to cost of operations. 170
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes the estimated amortization related to NRG’sout-of-market contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Contracts | | | | | | | | | | | | | | | | | | | | | | | | Energy
| | | | | | | | | | Year Ended December 31, | | Coal | | Gas Swaps | | Power Contracts | | Total | | | Customer | | Supply | | Coal | | Gas Swap | | Power | | Total | | | | (In millions) | | | (In millions) | | | 2009 | | $ | 19 | | | $ | 56 | | | $ | 80 | | | $ | 155 | | | 2010 | | | 6 | | | | 51 | | | | 28 | | | | 85 | | | $ | 8 | | | $ | 39 | | | $ | 6 | | | $ | 51 | | | $ | 27 | | | $ | 131 | | 2011 | | | — | | | | — | | | | 21 | | | | 21 | | | | 7 | | | | 11 | | | | — | | | | — | | | | 20 | | | | 38 | | 2012 | | | — | | | | — | | | | 22 | | | | 22 | | | | 1 | | | | 6 | | | | — | | | | — | | | | 21 | | | | 28 | | 2013 | | | — | | | | — | | | | 19 | | | | 19 | | | | — | | | | 3 | | | | — | | | | — | | | | 19 | | | | 22 | | 2014 | | | | — | | | | — | | | | — | | | | — | | | | 16 | | | | 16 | |
178
| | Note 1112 — | Debt and Capital Leases |
Long-term debt and capital leases consist of the following: | | | | | | | | | | | | | | | | As of December 31, | | Interest
| | | | | | | | | | | | | | 2008 | | 2007 | | Rate | | | As of December 31, | | Interest
| | | (In millions except rates) | | | 2009 | | 2008 | | Rate | | | (In millions except rates) | NRG Recourse Debt: | | | | | | | | | | | | | | | | | | | | | | | Senior notes, due 2019(a) | | | $ | 689 | | | $ | — | | | 8.50 | Senior notes, due 2017 | | $ | 1,100 | | | $ | 1,100 | | | | 7.375 | | | | 1,100 | | | | 1,100 | | | 7.375 | Senior notes, due 2016 | | | 2,400 | | | | 2,400 | | | | 7.375 | | | | 2,400 | | | | 2,400 | | | 7.375 | Senior notes, due 2014(a)(b) | | | 1,217 | | | | 1,199 | | | | 7.25 | | | | 1,211 | | | | 1,217 | | | 7.25 | Term Loan Facility, due 2013 | | | 2,642 | | | | 2,816 | | | | L+1.5 for 2008/ L+1.75 for 2007 | (f) | | | 2,213 | | | | 2,642 | | | L+1.75/L+1.5(f) | NRG Non-Recourse Debt: | | | | | | | | | | | | | | | | | | | | | | | CSF, notes and preferred interests, due 2009 and 2010(b) | | | 332 | | | | 333 | | | | 5.45-13.23 | | | NRG Peaker Finance Co. LLC, bonds, due June 2019(c) | | | 229 | | | | 235 | | | | L+1.07 | (f) | | NRG Energy Center Minneapolis LLC, senior secured notes, due 2013 and 2017(d) | | | 86 | | | | 97 | | | | 7.12-7.31 | | | CSF, notes and preferred interests, due 2010(c) | | | | 188 | | | | 325 | | | 5.45-12.65 for 2009/5.45-13.23 for 2008 | NRG Peaker Finance Co. LLC, bonds, due 2019(d) | | | | 220 | | | | 229 | | | L+1.07(f) | NRG Energy Center Minneapolis LLC, senior secured notes, due 2013 and 2017(e) | | | | 75 | | | | 86 | | | 7.12-7.31 | Dunkirk Power LLC tax-exempt bonds, due 2042 | | | | 52 | | | | — | | | Weekly rate based on SIFMA rate(g) | NRG Connecticut Peaking LLC, equity bridge loan facility, due 2010 and 2011 | | | | 108 | | | | — | | | L + 2(f) | Other | | | 20 | | | | — | | | | L + 0.45 | (f) | | | 39 | | | | 20 | | | L + 0.45(f) | | | | | | | | | | | | Subtotal long term debt | | | 8,026 | | | | 8,180 | | | | | | | Subtotal long-term debt | | | | 8,295 | | | | 8,019 | | | | Capital leases: | | | | | | | | | | | | | | | | | | | | | | | Saale Energie GmbH, Schkopau capital lease, due 2021 | | | 142 | | | | 181 | | | | | | | | 123 | | | | 142 | | | | | | | | | | | | | | | Subtotal | | | 8,168 | | | | 8,361 | | | | | | | | 8,418 | | | | 8,161 | | | | Less current maturities(e) | | | 464 | | | | 466 | | | | | | | Less current maturities(h) | | | | 571 | | | | 464 | | | | | | | | | | | | | | | Total | | $ | 7,704 | | | $ | 7,895 | | | | | | | $ | 7,847 | | | $ | 7,697 | | | | | | | | | | | | | | |
| | | (a) | | Includes discount of $(11) million as of December 31, 2009. On June 5, 2009, NRG issued these $700 million aggregate principal amount bonds resulting in a yield of 8.75%. | (b) | | Includes fair value adjustment as of December 31, 2009 and 2008 and 2007 of $17$11 million and $(1)$17 million, respectively, reflecting an adjustment for an interest rate swap. The swap was re-designated from the retired 2nd priority note to this note as part of the financing related to the Texas Genco acquisition. | (c) | (b) | Includes discount of $(1)$(2) million and $(8) million as of December 31, 2008.2009 and 2008, respectively. | (d) | (c) | Includes discount of $(37)$(31) million and $(43)$(37) million as of December 31, 20082009 and 2007,2008, respectively. | (e) | (d) | Includes premium of $2 million and $3 million as of December 31, 20082009 and 2007, respectively.2008. | (f) | | L+ equals LIBOR plus x%. | (e) (g) | | Securities Industry and Financial Markets Association, or SIFMA. | (h) | | Includes discount of $6 million and $7$(6) million on the NRG Peaker Finance debt as of December 31, 20082009 and 2007, respectively,2008; discount of $(1) million on the CSF notes and preferred interests as of December 31, 2009 and a premium of $1 million on NRG Energy Center Minneapolis debt as of December 31, 20082009 and 2007. |
| | (f) | L+ equals LIBOR plus x%2008. |
171179
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NRG Recourse Debt
Senior Notes NRG has threefour outstanding issuances of senior notes, or Senior Notes, under an Indenture, dated February 2, 2006, or the Indenture, between NRG and Law Debenture Trust Company of New York, as trustee: (i) 7.25% senior notes, issued February 2, 2006 and due February 1, 2014, or the 2014 Senior Notes; (ii) 7.375% senior notes, issued February 2, 2006 and due February 1, 2016, or the 2016 Senior Notes; (iii) 7.375% senior notes, issued November 21, 2006 and due January 15, 2017, or the 2017 Senior Notes; and (iv) 8.5% senior notes, issued June 5, 2009 and due June 15, 2019, or the 2019 Senior Notes. Supplemental indentures to the series of notes have been issued to add newly formed or acquired subsidiaries as guarantors. The Indentures and the form of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG. The Indentures also provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRG and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately. The terms of the Indentures, among other things, limit NRG’s ability and certain of its subsidiaries’ ability to: | | | | • | return capital to shareholders; | | | • | grant liens on assets to lenders; and | | | • | incur additional debt. |
Interest is payable semi-annually on the Senior Notes until their maturity dates. In addition, the Company entered into a fixed to floating interest rate swap in 2004 with a notional amount as of December 31, 20082009 of $400 million and a maturity date of December 15, 2013. At any time prior to February 1, 2009, NRG may redeem up to 35% of the aggregate principal amount of the 2014 Senior Notes and the 2016 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.25% of the principal amount, in the case of the 2014 Senior Notes, and 107.375% of the principal amount, in the case of the 2016 Senior Notes. In addition, NRG may redeem the 2014 Senior Notes and 2016 Senior Notes at the redemption prices expressed as a percentage of the principal amount redeemed set forth below, plus accrued and unpaid interest on the notes redeemed.
Prior to February 1, 2010, NRG may redeem all or a portion of the 2014 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued interest. The premium is the greater ofof: (i) 1% of the principal amount of the note, or (ii) the excess of the principal amount of the note over the following: the present value of 103.625% of the note, plus interest payments due on the note from the date of redemption through February 1, 2010, discounted at a Treasury rate plus 0.50%. On or after February 1, 2010, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth below, plus accrued and unpaid interest on the notes redeemed to the applicable redemption date: | | | | | | | Redemption
| | Redemption Period | | Percentage | | | February 1, 2010 to February 1, 2011 | | | 103.625 | % | February 1, 2011 to February 1, 2012 | | | 101.813 | % | February 1, 2012 and thereafter | | | 100.000 | % |
172
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Prior to February 1, 2011, NRG may redeem all or a portion of the 2016 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued interest. The premium is the greater ofof: (i) 1% of the principal amount of the note, or (ii) the excess of the principal amount of the note over the following: the present value of 103.688% of the note, plus interest payments due on the note from the date of redemption through February 1, 2011, discounted at a Treasury rate plus 0.50%. On or after February 1, 2011, NRG may redeem some or all of the notes at 180
redemption prices expressed as percentages of principal amount as set forth below, plus accrued and unpaid interest on the notes redeemed to the applicable redemption date: | | | | | | | Redemption
| | Redemption Period | | Percentage | | | February 1, 2011 to February 1, 2012 | | | 103.688 | % | February 1, 2012 to February 1, 2013 | | | 102.458 | % | February 1, 2013 to February 1, 2014 | | | 101.229 | % | February 1, 2014 and thereafter | | | 100.000 | % |
Prior to January 15, 2012, NRG may redeem up to 35% of the 2017 Senior Notes with net cash proceeds of certain equity offerings at a price of 107.375%, provided at least 65% of the aggregate principal amount of the notes issued remain outstanding after the redemption. Prior to January 15, 2012, NRG may redeem all or a portion of the Senior Notes at a price equal to 100% of the principal amount of the notes redeemed, plus a premium and any accrued and unpaid interest. The premium is the greater ofof: (i) 1% of the principal amount of the note, or (ii) the excess of the principal amount of the note over the following: the present value of 103.688% of the note, plus interest payments due on the note from the date of redemption through January 15, 2012, discounted at a Treasury rate plus 0.50%. In addition, on or after January 15, 2012, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth below, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: | | | | | | | Redemption
| | Redemption Period | | Percentage | | | February 1, 2012 to February 1, 2013 | | | 103.688 | % | February 1, 2013 to February 1, 2014 | | | 102.458 | % | February 1, 2014 to February 1, 2015 | | | 101.229 | % | February 1, 2015 and thereafter | | | 100.000 | % |
Prior to June 15, 2012, NRG may redeem up to 35% of the aggregate principal amount of the 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.5% of the principal amount. Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 104.25% of the note, plus interest payments due on the note from the date of redemption through June 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after June 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: | | | | | | | Redemption
| Redemption Period | | Percentage | June 15, 2014 to June 14, 2015 | | | 104.25 | % | June 15, 2015 to June 14, 2016 | | | 102.83 | % | June 15, 2016 to June 14, 2017 | | | 101.42 | % | June 15, 2017 and thereafter | | | 100.00 | % |
Senior Credit Facility As of December 31, 2008,2009, NRG has a Senior Credit Facility which is comprised of a senior first priority secured term loan, or the Term Loan Facility, a $1.0 billion senior first priority secured revolving credit facility, or the Revolving Credit Facility, and a $1.3 billion senior first priority secured synthetic letter of credit facility, or the Synthetic Letter of Credit Facility. The Senior Credit Facility is the result of a refinancing by the Company which occurredwas last amended on June 8, 2007 and for which resulted in a charge of $35 million which was recorded to the Company’s results of operations for the year ended December 31, 2007, primarily related to the write-off of previously deferred financing costs. Among other things, this refinancing resulted in a 0.25% reduction on the spread that the Company pays on its Term Loan Facility and Synthetic Letter of Credit Facility. The pricing on the Company’s Term Loan Facility and Synthetic Letter of Credit Facility is also subject to further reductions upon the achievement of certain financial ratios. On December 31, 2007, the Company used cash on hand to prepay, without penalty, $300 million of its Term Loan Facility under the Senior Credit Facility. With this prepayment, the Company met a financial ratio by the end of 2007 that resulted in a further 0.25% reduction in the interest rate on both its Term Loan Facility and Synthetic Letter of Credit Facility. The prepayment was credited against the Company’s mandatory annual offer required under the Senior Credit Facility, as hereinafter discussed. As of December 31, 2008,2009, NRG had issued $440$717 million of letters of credit under the Synthetic Letter of Credit Facility, leaving $860$583 million available for future issuances. There were no letters of credit issued underUnder the
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Company’s Revolving Credit Facility as of 181
December 31, 2008,2009, NRG had issued letters of credit totaling $95 million, leaving $1.0 billion$905 million available for borrowings, of which approximately $900$805 million could be used to issue additional letters of credit. The Term Loan Facility matures on February 1, 2013, and amortizes in 27twenty-seven consecutive equal quarterly installments of 0.25% term loan commitments, beginning June 30, 2006, with the balance payable on the seventh anniversary thereof. The full amount of the Revolving Credit Facility will mature on February 2, 2011. The Synthetic Letter of Credit Facility will mature on February 1, 2013, and no amortization will be required in respect thereof. NRG has the option to prepay the Senior Credit Facility in whole or in part at any time. Beginning in 2008, NRG must annually offer a portion of its excess cash flow (as defined in the Senior Credit Facility) to its first lien lenders under the Term Loan Facility. The percentage of the excess cash flow offered to these lenders is dependent upon the Company’s consolidated leverage ratio (as defined in the Senior Credit Facility) at the end of the preceding year. Of the amount offered, the first lien lenders must accept 50%, while the remaining 50% may either be accepted or rejected at the lenders’ option. The 2010 mandatory offer related to 2009 is expected to be $430 million, against which the Company made a prepayment of $200 million in December 2009. Based on current credit market conditions, the Company expects that its lenders will accept in full the 20092010 mandatory offer related to 2008,2009, and, as such, the Company has reclassified approximately $197$230 million of Term Loan Facility maturity from a non-current to a current liability as of December 31, 2008.2009. The 20082009 mandatory offer and prepayment related to 2007 was $446 million, against which the Company made a prepayment of $300 million in December 2007. Of the remaining $146 million, the lenders accepted a repayment of $143 million2008 paid in March 2008. The amount retained by the Company2009 was used for investments, capital expenditures and other items as permitted by the Senior Credit Facility. As of December 31, 2007, the Company reclassified approximately $146 million of the Term Loan Facility maturity from a non-current to a current liability.$197 million.
The Senior Credit Facility is guaranteed by substantially all of NRG’s existing and future direct and indirect subsidiaries, with certain customary oragreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries, and certain other subsidiaries. The capital stock of substantially all of NRG’s subsidiaries, with certain exceptions for unrestricted subsidiaries, foreign subsidiaries, and project subsidiaries, has been pledged for the benefit of the Senior Credit Facility’s lenders. The Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG’s project affiliates that have non-recourse debt financing, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG’s foreign subsidiaries. The Senior Credit Facility contains customary covenants, which, among other things, require NRG to meet certain financial tests, including minimum interest coverage ratio and a maximum leverage ratio on a consolidated basis, and limit NRG’s ability to: | | | | • | incur indebtedness and liens and enter into sale and lease-back transactions; | | | • | make investments, loans and advances; and | | | • | return capital to shareholders. |
Interest Rate Swaps — In May 2009, NRG entered into a series of forward-starting interest rate swaps. These interest rate swaps become effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company will pay its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which mature on February 1, 2013, is $900 million. In 2006 in connection with the Senior Credit Facility, NRG entered into aanother series of forward-setting interest rate swaps in 2006 which are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives quarterly the equivalent of a floating interest payment based on a3-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made quarterly, and the LIBOR is determined in advance of each interest period. While the 182
notional value of each of the swaps does not vary over time, the swaps are designed to mature sequentially.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The notional amounts and maturities of each tranche of these swaps as of December 31, 20082009, are as follows: | | | | | Maturity | | Notional Value | | | March 31, 2009 | | $ | 150 million | | March 31, 2010 | | $ | 190 million | | March 31, 2011 | | $ | 1.55 billion | |
Dunkirk Power LLC Tax-Exempt Bonds On April 15, 2009, NRG executed a $59 million tax-exempt bond financing, or the Dunkirk bonds, through its wholly-owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial Development Agency and will be used for construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially bear weekly interest based on the Securities Industry and Financial Markets Association, or SIFMA, rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit under the Company’s Revolving Credit Facility covering amounts drawn on the facility. The proceeds received through December 31, 2009 were $52 million, with the remaining balance being released over time as construction costs are paid. On February 1, 2010, the Company fixed the rate on the Dunkirk bonds at 5.875%. Interest will be payable semiannually. In addition, the $59 million letter of credit issued by NRG in support of the bonds was cancelled and replaced with a parent guarantee. NRG Non-Recourse Debt Debt Related to Capital Allocation Program During the third quarterIn 2006, the Company formed CSF I and CSF II, two wholly-owned unrestricted subsidiaries that are both consolidated by NRG. Their purpose was to repurchase an aggregate of $500 million in shares of NRG’s common stock in the public markets or in privately negotiated transactions in connection with the Company’s Capital Allocation Program. These subsidiaries were funded with a combination of cash from NRG, and a mix of notes and preferred interests issued to CS.CS, or the CSF Debt. Both the notes and the preferred interests are non-recourse debt to NRG or any of its restricted subsidiaries, with the debt collateralized by the NRG common stock held by CSF I and CSF II. In addition, the assets of CSF I and CSF II are not available to the creditors of NRG or the Company’s other subsidiaries. At December 31, 2008, CSF I and CSF II held 12,441,973 and 9,528,930 shares of NRG common stock, respectively, reflected within treasury stock on the Company’s consolidated balance sheet.
As of December 31, 2007,From inception through July 2008, the notes and preferred interests of CSF I and II contained a feature considered an embedded derivative, which requiresrequired NRG to pay to CS at maturity, either in cash or stock at NRG’s option, the excess of NRG’s then current stock price over a Threshold Price. ThisFrom inception through November 24, 2009, the notes and preferred interests of CSF II also contained a feature considered an embedded derivative with terms similar to the CSF I embedded derivative. The Threshold Price is the price of NRG’s stock in excess of a compound annual growth rate, or CAGR, of 20% beyond the volume-weighted average share price of the stock at the time of repurchase. Although this feature iswas considered a derivative, it iswas exempt from derivative accounting under the guidance in paragraph 11(a) of SFAS 133,ASC 815, and willwas only be recognized upon settlement. As a result of the early settlement described below in August 2008 by the CSF I extension and the unwinding of the CSF II debt in November 2009, both described below, there were no notes or preferred interests containing an embedded derivative feature as of December 31, 2008 only the notes and preferred interests of CSF II contain the embedded derivative feature. This CSF II embedded derivative has a Threshold Price of $40.80 per share and the maximum number of shares collateralizing the embedded derivatives is 7,623,211 shares. As of December 31, 2008, based on the Company’s stock price, the CSF II embedded derivative was out-of-the money and had no redemption value.2009.
CSF I Extension — In March 2008, the Company executed an arrangement with CS to extend the notes and preferred interest maturities of the CSF I Debt from October 2008 to June 2010. In addition, the settlement date of the embedded derivative, or CSF I CAGR, was extended 30 days to early December 2008. As part of this extension arrangement, the Company contributed 795,503 treasury shares to CSF I as additional collateral to maintain a blended interest rate in the CSF I facility of approximately 7.5%. Accordingly, theThe amount due at maturity in June 2010, including accrued interest, for the CSF I notes and preferred interestsDebt will be $248$249 million. In August 2008, the Company amended the CSF I notes and preferred interestsDebt to early settle the CSF I CAGR. Accordingly, NRG made a cash payment of $45 million to CS for the benefit of CSF I, which was recorded to interest expenseadditional paid in capital on the Company’s consolidated balance sheet as of December 31, 2008. See further discussion below regarding the adoption of FSP APB14-1. Share Lending Agreements — On February 20, 2009, CSF I and II entered into Share Lending Agreements, or SLAs, with affiliates of CS relating to the shares of NRG common stock currently held by CSF I and II in connection with the CSF Debt. The Company entered into the SLAs due to a lack of liquidity in the stock borrow 183
market for NRG shares that existed at that time and in order to maintain the intended economic benefits of the CSF Debt agreements. The SLAs permitted affiliates of CS to borrow up to the total number of shares of NRG common stock held by CSF I and II. CSF I and II loaned affiliates of CS 6,600,000 and 5,400,000 shares, respectively, of NRG common stock under the SLAs. Shares borrowed by affiliates of CS under the SLAs were used to replace shares borrowed by affiliates of CS from third parties in connection with CS hedging activities related to the financing agreements. The shares are expected to be returned upon the termination of the financing agreements. Until the shares are returned, the shares will be treated as outstanding for corporate law purposes, and accordingly, the holders of the borrowed shares will have all of the rights of a holder of the Company’s Consolidated Statementoutstanding shares, including the right to vote the shares on all matters submitted to a vote of Operations.the Company’s stockholders. However, because the CS affiliates must return all borrowed shares (or identical shares), the borrowed shares are not considered outstanding for the purpose of computing and reporting the Company’s basic or diluted earnings per share. CSF II Debt Maturity — On November 24, 2009, the Company completed the unwinding of the CSF II Debt, remitting a cash payment to CS of the $181 million outstanding principal and interest, while CS returned 5,400,000 shares of NRG common stock borrowed under the SLAs, and then released all 9,528,930 common shares held as collateral for the CSF II Debt. The CSF II Debt contained an embedded derivative feature, or CFS II CAGR, which could have required NRG to pay CS at maturity, either in cash or stock at NRG’s option, the excess of NRG’s then current stock price over a Threshold Price of $40.80 per share. On November 24, 2009, it was determined that no payment was required on the CSF II CAGR at which point the CSF II CAGR expired. At December 31, 2009, CSF I held 12,441,973 shares of NRG common stock of which 6,600,000 shares lent to affiliates of CS under the SLAs, with a fair value of $156 million, are considered outstanding and 5,841,973 shares are reflected within treasury stock on the Company’s consolidated balance sheet. Notes — As of December 31, 2008 and 2007,2009, CSF I and II had a total of $249$137 million in notes in connection with Phase I of the Capital Allocation Program thatwhich mature in two tranches: $112 million for CSF II in October 2009, plus accrued interest at an annual rate of 6.11%, and the balance of $137 million for CSF I in June 2010, plus accrued interest at an annual rate of 5.45%. As of December 31, 2008, CSF I and II had a total of $249 million in notes outstanding in connection with Phase I. Preferred Interests — As of December 31, 2008 and 2007,2009, CSF I had a total of $53 million in preferred interests issued and outstanding by CSF I and II were approximately $84 million to CS. These preferred interests are classified as a liability per SFAS No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,because they embody a fixed unconditional obligation that these two unrestricted subsidiaries must settle. The
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
preferred interests alsowhich mature in two tranches: $31 million for CSF II in October 2009, plus accrued interest at an annual rate of 13.23%, and the balance of $53 million for CSF I in June 2010, plus accrued interest at an annual rate of 12.65%. As of December 31, 2008, CSF I and II had a total of $84 million in preferred interests issued and outstanding. The preferred interests are classified as a liability per ASC 480,Distinguishing Liabilities from Equity,or ASC 480, because they embody a fixed unconditional obligation that the unrestricted subsidiaries must settle.
Adoption of FSP APB14-1— As discussed in Note 2,Summary of Significant Accounting Policies, the Company adopted FSP APB14-1 on January 1, 2009, which has been incorporated in ASC 470 and ASC 825. The following table summarizes certain information related to the CSF Debt in accordance with ASC 470: | | | | | | | | | | | December 31,
| | | December 31,
| | | | 2009 | | | 2008 | | | | (In millions) | | | Equity Component | | | | | | | | | Additional Paid-in Capital | | $ | — | | | $ | 14 | | | | | | | | | | | Liability Component | | | | | | | | | Principal amount | | $ | 190 | | | $ | 333 | | Unamortized discount | | | (2 | ) | | | (8 | ) | | | | | | | | | | Net carrying amount | | $ | 188 | | | $ | 325 | | | | | | | | | | |
The unamortized discount will be amortized through the maturity of the CSF Debt. The CSF II debt matured in November 2009 and the CSF I debt has a maturity date of June 2010. Interest expense for the CSF Debt, including the debt discount amortization for the years ended December 31, 2009, 2008, and 2007 was $33 million, $37 million, and $40 million, respectively. The effective interest rate as of December 31, 2009, was 11.4% for the CSF I debt. The effective interest rate as of December 31, 2008, was 11.4% for the CSF I debt and 12.1% for the CSF II debt. 184
Project Financings The following are descriptions of certain indebtedness of NRG’s project subsidiaries that remain outstanding as of December 31, 2008.2009. The indebtedness described below is non-recourse to NRG, unless otherwise noted. TANE Facility On February 24, 2009, Nuclear Innovation North America LLC, or NINA, executed an EPC agreement with Toshiba American Nuclear Energy Corporation, or TANE, which specifies the terms under which STP Units 3 and 4 will be constructed. Concurrent with the execution of the EPC agreement, NINA and TANE entered into a credit facility, or the TANE Facility, wherein TANE has committed up to $500 million to finance purchases of long-lead materials and equipment for the construction of STP Units 3 and 4. The TANE Facility matures on February 24, 2012, subject to two renewal periods, and provides for customary events of default, which include, among others: nonpayment of principal or interest; default under other indebtedness; the rendering of judgments; and certain events of bankruptcy or insolvency. Outstanding borrowings will accrue interest at LIBOR plus 3%, subject to a ratings grid, and are secured by substantially all of the assets of and membership interests in NINA and its subsidiaries. As of December 31, 2009, no amounts have been borrowed under the TANE Facility. GenConn Energy LLC related financings On April 27, 2009, NRG Connecticut Peaking LLC, a wholly-owned subsidiary of NRG, closed on an equity bridge loan facility, or EBL, in the amount of $121.5 million from a syndicate of banks. The purpose of the EBL is to fund the Company’s proportionate share of the project construction costs required to be contributed into GenConn Energy LLC, or GenConn, a 50% equity method investment of the Company. The EBL, which is fully collateralized with a letter of credit issued under the Company’s Synthetic Letter of Credit Facility covering amounts drawn on the facility, will bear interest at a rate of LIBOR plus 2% on drawn amounts. The EBL will mature on the earlier of Middletown’s commercial operations date or July 26, 2011. The EBL also requires mandatory prepayment of the portion of the loan utilized to pay costs of the Devon project, of approximately $54 million, on the earlier of Devon’s commercial operations date, currently anticipated to be June 2010, or January 27, 2011. The proceeds of the EBL received through December 31, 2009, were $108 million and the remaining amounts will be drawn as necessary. Borrowings of an equity method investment — In April 2009, GenConn, a variable interest entity, secured financing for 50% of the Devon and Middletown project construction costs through a7-year term loan facility, and also entered into a5-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving facility. In August 2009, GenConn began to draw under the GenConn Facility to cover costs related to the Devon project and as of December 31, 2009, has drawn $48 million. Other In 2008, NINA and NRG Repowering Holdings LLC, or NRG Repowering, each obtained a $20 million revolving credit facility to provide working capital which permits NINA and NRG Repowering to make cash draws or issue letters of credit. The facilities mature on April 21, 201130, 2010, for NINA and August 12, 2011, for NRG Repowering. The facilities provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the facility; the rendering of judgments to pay certain amounts of money against NINA or NRG Repowering and their subsidiaries; and certain events of bankruptcy or insolvency. Borrowings under the facilities accrue interest at LIBOR or a base rate, plus a spread and are securedsupported by substantially alla letter of the assets of the respective borrower.credit issued by NRG. As of December 31, 2009, and 2008, NINA and NRG Repowering each had borrowed approximately $20 million and $10 million.million, respectively. As of December 31, 2009, and 2008, NRG Repowering had borrowed approximately $19 million and $10 million, respectively. As of December 31, 2009, NRG Repowering also had outstanding approximately $1 million in letters of credit. 185
Peakers In June 2002, NRG Peaker FinancingFinance Company LLC, or Peakers, an indirect wholly-owned subsidiary, issued $325 million in floating rate bonds due June 2019. Peakers subsequently swapped such floating rate debt for fixed rate debt at an all-in cost of 6.67% per annum. Principal, interest, and swap payments arewere originally guaranteed by Syncora Guarantee Inc., successor in interest to XL Capital Assurance, through a financial guaranty insurance policy. In 2009, Assured Guaranty Mutual Corp assumed the responsibility as the bond insurer and controlling party. Syncora Guarantee Inc. continues to be the swap insurer. These notes are also secured by, among other things, substantially all of the assets of and membership interests in Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC, and NRG Rockford Equipment LLC. As of December 31, 2008,2009, approximately $266$251 million in principal remained outstanding on these bonds. Upon emergence from bankruptcy, NRG issued a $36 million letter of credit to the Peakers’ collateral agent. The letter of credit may be drawn if the project is unable to meet principal or interest payments. There are no provisions requiring NRG to replenish the letter of credit if it is drawn. On December 10, 2009, the collateral agent drew approximately $0.6 million on the letter of credit to meet the debt service requirements. NRG Thermal NRG owns and operates its thermal business through a wholly-owned subsidiary holding company, NRG Thermal LLC, or NRG Thermal. In August 1993, the predecessor entity to NRG Thermal’s largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG Thermal Minneapolis, issued $84 million of 7.31% senior secured notes due June 2013, of which approximately $31$25 million remained outstanding as of December 31, 2008.2009. In July 2002, NRG Thermal Minneapolis issued an additional $55 million of 7.25% Series A notes due August 2017, of which approximately $39$37 million remained outstanding as of December 31, 2008,2009, and $20 million of 7.12% Series B notes due August 2017, of which approximately $14$13 million remained outstanding as of December 31, 2008.2009. This indebtedness is secured by substantially all of the assets of NRG Thermal Minneapolis. NRG Thermal has guaranteed the indebtedness, and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal’s subsidiaries.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Capital Leases Saale Energie GmbH Saale Energie GmbH, or SEG, an NRG wholly-owned subsidiary, has a 41.9% participation in Schkopau through NRG’s interest in the Kraftwerke Schkopau GbR, or KSGbR, partnership. Under the terms of a Use and Benefit Fee Agreement, SEG and the other partner to the project, E.ON Kraftwerke GmbH, are required to fund debt service and certain other costs resulting from the construction and financing of Schkopau. The Use and Benefit Fee Agreement is treated as a capital lease under USU.S. GAAP. Calls for funds are made to the partners based on their participation interest as cash is needed. As of December 31, 2008,2009, the capital lease obligation at SEG was approximately $142$123 million. The KSGbR issued debt to fund Schkopau pursuant to multiple facilities totaling approximately €785 million. As of December 31, 2008,2009, approximately €185€141 million (approximately $258$202 million) remained outstanding at Schkopau. Interests on the individual loans accrue at fixed rates averaging 5.30%4.26% per annum, with maturities occurring between 20092010 and 2015. SEG remains liable to the lenders as a partner in KSGbR, but there is no recourse to NRG. 186
Consolidated Annual Maturities and Future Minimum Lease Payments Annual payments based on the maturities of NRG’s long-term debt and capital leases for the years ending after December 31, 20082009 are as follows: | | | | | | | | | | | (In millions) | | | (In millions) | | | 2009 | | $ | 464 | | | 2010 | | | 258 | | | $ | 571 | | 2011 | | | 85 | | | | 143 | | 2012 | | | 67 | | | | 70 | | 2013 | | | 2,352 | | | | 1,926 | | 2014 | | | | 1,250 | | Thereafter | | | 4,942 | | | | 4,458 | | | | | | | | | Total | | $ | 8,168 | | | $ | 8,418 | | | | | | | | |
NRG’s future minimum lease payments for capital leases included above as of December 31, 20082009, are as follows: | | | | | | | | | | | (In millions) | | | (In millions) | | | 2009 | | $ | 87 | | | 2010 | | | 23 | | | $ | 28 | | 2011 | | | 14 | | | | 16 | | 2012 | | | 13 | | | | 14 | | 2013 | | | 13 | | | | 13 | | 2014 | | | | 14 | | Thereafter | | | 172 | | | | 107 | | | | | | | | | Total minimum obligations | | | 322 | | | | 192 | | Interest | | | 180 | | | | 69 | | | | | | | | | Present value of minimum obligations | | | 142 | | | | 123 | | Current portion | | | 72 | | | | 22 | | | | | | | | | Long-term obligations | | $ | 70 | | | $ | 101 | | | | | | | | |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | Note 1213 — | Asset Retirement Obligations |
NRG’s AROs are primarily related to the future dismantlement of equipment on leased property and environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities. In addition, NRG has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations. See Note 7,Nuclear Decommissioning Trust Fund,for a further discussion of NRG’s nuclear decommissioning obligations. Consequently, accretion for the nuclear decommissioning ARO and amortization of the related ARO asset are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income, consistent with regulatory treatment. The following table represents the balance of ARO obligations as of December 31, 2009, and 2008, along with the additions, reductions and accretion related to the Company’s ARO obligations for the year ended December 31, 2009: | | | | | | | Total | | | | (In millions) | | | Balance as of December 31, 2008 | | $ | 393 | | Additions | | | 3 | | Revisions in estimated cashflows | | | (5 | ) | Accretion — Expense | | | 8 | | Accretion — Nuclear decommissioning | | | 16 | | | | | | | Balance as of December 31, 2009 | | $ | 415 | | | | | | |
187
| | Note 14 — | Benefit Plans and Other Postretirement Benefits |
NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation by eligible Texas based employees. NRG expects to contribute approximately $60$18 million to the Company’s three pension plans in 2009, $29 million of which related to the Company’s 2008 benefit obligation as a result of the weak market performance of plan assets in 2008.2010. NRG Plans for Bargained and Non-bargained Employees — Substantially all employees hired prior to December 5, 2003, were eligible to participate in NRG’s legacy defined benefit pension plans. The Company initiated a noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. Generally, these are groups that were acquired prior to 2004 and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements. Texas Genco Retirement Plan — The Texas region’s pension plan is a noncontributory defined benefit pension plan that provides a final average pay benefit or cash balance benefit, where the participant receives the more favorable of the two formulas, based on all years of service. In addition, employees who were hired prior to 1999 are also eligible for grandfathered benefits under a final average pay formula. In most cases, the benefits under the grandfathered formula were frozen on December 31, 2008. NRG’s Texas region employees are also covered under an unfunded postretirement health and welfare plan. Each year, employees receive a fixed credit of $750 to their account plus interest. Certain grandfathered employees will receive additional credits through 2008. At retirement, the employees may use their accounts to purchase retiree medical and dental benefits from NRG. NRG’s costs are limited to the amounts earned in the employee’s account; all other costs are paid by the participant. NRG Defined Benefit Plans The net annual periodic pension cost related to NRG domestic pension and other postretirement benefit plans include the following components: | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | Pension Benefits | | | | | Pension Benefits | | | | | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | | | | (In millions) | | | | | (In millions) | | | | | Service cost benefits earned | | $ | 14 | | | $ | 15 | | | $ | 17 | | | $ | 12 | | | $ | 14 | | | $ | 15 | | Interest cost on benefit obligation | | | 18 | | | | 17 | | | | 15 | | | | 20 | | | | 18 | | | | 17 | | Expected return on plan assets | | | (14 | ) | | | (11 | ) | | | (7 | ) | | | (16 | ) | | | (14 | ) | | | (11 | ) | Amortization of unrecognized net gain | | | (1 | ) | | | — | | | | — | | | | 1 | | | | (1 | ) | | | — | | | | | | | | | | | | | | | | | Net periodic benefit cost | | $ | 17 | | | $ | 21 | | | $ | 25 | | | $ | 17 | | | $ | 17 | | | $ | 21 | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Year Ended December 31,
| | | | Other Postretirement Benefits | | | | 2009 | | | 2008 | | | 2007 | | | | (In millions) | | | Service cost benefits earned | | $ | 2 | | | $ | 2 | | | $ | 2 | | Interest cost on benefit obligation | | | 6 | | | | 6 | | | | 5 | | Amortization of unrecognized prior service cost | | | 1 | | | | 1 | | | | — | | | | | | | | | | | | | | | Net periodic benefit cost | | $ | 9 | | | $ | 9 | | | $ | 7 | | | | | | | | | | | | | | |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | Year Ended December 31, | | | | Other Postretirement Benefits | | | | 2008 | | | 2007 | | | 2006 | | | | (In millions) | | | Service cost benefits earned | | $ | 2 | | | $ | 2 | | | $ | 3 | | Interest cost on benefit obligation | | | 6 | | | | 5 | | | | 4 | | Amortization of unrecognized prior service cost | | | 1 | | | | — | | | | — | | | | | | | | | | | | | | | Net periodic benefit cost | | $ | 9 | | | $ | 7 | | | $ | 7 | | | | | | | | | | | | | | |
A comparison of the pension benefit obligation, other post retirement benefit obligations, and related plan assets as of December 31, 20082009 and 20072008 for NRG’s plans on a combined basis is as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | | | As of December 31, | | | | | | | Other Postretirement
| | | | Pension Benefits | | Other Postretirement Benefits | | | Pension Benefits | | Benefits | | | | 2008 | | 2007 | | 2008 | | 2007 | | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | | | | (In millions) | | | | | Benefit obligation at January 1 | | $ | 290 | | | $ | 294 | | | $ | 83 | | | $ | 80 | | | $ | 291 | | | $ | 290 | | | $ | 91 | | | $ | 83 | | Service cost | | | 14 | | | | 15 | | | | 2 | | | | 2 | | | | 12 | | | | 14 | | | | 2 | | | | 2 | | Interest cost | | | 18 | | | | 17 | | | | 6 | | | | 5 | | | | 20 | | | | 18 | | | | 6 | | | | 6 | | Plan amendments | | | — | | | | (4 | ) | | | 5 | | | | — | | | | 1 | | | | — | | | | — | | | | 5 | | Actuarial gain | | | (19 | ) | | | (13 | ) | | | (4 | ) | | | (2 | ) | | | 45 | | | | (19 | ) | | | 6 | | | | (4 | ) | Employee and retiree contributions | | | | — | | | | — | | | | 1 | | | | — | | Benefit payments | | | (12 | ) | | | (19 | ) | | | (1 | ) | | | (2 | ) | | | (12 | ) | | | (12 | ) | | | (2 | ) | | | (1 | ) | | | | | | | | | | | | | | | | | | | | Benefit obligation at December 31 | | | 291 | | | | 290 | | | | 91 | | | | 83 | | | | 357 | | | | 291 | | | | 104 | | | | 91 | | | | | | | | | | | | | | | | | | | | | Fair value of plan assets at January 1 | | | 168 | | | | 123 | | | | — | | | | — | | | | 195 | | | | 168 | | | | — | | | | — | | Actual return on plan assets | | | (60 | ) | | | 7 | | | | — | | | | — | | | | 53 | | | | (60 | ) | | | — | | | | — | | Employee contributions | | | | — | | | | — | | | | 1 | | | | — | | Employer contributions | | | 99 | | | | 58 | | | | 1 | | | | 1 | | | | 27 | | | | 99 | | | | 1 | | | | 1 | | Benefit payments | | | (12 | ) | | | (20 | ) | | | (1 | ) | | | (1 | ) | | | (12 | ) | | | (12 | ) | | | (2 | ) | | | (1 | ) | | | | | | | | | | | | | | | | | | | | Fair value of plan assets at December 31 | | | 195 | | | | 168 | | | | — | | | | — | | | | 263 | | | | 195 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | Funded status at December 31 — excess of obligation over assets | | $ | (96 | ) | | $ | (122 | ) | | $ | (91 | ) | | $ | (83 | ) | | $ | (94 | ) | | $ | (96 | ) | | $ | (104 | ) | | $ | (91 | ) | | | | | | | | | | | | | | | | | | | |
Amounts recognized in NRG’s balance sheets were as follows: | | | | | | | | | | | | | | | | | | | As of December 31, | | | | | Other Postretirement
| | | Pension Benefits | | Benefits | | | 2008 | | 2007 | | 2008 | | 2007 | | | (In millions) | | Current liabilities | | $ | — | | | $ | — | | | $ | 2 | | | $ | — | | Non-current liabilities | | | 96 | | | | 122 | | | | 89 | | | | 83 | |
179
| | | | | | | | | | | | | | | | | | | As of December 31, | | | | | | | | | | Other Postretirement
| | | | Pension Benefits | | | Benefits | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | | | | (In millions) | | | | | | Current liabilities | | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | Non-current liabilities | | | 94 | | | | 96 | | | | 102 | | | | 89 | |
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Amounts recognized in NRG’s accumulated other comprehensive income that have not yet been recognized as components of net periodic benefit cost were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | As of December 31, | | | | Pension Benefits | | Other Postretirement Benefits | | | | | | Other Postretirement
| | | | 2008 | | 2007 | | 2008 | | 2007 | | Pension Benefits | | Benefits | | | | (In millions) | | 2009 | | 2008 | | 2009 | | 2008 | | | | | | (In millions) | | | | Unrecognized (gain)/loss | | $ | 21 | | | $ | (36 | ) | | $ | (6 | ) | | $ | 1 | | | | | Unrecognized loss/(gain) | | | $ | 29 | | | $ | 21 | | | $ | 1 | | | $ | (6 | ) | Prior service (credit)/cost | | | (3 | ) | | | (3 | ) | | | 5 | | | | — | | | | (3 | ) | | | (3 | ) | | | 4 | | | | 5 | |
189
Other changes in plan assets and benefit obligations recognized in other comprehensive income were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | | | Other Postretirement
| | | | | Other Postretirement
| | | | Pension Benefits | | Benefits | | | Pension Benefits | | Benefits | | | | 2008 | | 2007 | | 2008 | | 2007 | | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | | | | (In millions) | | | | | Net loss/(gain) | | $ | 55 | | | $ | (8 | ) | | $ | (4 | ) | | $ | (2 | ) | | $ | 7 | | | $ | 55 | | | $ | 7 | | | $ | (4 | ) | Amortization of net actuarial loss | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | — | | Prior service (credit)/cost | | | — | | | | (4 | ) | | | 5 | | | | — | | | Prior service cost | | | | 1 | | | | — | | | | — | | | | 5 | | Amortization for prior service cost | | | — | | | | — | | | | (1 | ) | | | — | | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | | | | | | | | | | | | | | | | | | | Total recognized in other comprehensive loss/(income) | | $ | 56 | | | $ | (12 | ) | | $ | — | | | $ | (2 | ) | | Total recognized in other comprehensive loss | | | $ | 8 | | | $ | 56 | | | $ | 6 | | | $ | — | | | | | | | | | | | | | | | | | | | | | Total recognized in net periodic pension cost and other comprehensive income | | $ | 73 | | | $ | 9 | | | $ | 9 | | | $ | 5 | | | $ | 25 | | | $ | 73 | | | $ | 15 | | | $ | 9 | | | | | | | | | | | | | | | | | | | | |
The Company’s estimated net gain for NRG’s domestic pension plan that will be amortized from the accumulated other comprehensive income to net periodic cost over the next fiscal year is minimal. The following table presents the balances of significant components of NRG’s domestic pension plan: | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | | | | Pension Benefits | | | Pension Benefits | | | | 2008 | | 2007 | | | 2009 | | 2008 | | | | (In millions) | | | (In millions) | | | Projected benefit obligation | | $ | 291 | | | $ | 290 | | | $ | 357 | | | $ | 291 | | Accumulated benefit obligation | | | 251 | | | | 236 | | | | 309 | | | | 251 | | Fair value of plan assets | | | 195 | | | | 168 | | | | 263 | | | | 195 | |
NRG’s market-related value of its plan assets is the fair value of the assets. The fair values of the Company’s pension plan assets at December 31, 2009 by asset category are as follows: | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2009 | | | | Quoted Prices in
| | | | | | Significant
| | | | | | | Active Markets for
| | | Significant
| | | Unobservable
| | | | | | | Identical Assets
| | | Observable
| | | Inputs
| | | | | | | (Level 1) | | | Inputs (Level 2) | | | (Level 3) | | | Total | | | | (In millions) | | | U.S. equity investment | | $ | 44 | | | $ | — | | | $ | — | | | $ | 44 | | International equity investment | | | 12 | | | | — | | | | — | | | | 12 | | Corporate bond investment-fixed income | | | 23 | | | | — | | | | — | | | | 23 | | Common/collective trust investment – U.S. equity | | | — | | | | 107 | | | | — | | | | 107 | | Common/collective trust investment – international equity | | | — | | | | 29 | | | | — | | | | 29 | | Common/collective trust investment – fixed income | | | — | | | | 48 | | | | — | | | | 48 | | | | | | | | | | | | | | | | | | | Total | | $ | 79 | | | $ | 184 | | | $ | — | | | $ | 263 | | | | | | | | | | | | | | | | | | |
The fair value of the U.S. and international equity investments and the corporate bond investment are based on quoted prices in active markets and are categorized in Level 1. All equity investments are valued at the net asset value of shares held at year end. The fair value of the corporate bond investment is based on the closing price reported on the active market on which the individual securities are traded. The fair value of the common /collective trusts are valued at fair value which is equal to the sum of the market value of all of the fund’s underlying investments and is categorized as Level 2. 190
The following table presents the significant assumptions used to calculate NRG’s benefit obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | Weighted-Average
| | Pension Benefits | | Other Postretirement Benefits | | | Pension Benefits | | Other Postretirement Benefits | Assumptions | | 2008 | | 2007 | | 2008 | | 2007 | | | 2009 | | 2008 | | 2009 | | 2008 | | Discount rate | | | 6.88% | | | | 6.56% | | | | 6.88% | | | | 6.56% | | | 5.93% | | 6.88% | | 6.14% | | 6.88% | Rate of compensation increase | | | 4.00-4.50% | | | | 4.00-4.50% | | | | N/A | | | | N/A | | | 4.00-4.50% | | 4.00-4.50% | | N/A | | N/A | Health care trend rate | | | — | | | | — | | | | 9.5% grading to 5.5% in 2016 | | | | 9.5% grading to 5.5% in 2016 | | | — | | — | | 9.5% grading to 5.5% in 2016 | | 9.5% grading to 5.5% in 2016 |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table presents the significant assumptions used to calculate NRG’s benefit expense: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | | | Pension Benefits | | Other Postretirement Benefits | | | Weighted-Average Assumptions | | 2008 | | 2007 | | 2006 | | 2008 | | 2007 | | 2006 | | | Weighted-Average
| | | Pension Benefits | | Other Postretirement Benefits | Assumptions | | | 2009 | | 2008 | | 2007 | | 2009 | | 2008 | | 2007 | | Discount rate | | | 6.56 | % | | | 5.92 | % | | | 5.50 | % | | | 6.56% | | | | 5.92% | | | | 5.50% | | | 6.88% | | 6.56% | | 5.92% | | 6.88% | | 6.56% | | 5.92% | Expected return on plan assets | | | 7.50 | % | | | 8.00 | % | | | 8.00 | % | | | — | | | | — | | | | — | | | 7.50% | | 7.50% | | 8.00% | | — | | — | | — | Rate of compensation increase | | | 4.00-4.50 | % | | | 4.00-4.50 | % | | | 4.00-4.50 | % | | | — | | | | — | | | | — | | | 4.00-4.50% | | 4.00-4.50% | | 4.00-4.50% | | — | | — | | — | Health care trend rate | | | — | | | | — | | | | — | | | | 9.5% grading to 5.5% in 2016 | | | | 10.5% grading to 5.5% in 2012 | | | | 11.5% grading to 5.5% in 2012 | | | — | | — | | — | | 9.5% grading to 5.5% in 2016 | | 9.5% grading to 5.5% in 2016 | | 10.5% grading to 5.5% in 2012 |
NRG uses December 31 of each respective year as the measurement date for the Company’s pension and other postretirement benefit plans. The Company sets the discount rate assumptions on an annual basis for each of NRG’s retirement related benefit plans at their respective measurement date. This rate is determined by NRG’s Investment Committee based on information provided by the Company’s actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. The discount rate assumptions used to determine future pension obligations as of December 31, 20082009, and 20072008 were based on the Hewitt Yield Curve, or HYC, which was designed by Hewitt Associates to provide a means for plan sponsors to value the liabilities of their postretirement benefit plans. The HYC is a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the HYC is required to have a rating of Aa or better by Moody’s Investor Service, Inc. or a rating of AA or better by Standard & Poor’s. Prior to using the HYC rates, the discount rate assumptions for pension expense in 2006 were based on investment yields available on AA rated long-term corporate bonds. NRG employs a total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The target allocation of plan assets is 60%63% to 75%77% invested in equity securities of which 50% to 60% invested in U.S. equity securities, with the remainder invested in fixed income securities. The Investment Committee reviews the asset mix periodically and as the plan assets increase in future years, the Investment Committee may examine other asset classes such as real estate or private equity. NRG employs a building block approach to determining the long-term rate of return for plan assets, with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed income are preserved, consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness. Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across USU.S. and non-USnon-U.S. equities, as well as among growth, value, small and large capitalization stocks. NRG’s pension plan assets weighted average allocation as of December 31, 20082009, and 20072008 were as follows: | | | | | | | | | | | As of December 31, | | | | 2008 | | | 2007 | | | US Equity | | | 50-55 | % | | | 50-55 | % | International Equity | | | 15 | % | | | 15 | % | US Fixed Income | | | 30-35 | % | | | 30-35 | % |
| | | | | | | | | | | As of December 31, | | | | 2009 | | | 2008 | | | U.S. Equity | | | 50-60 | % | | | 50-55 | % | International Equity | | | 13-17 | % | | | 15 | % | U.S. Fixed Income | | | 25-35 | % | | | 30-35 | % |
181191
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NRG’s expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Postretirement Benefit | | | | | Other Postretirement Benefit | | | | Pension
| | | | Medicare Prescription
| | | Pension
| | | | Medicare Prescription
| | | | Benefit Payments | | Benefit Payments | | Drug Reimbursements | | | Benefit Payments | | Benefit Payments | | Drug Reimbursements | | | | (In millions) | | | | | (In millions) | | | | | 2009 | | $ | 13 | | | $ | 3 | | | $ | — | | | 2010 | | | 15 | | | | 3 | | | | — | | | $ | 16 | | | $ | 2 | | | $ | — | | 2011 | | | 16 | | | | 4 | | | | — | | | | 17 | | | | 3 | | | | — | | 2012 | | | 18 | | | | 4 | | | | — | | | | 19 | | | | 3 | | | | — | | 2013 | | | 20 | | | | 4 | | | | — | | | | 21 | | | | 4 | | | | — | | 2014-2018 | | | 133 | | | | 30 | | | | 1 | | | 2014 | | | | 23 | | | | 4 | | | | — | | 2015-2019 | | | | 149 | | | | 30 | | | | 1 | |
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect: | | | | | | | | | | | | | | | | | | | 1-Percentage-
| | 1-Percentage-
| | | 1-Percentage-
| | 1-Percentage-
| | | | Point Increase | | Point Decrease | | | Point Increase | | Point Decrease | | | | (In millions) | | | (In millions) | | | Effect on total service and interest cost components | | $ | — | | | $ | (1 | ) | | $ | 1 | | | $ | (1 | ) | Effect on postretirement benefit obligation | | | 7 | | | | (6 | ) | | | 9 | | | | (7 | ) |
STP Defined Benefit Plans NRG has a 44% undivided ownership interest in STP, as discussed further in Note 26,27,Jointly Owned Plants. STPNOC, who operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. For the periodyears ending December 31, 20082009, and 2007,2008, NRG reimbursed STPNOC approximately $6$5 million and $12$6 million, respectively, towards its defined benefit plans. In 2009,2010, NRG expects to reimburse STPNOC approximately $5$4 million for its contributions towards the plans. The Company has recognized the following in its statement of financial position and accumulated other comprehensive income related to its 44% interest in STP: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | | | | Pension Benefits | | Other Postretirement Benefits | | | Pension Benefits | | Other Postretirement Benefits | | | | 2008 | | 2007 | | 2008 | | 2007 | | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | | (In millions) | | | Funded status — STPNOC benefit plans | | $ | (48 | ) | | $ | (20 | ) | | $ | (27 | ) | | $ | (22 | ) | | $ | (43 | ) | | $ | (48 | ) | | $ | (30 | ) | | $ | (27 | ) | Net periodic benefit costs | | | 5 | | | | 4 | | | | 3 | | | | 3 | | | | 10 | | | | 5 | | | | 4 | | | | 3 | | Other changes in plan assets and benefit obligations recognized in other comprehensive income | | | 27 | | | | 4 | | | | 6 | | | | 4 | | | | (10 | ) | | | 27 | | | | 5 | | | | 6 | |
Defined Contribution Plans NRG’s employees have also been eligible to participate in defined contribution 401(K) plans. The Company’s contributions to these plans were approximately $22 million, $17 million, $16 million, and $15$16 million for the years ended December 31, 2009, 2008, 2007 and 2006,2007, respectively.
182192
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | Note 1315 — | Capital Structure |
The following table reflects the changes in NRG’s common stock issued and outstanding for the year ended December 31, 2009, 2008, and 2007: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Authorized | | Issued | | Treasury | | Outstanding | | | Authorized | | Issued | | Treasury | | Outstanding | | | Balance as of December 31, 2006 | | | 500,000,000 | | | | 274,248,264 | | | | (29,601,162 | ) | | | 244,647,102 | | | | 500,000,000 | | | | 274,248,264 | | | | (29,601,162 | ) | | | 244,647,102 | | Retirement of shares | | | — | | | | (14,094,962 | ) | | | 14,094,962 | | | | — | | | | — | | | | (14,094,962 | ) | | | 14,094,962 | | | | — | | Additional Share Repurchases | | | — | | | | — | | | | (2,037,700 | ) | | | (2,037,700 | ) | | Capital Allocation Plan — Phase II | | | — | | | | — | | | | (7,006,700 | ) | | | (7,006,700 | ) | | Additional Share Repurchase | | | | — | | | | — | | | | (2,037,700 | ) | | | (2,037,700 | ) | Capital Allocation Plans | | | | — | | | | — | | | | (7,006,700 | ) | | | (7,006,700 | ) | Shares issued from LTIP | | | — | | | | 1,132,227 | | | | — | | | | 1,132,227 | | | | — | | | | 1,132,227 | | | | — | | | | 1,132,227 | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2007 | | | 500,000,000 | | | | 261,285,529 | | | | (24,550,600 | ) | | | 236,734,929 | | | | 500,000,000 | | | | 261,285,529 | | | | (24,550,600 | ) | | | 236,734,929 | | Capital Allocation Plan — Phase II | | | — | | | | — | | | | (4,691,883 | ) | | | (4,691,883 | ) | | Capital Allocation Plans | | | | — | | | | — | | | | (4,691,883 | ) | | | (4,691,883 | ) | Shares issued from LTIP | | | — | | | | 1,004,176 | | | | — | | | | 1,004,176 | | | | — | | | | 1,004,176 | | | | — | | | | 1,004,176 | | 5.75% Preferred Stock conversion | | | — | | | | 1,309,495 | | | | — | | | | 1,309,495 | | | | — | | | | 1,309,495 | | | | — | | | | 1,309,495 | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2008 | | | 500,000,000 | | | | 263,599,200 | | | | (29,242,483 | ) | | | 234,356,717 | | | | 500,000,000 | | | | 263,599,200 | | | | (29,242,483 | ) | | | 234,356,717 | | Shares issued under NRG Employee Stock Purchase Plan, or ESPP | | | | — | | | | — | | | | 81,532 | | | | 81,532 | | Shares loaned to affiliates of CS | | | | — | | | | — | | | | 12,000,000 | | | | 12,000,000 | | Shares returned by affiliate of CS | | | | — | | | | — | | | | (5,400,000 | ) | | | (5,400,000 | ) | Capital Allocation Plans | | | | — | | | | — | | | | (19,305,500 | ) | | | (19,305,500 | ) | Shares issued from LTIP | | | | — | | | | 367,858 | | | | — | | | | 367,858 | | 4.00% Preferred Stock conversion | | | | — | | | | 13,293,500 | | | | — | | | | 13,293,500 | | 5.75% Preferred Stock conversion | | | | — | | | | 18,601,201 | | | | — | | | | 18,601,201 | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2009 | | | | 500,000,000 | | | | 295,861,759 | | | | (41,866,451 | ) | | | 253,995,308 | | | | | | | | | | | | |
Stock Split
On April 25, 2007, NRG’s Board of Directors approved a two-for-one stock split of the Company’s outstanding shares of common stock which was effected through a stock dividend distributed by the Company’s transfer agent on May 31, 2007. All share amounts for all periods presented have been adjusted to reflect the stock split.
Common Stock
NRG’s authorized common stock consists of 500 million shares of NRG stock. Common stock issued as of December 31, 2008 and 2007 was 263,599,200 and 261,285,529 shares, respectively, at a par value of $0.01 per share. Common stock issued and outstanding as of December 31, 2008 and 2007 were 234,356,717 and 236,734,929, respectively.
The following table summarizes NRG’s common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long termlong-term incentive plan as of December 31, 2008:2009: | | | | | | | Common Stock
| | Equity Instrument | | Reserve Balance | | | 4% Convertible perpetual preferred | | | 26,151,97212,858,472 | | 3.625% Convertible perpetual preferred | | | 16,000,000 | | 5.75% Mandatory convertible preferred | | | 19,210,505 | | Long term incentive plan | | | 13,561,56513,193,707 | | | | | | | Total | | | 74,924,04242,052,179 | | | | | | |
Treasury Stock
As of December 31, 2008 and 2007, NRG has treasury shares of 29,242,483 and 24,550,600, respectively and are held at cost of approximately $823 million and $638 million, respectively.
Capital Allocation Plan — In December 2007, the Company initiated its 2008 Capital Allocation Plan, with the repurchase of 2,037,700 shares of NRG common stock during that month for approximately $85 million. In February 2008,
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
the Company’s Board of Directors authorized an additional $200 million in common share repurchases that raised the total 2008 Capital Allocation Plan to approximately $300 million. In the first quarterDuring 2008, the Company repurchased 1,281,600a total of 4,691,883 shares of NRG common stock for approximately $55 million. In the third quarter 2008, the Company repurchased an additional 3,410,283 of NRG common stock for approximately $130$185 million. As of December 31, 2008, NRG had repurchased a total of 6,729,583 shares of NRG common stock at a cost of approximately $270 million as part of its 2008 Capital Allocation Plan. In the third quarter 2009, to complete its remaining $30 million planned share re-purchase under the 2008 Capital Allocation plan and to initiate its 2009 Capital Allocation Plan, the Company repurchased 8,919,100 shares of NRG common stock for approximately $250 million. In the fourth quarter 2009, the Company repurchased an additional 10,386,400 shares of NRG common stock for approximately $250 million. For 2009, NRG repurchased a total of 19,305,500 shares of NRG common stock at a cost of approximately $500 million under its share repurchase program. Retirement of Treasury Stock — On May 22, 2007, NRG retired 14,094,962 shares of treasury stock. These retired shares are now included in the Company’s pool of authorized but unissued shares. The retired stock had a carrying value of approximately $447 million. The Company’s accounting policy upon the formal retirement of 193
treasury stock is to deduct its par value from Common Stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital. Employee Stock Purchase Plan — In May 2008, NRG shareholders approved the adoption of the NRG Energy, Inc. Employee Stock Purchase Plan, or ESPP, pursuant to which eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at 85% of its fair market value on the exercise date. An exercise date occurs each June 30 and December 31. The initial six month employee withholding period began July 1, 2008 and ended December 31, 2008.the first issuance of common stock under the ESPP occurred in 2009. As of December 31, 2008,2009, there were 500,000remained 418,468 shares of treasury stock reserved for issuance under the ESPP. InESPP, and in January 2009, 41,7062010, 54,845 shares of common stock were issued to employee accountaccounts from treasury stock. Share Lending Agreements — As discussed in Note 12,Debt and Capital Leases, underDebt Related to Capital Allocation Program,CSF I and CSF II loaned 12,000,000 shares of NRG common stock to affiliates of CS in the first quarter 2009, and in the fourth quarter 2009, CS returned 5,400,000 of these shares in connection with the maturity of the CSF II Debt. Preferred Stock As of December 31, 20082009, and 2007,2008, the Company had 10,000,000 shares of preferred stock authorized. As of December 31, 2008,2009, the Company’s preferred stock consisted of threetwo series: the 5.75% Mandatory Convertible Preferred Stock, or 5.75% Preferred Stock; the 4% Convertible Perpetual Preferred Stock, or 4% Preferred Stock; and the 3.625% Convertible Perpetual Preferred Stock, which is treated as Redeemable Preferred Stock, or 3.625% Preferred Stock. 5.75% Preferred Stock On February 2, 2006, NRG completed the issuance of 2,000,000 shares of 5.75% Preferred Stock, for net proceeds of $486 million, reflecting an offering price of $250 per share and the deduction of offering expenses and discounts of approximately $14 million. Dividends on the 5.75% Preferred Stock arewere $14.375 per share per year, and arewere due and payable on a quarterly basis beginning on March 15, 2006. Each share Certain holders of the Company’s 5.75% Preferred Stock will automaticallyelected to convert their preferred shares into a numberNRG common shares prior to the mandatory conversion date of shares of common stock on March 16, 2009 or the Conversion Date, at a rate that is dependent upon the applicable market value of NRG’s common stock, illustrated in the following table: | | | | | Applicable Market Value on Conversion Date
| | Conversion Rate | | | equal to or greater than $30.23 | | | 8.2712 | | less than $30.23 but greater than $24.38 | | | 8.2712 to 10.2564 | | less than or equal to $24.38 | | | 10.2564 | |
Included in the agreement is a call option which allows that at any time prior to March 16, 2009, should the price of NRG’s common stock exceed $45.375, for at least 20 trading days within a period of 30 consecutive trading days, NRG may elect to cause the conversion of all, but not less than all, of its 5.75% Preferred Stock outstanding at the minimum conversion rate of 8.2712 shares of the Company’s common stock for each share of the 5.75% Preferred Stock. However, NRG can cause conversion only if it pays the holders in cash an amount equal to any
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
accrued, accumulated and unpaid dividends on the outstanding 5.75% Preferred Stock declared and not declared plus the present value of all remaining future dividends through March 16, 2009.
The holders of the 5.75% Preferred Stock may elect to convert at any time prior to the Conversion Date at the minimum conversion rate of 8.2712. As of December 31, 2008, 158,320 sharesMarch 16, 2009, each remaining outstanding share of the 5.75% Preferred Stock wereautomatically converted early into 1,309,495 shares of common stock at a rate of 10.2564, based upon the electionapplicable market value of NRG’s common stock. These conversions resulted in a decrease in preferred stock of $447 million, and a corresponding increase in Additional Paid-in Capital. The following table summarizes the conversion of the holders. As of February 2, 2009, an additional 142,400 shares of 5.75% Preferred Stock was converted into 1,177,818 shares of common stock in 2009. Also included is an early conversion feature by the holders which is contingent upon a cash acquisition of NRG on or prior to March 16, 2009. This feature requires paying converting holders an amount equal to the sum of any accumulated and unpaid dividends, the present value of all remaining dividend payments through and including March 16, 2009, and a specified conversion rate determined by reference to the price per share of the Company’s common stock paid in such acquisition for each share of the outstanding 5.75% Preferred Stock. However, should such a transaction be consummated by a public acquirer, in lieu of providing for conversion and paying the dividend amount, the Company may adjust its conversion obligation such that upon conversion of the outstanding 5.75%Common Stock:
| | | | | | | | | | | | | | | Preferred Stock
| | | Conversion Rate
| | | Common Stock
| | | | Shares | | | (per share) | | | Shares | | | Balance as of December 31, 2008 | | | 1,841,680 | | | | | | | | — | | Preferred shares converted by the holders prior to March 16, 2009 | | | 144,975 | | | | 8.2712 | | | | 1,199,116 | | Preferred shares automatically converted as of March 16, 2009 | | | 1,696,705 | | | | 10.2564 | | | | 17,402,085 | | | | | | | | | | | | | | | Balance at December 31, 2009 | | | — | | | | | | | | 18,601,201 | | | | | | | | | | | | | | |
4% Preferred Stock NRG will deliver the acquirer’s common stock. As of December 31, 2009, and 2008, 154,057 and 2007, 420,000 shares of the Company’s 4% Preferred Stock were issued and outstanding at a liquidation value, net of issuance costs, of $149 million and $406 million.million, respectively. The 4% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 4% Preferred Stock are entitled to receive, when declared by NRG’s Board of Directors, cash dividends at the rate of 4% per annum, or $40.00 per share per year, payable quarterly in arrears commencing on March 15, 2005. The 4% Preferred Stock is convertible, at the option of the holder, at any time into shares of NRG’s common stock at an initial conversion price of $20.00 per share. As of February 2, 2009, 100 shares ofIn addition, NRG had the 4% Preferred Stock were converted into 5,000 shares of common stock in 2009. Onability to redeem, on or after December 20, 2009, NRG may redeem,and subject to 194
certain limitations, some or all of the 4% Preferred Stock with cash at a redemption price equal to 100% of the liquidation preference, plus accumulated but unpaid dividends, including liquidated damages, if any, to the redemption date. Should NRG be subject to a fundamental change, as defined inDuring the Certificatefirst half of Designation2009, 413 shares of the 4% Preferred Stock eachwere converted, at the option of the holder, into 20,650 shares of common stock. In addition, in November 2009, NRG notified the holders of the Company’s intention to redeem approximately 50% of the outstanding 4% Preferred Stock and 265,457 shares of the 4% Preferred Stock haswere converted, at the right, subject to certain limitations, to require NRG to purchase any or alloption of the Company’sholder, into 13,272,850 shares of common stock in December 2009 in response to this notification. These conversions resulted in a decrease in preferred stock of $257 million, and a corresponding increase in Additional Paid-in Capital. The following table summarizes all 4% Preferred Stock at a purchase price equal to 100% ofconversions and redemptions for the liquidation preference, plus accumulated and unpaid dividends, including liquidated damages, if any, toyear ended December 31, 2009:
| | | | | | | | | | | | | | | Preferred Stock
| | | Conversion Rate
| | | Common Stock
| | | | Shares | | | (per share) | | | Shares | | | Balance as of December 31, 2008 | | | 420,000 | | | | | | | | — | | Preferred shares converted by the holders prior to November 20, 2009 | | | 413 | | | | 50 | | | | 20,650 | | First redemption: | | | | | | | | | | | | | Preferred shares converted by the holders prior to December 22, 2009 | | | 256,486 | | | | 50 | | | | 12,824,300 | | Preferred shares redeemed for cash by the Company prior to December 22, 2009 | | | 73 | | | | | | | | | | Second redemption: | | | | | | | | | | | | | Preferred shares converted by the holders prior to December 31 , 2009 | | | 8,971 | | | | 50 | | | | 448,550 | | | | | | | | | | | | | | | Balance at December 31, 2009 | | | 154,057 | | | | | | | | 13,293,500 | | | | | | | | | | | | | | |
On December 22, 2009, NRG notified the date of purchase. Final determination of a fundamental change must be approved by the Board of Directors. Each holderholders of the 4% Preferred Stock has one voteof the Company’s intention to call for each shareredemption the remaining outstanding shares of the 4% Preferred Stock held byon January 21, 2010. As of January 21, 2010, the holder on all matters voted upon byCompany completed the holdersredemption of NRG common stock, as well as voting rights specifically provided for in NRG’s amended and restated certificatethe remaining shares of incorporation or as otherwise, from time to time, required by law. The 4% Preferred Stock, is, with respectholders converting 154,029 shares to dividend rights and rights upon liquidation, winding up or dissolution: junior to all7,701,450 shares of NRG’s existing and future debt obligations; junior to each other class or series of NRG’s capital stock other than (i) NRG’s common stock and any other class or series of the Company’s capital stock that provides that such class or series will rank junior to the 4% Preferred Stock, and (ii) any other class or series of NRG’s capital stock, the terms of which provide that such class or series will rank on a parity with the 4% Preferred Stock.Company redeeming 28 shares for $28,000 cash.
Redeemable Preferred Stock 3.625% Preferred Stock On August 11, 2005, NRG issued 250,000 shares of 3.625% Preferred Stock, which is treated as Redeemable Preferred Stock, to CS in a private placement. As of December 31, 20082009 and 2007,2008, 250,000 shares of the 3.625% Preferred Stock were issued and outstanding at a liquidation value, net of issuance costs, of $247 million. The 3.625% Preferred Stock amount is located after the Liabilitiesliabilities but before the Stockholders’ Equitystockholders’ equity section on the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Balance Sheet, balance sheet, due to the fact that the preferred shares can be redeemed in cash by the shareholder. The 3.625% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 3.625% Preferred Stock are entitled to receive, out of legally available funds, cash dividends at the rate of 3.625% per annum, or $36.25 per share per year, payable in cash quarterly in arrears commencing on December 15, 2005.
Each share of the 3.625% Preferred Stock is convertible during the90-day period beginning August 11, 2015 at the option of NRG or the holder. Holders tendering the 3.625% Preferred Stock for conversion shall be entitled to receive, for each share of 3.625% Preferred Stock converted, $1,000 in cash and a number of shares of NRG common stock equal to the product of (a) the greater of (i) the difference between the average closing share price of NRG common stock on each of the 20 consecutive scheduled trading days starting on the date 30 exchange business days immediately prior to the conversion date, or the Market Price, and $29.54 and (ii) zero, times (b) 50.77. The number of NRG common stock to be delivered under the conversion feature is limited to 16,000,000 shares. If upon conversion, the Market Price is less than $19.69, then the Holder will deliver to NRG cash or a number of shares of NRG common stock equal in value to the product of (i) $19.69 minus the Market Price, times (ii) 50.77. NRG may elect to make a cash payment in lieu of delivering shares of NRG common stock in connection with such 195
conversion, and NRG may elect to receive cash in lieu of shares of common stock, if any, from the Holder in connection with such conversion. The conversion feature is considered an embedded derivative per SFAS 133ASC 815 that is exempt from derivative accounting as it’sit is excluded from the scope pursuant to paragraph 11(a) of SFAS 133.ASC 815. If a fundamental change occurs, the holders will have the right to require NRG to repurchase all or a portion of the 3.625% Preferred Stock for a period of time after the fundamental change at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends. The 3.625% Preferred Stock is senior to all classes of common stock, on parity with the Company’s 4% Preferred Stock, and junior to all of the Company’s existing and future debt obligations and all of NRG subsidiaries’ existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | Note 1416 — | Investments Accounted for by the Equity Method |
NRG accounts for the company’sCompany’s significant investments using the equity method of accounting. NRG’s carrying value of equity investments can be impacted by impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates, as well as other adjustments. The following table summarizes NRG’s equity method investments, as of December 31, 2008:2009: | | | | | | | | | | | | | | Economic
| | Name | | Geographic Area | | | Interest | | | MIBRAG | | | Germany | | | | 50.0 | % | Sherbino I Wind Farm LLC | | | USA | | | | 50.0 | %50.0% | Saguaro Power Company | | | USA | | | | 50.0 | %50.0% | GenConn Energy LLC | | | USA | | | | 50.0 | %50.0% | Gladstone Power Station | | | Australia | | | | 37.5 | %37.5% |
MIBRAG— On June 10, 2009, NRG owns acompleted the sale of its 50% interestownership in MIBRAG located near Leipzig, Germany, MIBRAG owns and manages a coal mining operation, three lignite fueled power generation facilities and other related businesses. Approximately 40% of the power generated by MIBRAG is used to support its mining operations, with the remainder sold to a German utility company. A portion of the coal from MIBRAG’s mining operation is used to fuel the power generation facilities, but a majority of the mined coal is sold primarily to two major customers, including Schkopau, an affiliate of NRG. A significant portion of MIBRAG’s sales are made pursuant to long-term coal and energy supply contracts. For the years ended December 31, 2008, 2007 and 2006, NRG’s equity earnings from MIBRAG were approximately $31 million, $36 million and $30 million, respectively. As discussedMibrag B.V. See further discussion in Note 2,4,Summary of Significant Accounting PoliciesDiscontinued Operations and Dispositions, the Company’s MIBRAG equity investment was negatively affected by the adoption ofEITF 04-6. Upon adoption ofEITF 04-6 on January 1, 2006, NRG’s investment in MIBRAG was reduced by approximately $93 million, with an offsetting charge to retained earnings..
Sherbino I Wind Farm LLC— NRG owns a 50% interest in Sherbino, a joint venture with BP.BP Wind Energy North America Inc. Sherbino is a 150MW wind farm consisting of 50 Vestas 3 MW3MW wind turbine generators, which commenced commercial operations in October 2008. NRG contributed approximately $84 million to its equity investment in Sherbino in 2008. ForNRG’s equity loss from Sherbino was insignificant for the year ended December 31, 2009, and for the year ended December 31, 2008, NRG’sNRG posted equity earnings from Sherbino wereof $8 million. Saguaro Power Company— NRG owns a 50% interest in the Saguaro plant, a cogeneration plant with dual-fuel capability, natural gas and oil. For the yearsyear ended December 31, 2008, 2007 and 20062009, NRG’s equity lossincome from Saguaro was $10 million. NRG posted equity losses in 2008 and 2007 of $2 million and $3 million, and $1 million.respectively. GenConn Energy LLC— NRG owns a 50% interest in GenConn, a limited liability company formed in February 2008 by NRG and The United Illuminating Company, or UI, for the construction and operation of two 200 MW peaking facilities in Connecticut through GenConn’s wholly-owned subsidiaries, GenConn Devon, LLC, or Devon, and GenConn Middletown LLC, or Middletown. Devon and Middletown have each entered into30-year cost of service type contracts with Connecticut Light & Power, or CL&P as mandated by the DPUC, commencing when the facilities reach commercial operations, currently expected to be 2010 and 2011, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The project is expected to be funded through equity contributions from the owners and non-recourse, project level debt. As of December 31, 2008,2009, NRG has made a nominal equity investment in GenConn. In addition, as discussed in Note 8,9,Capital Leases and Notes Receivable, in 2008 NRG entered into a short-term $45 million note receivable facility with GenConn to fund NRG’s proportionate share of project liquidity needs. GenConn had borrowed $36 million under this facility as of December 31, 2008. As discussedneeds which was repaid in Note 25,Guarantees, NRG has guaranteed its proportionate share of GenConn’s payments to a vendor under turbine purchase agreements for the Devon and Middletown sites, effective until such time as GenConn has obtained financing for each of the respective projects. As of December 31, 2008, NRG’s potential remaining obligation under the guarantees is $54 million.2009. NRG’s maximum exposure to loss is limited to its equity investments and note receivable,receivable. On April 27, 2009, a wholly-owned subsidiary of NRG, NRG Connecticut Peaking LLC, closed on an equity bridge loan facility, or EBL, in the amount of $121.5 million from a syndicate of banks. For a detailed discussion on the facility, see Note 12— Debt and Capital Leases. GenConn had borrowed $108 million under this facility as well as its remaining potential obligation under the turbine purchase guarantees.of December 31, 2009. 196
As discussed in Note 20,21,Related Party Transactions, a subsidiary of NRG has entered into construction management agreements with Devon and Middletown, and recognized approximately $7 million and $1 million of revenue for the yearyears ended December 31, 2008.2009 and 2008, respectively. In addition, NRG earned interest income of $2 million in 2009 from GenConn on an outstanding note receivable as discussed in Note 9,Capital Leases and Notes Receivable. GenConn is considered a VIE under FIN 46R,ASC 810, but NRG is not the primary beneficiary of GenConn and accounts for its 50% interest under the equity method. GenConn is a development stage entity, and is not expected to begin generating revenues until 2010; therefore NRG recognized no equity earnings from the joint venture for the yearyears ended December 31, 2008.2008 or 2009. Gladstone— Through a joint venture, NRG owns a 37.5% interest in Gladstone, an unincorporated joint venture, or UJV, which operates a 1,613 megawatt coal-fueled power generation facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants in proportion to their ownership interests. Coal is sourced from a mining operation owned and operated by certain joint venture partners and other investors under a long-term supply agreement.local mines in Queensland. NRG and the joint venture participants receive a majority of their respective share of revenues directly from customers and are directly responsible and liable for project-related debt, allthe off takers in proportion to the ownership interests in the UJV.joint venture. Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold onto the national market.Queensland Government owned utility under long term supply contracts. For the years ended December 31, 2009, 2008 2007 and 2006,2007, NRG’s equity earnings from Gladstone were approximately $21$17 million, $21 million and $25$21 million, respectively. On June 8, 2006, NRG announced the saleThe undistributed earnings from equity investments as of the Company’s 37.5% equity interest in Gladstone,December 31, 2009 and its associated 100% owned NRG Gladstone Operating Services to Transfield Services Infrastructure B.V, or Transfield Services, of Australia. On October 9, 2008, Transfield Services signed a deed of termination which terminates the salewere $132 million and purchase agreement signed in June 2006.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)$116 million, respectively.
| | Note 1517 — | Gains/(Losses) on Sales of Equity Method Investments |
Gains or losses are recognized on completion of the sale. The Company had no sales of equity method investments during the year ended December 31, 2008. Gains/(losses) on sales of equity method investments recorded in other income/expense in the Company’s consolidated statements of operations for the years ended December 31, 2007 and 2006 include the following:
| | | | | | | | | | | | | | | Year Ended | | | | | | | 2007 | | | 2006 | | | Segment | | | | (In millions) | | | | | | Powersmith Cogeneration | | $ | 1 | | | $ | — | | | | Corporate | | Latin American Funds | | | — | | | | 3 | | | | International | | James River Power LLC | | | — | | | | (6 | ) | | | Corporate | | Cadillac | | | — | | | | 11 | | | | Corporate | | | | | | | | | | | | | | | Total gains on sales of equity method investments | | $ | 1 | | | $ | 8 | | | | | | | | | | | | | | | | | | |
Latin American Funds — On June 30, 2006, NRG, through its wholly-owned entities NRG Caymans-C and NRG Caymans-P, completed the sale of the entities remaining interests in various Latin American power funds to a subsidiary of Australia Post. Total proceeds received were approximately $23 million and a pre-tax gain of approximately $3 million was recognized in the second quarter 2006.
James River —On May 15, 2006, NRG completed the sale of Capistrano Cogeneration Company, a subsidiary of NRG which owned a 50% interest in James River, to Cogentrix. The proceeds from the sale were approximately $8 million. As a result of the sale, NRG recorded a pre-tax loss of approximately $6 million.
Cadillac —On January 1, 2006, NRG sold 49.5% of the Company’s 50% interest in a 38MW biomass fuel generation facility located in Cadillac, Michigan, along with its right to receive Production Tax Credits, or PTCs, through 2009 to Lakes Renewable LLC. In consideration, NRG received approximately $4 million in a note receivable and a promissory note equal to the value of the Company’s share in future PTCs earned through 2009. The sale was contingent upon the receipt of a favorable private letter ruling from the Internal Revenue Service, or IRS, and accordingly, all consideration was held in escrow. On April 13, 2006, NRG sold its remaining 0.5% share in Cadillac along with the Company’s interest in the note receivable and promissory note to Delta Power for approximately $11 million, resulting in a pre-tax gain of approximately $11 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | Note 16 — | Earnings Per Share |
Basic earnings per common share is computed by dividing net income less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. Dilutive effect for equity compensation — The outstanding non-qualified stock options, non-vested restricted stock units, deferred stock units and performance units are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method. Dilutive effect for other equity instruments — NRG’s outstanding 4% Preferred Stock and 5.75% Preferred Stock are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are considered for inclusion in the denominator for purposes of computing diluted earnings per share under the if-converted method. The if-converted method is also used to determine the dilutive effect of embedded derivatives in the Company’s 3.625% Preferred Stock, and CSF preferred interests and notes. 197
The reconciliation of NRG’s basic earnings per common share to diluted earnings per share for the years ended December 31, 2009, 2008 2007 and 20062007 is shown in the following table: | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2008 | | | 2007 | | | 2006 | | | | (In millions) | | | Basic earnings per share | | | | | | | | | | | | | Numerator: | | | | | | | | | | | | | Income from continuing operations | | $ | 1,016 | | | $ | 569 | | | $ | 543 | | Preferred stock dividends | | | (55 | ) | | | (55 | ) | | | (52 | ) | | | | | | | | | | | | | | Net income available to common stockholders from continuing operations | | | 961 | | | | 514 | | | | 491 | | Discontinued operations, net of tax | | | 172 | | | | 17 | | | | 78 | | | | | | | | | | | | | | | Net income available to common stockholders | | $ | 1,133 | | | $ | 531 | | | $ | 569 | | | | | | | | | | | | | | | Denominator: | | | | | | | | | | | | | Weighted average number of common shares outstanding | | | 235.0 | | | | 240.2 | | | | 258.0 | | Basic earnings per share: | | | | | | | | | | | | | Income from continuing operations | | $ | 4.09 | | | $ | 2.14 | | | $ | 1.90 | | Discontinued operations, net of tax | | | 0.73 | | | | 0.07 | | | | 0.31 | | | | | | | | | | | | | | | Net income | | $ | 4.82 | | | $ | 2.21 | | | $ | 2.21 | | | | | | | | | | | | | | |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | | | | (In millions) | | | (In millions) | | | Diluted earnings per share | | | | | | | | | | | | | | Basic earnings per share attributable to NRG common stockholders | | | | | | | | | | | | | | Numerator: | | | | | | | | | | | | | | Income from continuing operations, net of income taxes | | | $ | 942 | | | $ | 1,053 | | | $ | 556 | | Preferred stock dividends | | | | (33 | ) | | | (55 | ) | | | (55 | ) | | | | | | | | | | Net income available to common stockholders from continuing operations | | | | 909 | | | | 998 | | | | 501 | | Income from discontinued operations, net of tax | | | | — | | | | 172 | | | | 17 | | | | | | | | | | | Net income attributable to NRG Energy, Inc. available to common stockholders | | | $ | 909 | | | $ | 1,170 | | | $ | 518 | | | | | | | | | | | Denominator: | | | | | | | | | | | | | | Weighted average number of common shares outstanding | | | | 245.5 | | | | 235.0 | | | | 240.2 | | Basic earnings per share: | | | | | | | | | | | | | | Income from continuing operations | | | $ | 3.70 | | | $ | 4.25 | | | $ | 2.09 | | Income from discontinued operations, net of tax | | | | — | | | | 0.73 | | | | 0.07 | | | | | | | | | | | Net income attributable to NRG Energy, Inc. | | | $ | 3.70 | | | $ | 4.98 | | | $ | 2.16 | | | | | | | | | | | Diluted earnings per share attributable to NRG common stockholders | | | | | | | | | | | | | | Numerator: | | | | | | | | | | | | | | | | | | | | | | | | | Net income available to common stockholders from continuing operations | | $ | 961 | | | $ | 514 | | | $ | 491 | | | $ | 909 | | | $ | 998 | | | $ | 501 | | Add preferred stock dividends for dilutive preferred stock | | | 46 | | | | 46 | | | | 43 | | | | 23 | | | | 46 | | | | 46 | | | | | | | | | | | | | | | | | Adjusted income from continuing operations available to common stockholders | | | 1,007 | | | | 560 | | | | 534 | | | | 932 | | | | 1,044 | | | | 547 | | Discontinued operations, net of tax | | | 172 | | | | 17 | | | | 78 | | | Income from discontinued operations, net of tax | | | | — | | | | 172 | | | | 17 | | | | | | | | | | | | | | | | | Net income available to common stockholders | | $ | 1,179 | | | $ | 577 | | | $ | 612 | | | Net income attributable to NRG Energy, Inc. available to common stockholders | | | $ | 932 | | | $ | 1,216 | | | $ | 564 | | | | | | | | | | | | | | | | | Denominator: | | | | | | | | | | | | | | | | | | | | | | | | | Weighted average number of common shares outstanding | | | 235.0 | | | | 240.2 | | | | 258.0 | | | | 245.5 | | | | 235.0 | | | | 240.2 | | Incremental shares attributable to the issuance of equity compensation (treasury stock method) | | | 2.3 | | | | 3.8 | | | | 2.8 | | | | 1.2 | | | | 2.3 | | | | 3.8 | | Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method) | | | — | | | | 6.0 | | | | — | | | | — | | | | — | | | | 6.0 | | Incremental shares attributable to the assumed conversion features of outstanding preferred stock (if-converted method) | | | 37.5 | | | | 37.5 | | | | 39.8 | | | | 24.5 | | | | 37.5 | | | | 37.5 | | | | | | | | | | | | | | | | | Total dilutive shares | | | 274.8 | | | | 287.5 | | | | 300.6 | | | | 271.2 | | | | 274.8 | | | | 287.5 | | | | | | | | | | | | | | | | | Diluted earnings per share: | | | | | | | | | | | | | | | | | | | | | | | | | Income from continuing operations available to common stockholders | | $ | 3.66 | | | $ | 1.95 | | | $ | 1.78 | | | $ | 3.44 | | | $ | 3.80 | | | $ | 1.90 | | Discontinued operations, net of tax | | | 0.63 | | | | 0.06 | | | | 0.26 | | | Income from discontinued operations, net of tax | | | | — | | | | 0.63 | | | | 0.06 | | | | | | | | | | | | | | | | | Net income | | $ | 4.29 | | | $ | 2.01 | | | $ | 2.04 | | | Net income attributable to NRG Energy, Inc. | | | $ | 3.44 | | | $ | 4.43 | | | $ | 1.96 | | | | | | | | | | | | | | | | |
The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted earnings per share: | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | | | | (In millions of shares) | | | (In millions of shares) | | | Equity compensation — NQSO’s and PU’s | | | 1.9 | | | | 0.1 | | | | 0.7 | | | | 5.7 | | | | 1.9 | | | | 0.1 | | Embedded derivative of 3.625% redeemable perpetual preferred stock | | | 16.0 | | | | 12.2 | | | | 16.0 | | | | 16.0 | | | | 16.0 | | | | 12.2 | | Embedded derivatives of CSF preferred interests and notes | | | 7.6 | | | | 16.1 | | | | 18.3 | | | | — | | | | 7.6 | | | | 16.1 | | | | | | | | | | | | | | | | | Total | | | 25.5 | | | | 28.4 | | | | 35.0 | | | | 21.7 | | | | 25.5 | | | | 28.4 | | | | | | | | | | | | | | | | |
191 198
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | Note 1718 — | Segment Reporting |
NRG’s segment structure reflects core areas of operation which are primarily the geographic regions ofsegregated based on the Company’s wholesale power generation, retail, thermal and chilled water business, and corporate activities including windactivities. In May 2009, NRG’s segment structure changed to reflect the Company’s acquisition of Reliant Energy and nuclear development.has been incorporated as a separate reporting segment as per ASC 280,Segment Reporting. Within NRG’s wholesale power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, Northeast, South Central, West and International. The Company’s corporate activities include wind, solar and nuclear development. In the second quarter 2009, management changed its method for allocating corporate general and administrative expenses to the segments. Corporate general and administrative expenses had been allocated based on budgeted segment revenues. Beginning in the second quarter 2009, corporate general and administrative expenses have been allocated based on forecasted earnings/(losses) before interest expense, income taxes, depreciation and amortization expense. As of December 31, 2009, there were no customers from whom the Company derived more than 10% of the Company’s consolidated revenues. The following table summarizes customers from whom NRG derived more than 10% of the Company’s consolidated revenues for the years ended December 31, 2008 2007 and 2006:2007: | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | 2008 | | 2007 | | | Customer A — Northeast region | | | — | % | | | — | % | | | 10 | % | | Customer A — Texas region | | | | 11 | % | | | — | % | Customer B — Texas region | | | 11 | | | | — | | | | — | | | | 11 | | | | 27 | | Customer C — Texas region | | | 11 | | | | 27 | | | | — | | | | | | | | | | | | | | | | Total | | | 22 | % | | | 27 | % | | | 10 | % | | | 22 | % | | | 27 | % | | | | | | | | | | | | | |
192199
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2009 | | | | | | | Wholesale Power Generation | | | | | | | | | | | | | | | | Reliant
| | | | | | | | | South
| | | | | | | | | | | | | | | | | | | | | | Energy | | | Texas(a) | | | Northeast | | | Central | | | West | | | International | | | Thermal | | | Corporate | | | Elimination | | | Total | | | | (In millions) | | | Operating revenues | | $ | 4,182 | | | $ | 2,946 | | | $ | 1,201 | | | $ | 581 | | | $ | 150 | | | $ | 144 | | | $ | 135 | | | $ | 28 | | | $ | (415 | ) | | $ | 8,952 | | Operating expenses | | | 3,044 | | | | 1,634 | | | | 740 | | | | 508 | | | | 110 | | | | 116 | | | | 112 | | | | 129 | | | | (418 | ) | | | 5,975 | | Depreciation and amortization | | | 137 | | | | 472 | | | | 118 | | | | 67 | | | | 8 | | | | — | | | | 10 | | | | 6 | | | | — | | | | 818 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating income/(loss) | | | 1,001 | | | | 840 | | | | 343 | | | | 6 | | | | 32 | | | | 28 | | | | 13 | | | | (107 | ) | | | 3 | | | | 2,159 | | Equity in earnings of unconsolidated affiliates | | | — | | | | — | | | | — | | | | — | | | | 10 | | | | 31 | | | | — | | | | — | | | | — | | | | 41 | | Gains on sales of equity method investments | | | — | | | | — | | | | — | | | | — | | | | — | | | | 128 | | | | — | | | | — | | | | — | | | | 128 | | Other income/(loss), net | | | — | | | | 7 | | | | 2 | | | | 1 | | | | — | | | | (20 | ) | | | — | | | | 27 | | | | (22 | ) | | | (5 | ) | Refinancing expenses | | | (1 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (19 | ) | | | — | | | | (20 | ) | Interest expense | | | (34 | ) | | | (4 | ) | | | (54 | ) | | | (48 | ) | | | (2 | ) | | | (8 | ) | | | (5 | ) | | | (497 | ) | | | 18 | | | | (634 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations before income taxes | | | 966 | | | | 843 | | | | 291 | | | | (41 | ) | | | 40 | | | | 159 | | | | 8 | | | | (596 | ) | | | (1 | ) | | | 1,669 | | Income tax expense | | | — | | | | 171 | | | | — | | | | — | | | | — | | | | 9 | | | | — | | | | 548 | | | | — | | | | 728 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations | | | 966 | | | | 672 | | | | 291 | | | | (41 | ) | | | 40 | | | | 150 | | | | 8 | | | | (1,144 | ) | | | (1 | ) | | | 941 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income/(loss) | | | 966 | | | | 672 | | | | 291 | | | | (41 | ) | | | 40 | | | | 150 | | | | 8 | | | | (1,144 | ) | | | (1 | ) | | | 941 | | Less: Net loss attributable to noncontrolling interest | | | — | | | | (1 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (1 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income/(loss) attributable to NRG Energy, Inc. | | $ | 966 | | | $ | 673 | | | $ | 291 | | | $ | (41 | ) | | $ | 40 | | | $ | 150 | | | $ | 8 | | | $ | (1,144 | ) | | $ | (1 | ) | | $ | 942 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity investments in affiliates | | $ | 2 | | | $ | 92 | | | $ | 6 | | | $ | — | | | $ | 35 | | | $ | 273 | | | $ | — | | | $ | 1 | | | $ | — | | | $ | 409 | | Capital expenditures | | | 7 | | | | 189 | | | | 207 | | | | 9 | | | | 8 | | | | — | | | | 10 | | | | 353 | | | | — | | | | 783 | | Goodwill | | | — | | | | 1,713 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 5 | | | | — | | | | 1,718 | | Total assets | | $ | 2,007 | | | $ | 13,092 | | | $ | 1,866 | | | $ | 909 | | | $ | 329 | | | $ | 785 | | | $ | 206 | | | $ | 22,442 | | | $ | (18,258 | ) | | $ | 23,378 | | (a) Includes inter-segment sales of $411 million to Reliant Energy. | If the Company continued using the 2008 allocation method for corporate general and administrative expenses, the effect to net income/(loss) of each segment for the year ended December 31, 2009, would have been as follows: | Net income/(loss) attributable to NRG Energy, Inc. as reported | | $ | 966 | | | $ | 673 | | | $ | 291 | | | $ | (41 | ) | | $ | 40 | | | $ | 150 | | | $ | 8 | | | $ | (1,144 | ) | | $ | (1 | ) | | $ | 942 | | Increase/(decrease) in net income/(loss) attributable to NRG Energy, Inc. | | | (46 | ) | | | 33 | | | | 13 | | | | (3 | ) | | | 2 | | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | Adjusted net income/(loss) attributable to NRG Energy, Inc. | | $ | 920 | | | $ | 706 | | | $ | 304 | | | $ | (44 | ) | | $ | 42 | | | $ | 151 | | | $ | 8 | | | $ | (1,144 | ) | | $ | (1 | ) | | $ | 942 | | | |
200
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2008 | | | Year Ended December 31, 2008 | | | | Wholesale Power Generation | | | | | | | | | | | Wholesale Power Generation | | | | | | | | | | | | | | | | South
| | | | | | | | | | | | | | | | | | | South
| | | | | | | | | | | | | | | | Texas | | Northeast | | Central | | West | | International | | Thermal | | Corporate | | Elimination | | Total | | | Texas | | Northeast | | Central | | West | | International | | Thermal | | Corporate | | Elimination | | Total | | | | (In millions) | | | (In millions) | | | Operating revenues | | $ | 4,026 | | | $ | 1,630 | | | $ | 746 | | | $ | 171 | | | $ | 158 | | | $ | 154 | | | $ | 3 | | | $ | (3 | ) | | $ | 6,885 | | | $ | 4,026 | | | $ | 1,630 | | | $ | 746 | | | $ | 171 | | | $ | 158 | | | $ | 154 | | | $ | 3 | | | $ | (3 | ) | | $ | 6,885 | | Operating expenses | | | 1,890 | | | | 1,087 | | | | 579 | | | | 105 | | | | 133 | | | | 122 | | | | 52 | | | | (5 | ) | | | 3,963 | | | | 1,890 | | | | 1,087 | | | | 579 | | | | 105 | | | | 133 | | | | 122 | | | | 52 | | | | (5 | ) | | | 3,963 | | Depreciation and amortization | | | 451 | | | | 109 | | | | 67 | | | | 8 | | | | — | | | | 10 | | | | 4 | | | | — | | | | 649 | | | | 451 | | | | 109 | | | | 67 | | | | 8 | | | | — | | | | 10 | | | | 4 | | | | — | | | | 649 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating income/(loss) | | | 1,685 | | | | 434 | | | | 100 | | | | 58 | | | | 25 | | | | 22 | | | | (53 | ) | | | 2 | | | | 2,273 | | | | 1,685 | | | | 434 | | | | 100 | | | | 58 | | | | 25 | | | | 22 | | | | (53 | ) | | | 2 | | | | 2,273 | | Equity in earnings/(loss) of unconsolidated affiliates | | | 9 | | | | — | | | | — | | | | (2 | ) | | | 52 | | | | — | | | | — | | | | — | | | | 59 | | | | 9 | | | | — | | | | — | | | | (2 | ) | | | 52 | | | | — | | | | — | | | | — | | | | 59 | | Other income, net | | | 9 | | | | 12 | | | | 1 | | | | 1 | | | | 5 | | | | — | | | | 20 | | | | (31 | ) | | | 17 | | | | 9 | | | | 12 | | | | 1 | | | | 1 | | | | 5 | | | | — | | | | 20 | | | | (31 | ) | | | 17 | | Interest expense | | | (100 | ) | | | (56 | ) | | | (51 | ) | | | (6 | ) | | | — | | | | (6 | ) | | | (420 | ) | | | 19 | | | | (620 | ) | | | (100 | ) | | | (56 | ) | | | (51 | ) | | | (6 | ) | | | — | | | | (6 | ) | | | (383 | ) | | | 19 | | | | (583 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations before income taxes | | | 1,603 | | | | 390 | | | | 50 | | | | 51 | | | | 82 | | | | 16 | | | | (453 | ) | | | (10 | ) | | | 1,729 | | | | 1,603 | | | | 390 | | | | 50 | | | | 51 | | | | 82 | | | | 16 | | | | (416 | ) | | | (10 | ) | | | 1,766 | | Income tax expense | | | 692 | | | | — | | | | — | | | | — | | | | 19 | | | | — | | | | 2 | | | | — | | | | 713 | | | | 692 | | | | — | | | | — | | | | — | | | | 19 | | | | — | | | | 2 | | | | — | | | | 713 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations | | | 911 | | | | 390 | | | | 50 | | | | 51 | | | | 63 | | | | 16 | | | | (455 | ) | | | (10 | ) | | | 1,016 | | | | 911 | | | | 390 | | | | 50 | | | | 51 | | | | 63 | | | | 16 | | | | (418 | ) | | | (10 | ) | | | 1,053 | | Income from discontinued operations, net of income taxes | | | — | | | | — | | | | — | | | | — | | | | 172 | | | | — | | | | — | | | | — | | | | 172 | | | | — | | | | — | | | | — | | | | — | | | | 172 | | | | — | | | | — | | | | — | | | | 172 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income/(loss) | | $ | 911 | | | $ | 390 | | | $ | 50 | | | $ | 51 | | | $ | 235 | | | $ | 16 | | | $ | (455 | ) | | $ | (10 | ) | | $ | 1,188 | | | | 911 | | | | 390 | | | | 50 | | | | 51 | | | | 235 | | | | 16 | | | | (418 | ) | | | (10 | ) | | | 1,225 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income/(loss) attributable to NRG Energy, Inc. | | | $ | 911 | | | $ | 390 | | | $ | 50 | | | $ | 51 | | | $ | 235 | | | $ | 16 | | | $ | (418 | ) | | $ | (10 | ) | | $ | 1,225 | | | | | | | | | | | | | | | | | | | | | | | Balance sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity investments in affiliates | | $ | 92 | | | $ | 1 | | | $ | — | | | $ | 25 | | | $ | 372 | | | $ | — | | | $ | — | | | $ | — | | | $ | 490 | | | $ | 92 | | | $ | 1 | | | $ | — | | | $ | 25 | | | $ | 372 | | | $ | — | | | $ | — | | | $ | — | | | $ | 490 | | Capital expenditures | | | 238 | | | | 208 | | | | 14 | | | | 35 | | | | — | | | | 11 | | | | 509 | | | | — | | | | 1,015 | | | | 238 | | | | 208 | | | | 14 | | | | 35 | | | | — | | | | 11 | | | | 509 | | | | — | | | | 1,015 | | Goodwill | | | 1,713 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 5 | | | | — | | | | 1,718 | | | | 1,713 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 5 | | | | — | | | | 1,718 | | Total assets | | $ | 12,899 | | | $ | 1,667 | | | $ | 933 | | | $ | 264 | | | $ | 973 | | | $ | 208 | | | $ | 20,208 | | | $ | (12,344 | ) | | $ | 24,808 | | | $ | 12,899 | | | $ | 1,667 | | | $ | 933 | | | $ | 264 | | | $ | 973 | | | $ | 208 | | | $ | 20,215 | | | $ | (12,351 | ) | | $ | 24,808 | |
193201
NRG ENERGY, INC. AND SUBSIDIARIES
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2007 | | | | Wholesale Power Generation | | | | | | | | | | | | | | | | | | | | | | South
| | | | | | | | | | | | | | | | | | | | | | Texas | | | Northeast | | | Central | | | West | | | International | | | Thermal | | | Corporate | | | Elimination | | | Total | | | | (In millions) | | | Operating revenues | | $ | 3,287 | | | $ | 1,605 | | | $ | 658 | | | $ | 127 | | | $ | 140 | | | $ | 159 | | | $ | 30 | | | $ | (17 | ) | | $ | 5,989 | | Operating expenses | | | 1,849 | | | | 1,045 | | | | 533 | | | | 85 | | | | 112 | | | | 125 | | | | 47 | | | | (8 | ) | | | 3,788 | | Depreciation and amortization | | | 469 | | | | 102 | | | | 68 | | | | 3 | | | | — | | | | 11 | | | | 5 | | | | — | | | | 658 | | Gain/(loss) on disposal/sale of assets | | | — | | | | — | | | | — | | | | — | | | | — | | | | 18 | | | | (1 | ) | | | — | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating income/(loss) | | | 969 | | | | 458 | | | | 57 | | | | 39 | | | | 28 | | | | 41 | | | | (23 | ) | | | (9 | ) | | | 1,560 | | Equity in earnings/(loss) of unconsolidated affiliates | | | — | | | | — | | | | — | | | | (3 | ) | | | 57 | | | | — | | | | — | | | | — | | | | 54 | | Gains on sales of equity method investments | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | 1 | | Other income, net | | | 7 | | | | — | | | | — | | | | — | | | | 8 | | | | 1 | | | | 58 | | | | (19 | ) | | | 55 | | Refinancing expenses | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (35 | ) | | | — | | | | (35 | ) | Interest expense | | | (164 | ) | | | (57 | ) | | | (53 | ) | | | — | | | | (5 | ) | | | (6 | ) | | | (436 | ) | | | 19 | | | | (702 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations before income taxes | | | 812 | | | | 401 | | | | 4 | | | | 36 | | | | 88 | | | | 36 | | | | (435 | ) | | | (9 | ) | | | 933 | | Income tax expense/(benefit) | | | 327 | | | | — | | | | — | | | | — | | | | (12 | ) | | | — | | | | 62 | | | | — | | | | 377 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations | | | 485 | | | | 401 | | | | 4 | | | | 36 | | | | 100 | | | | 36 | | | | (497 | ) | | | (9 | ) | | | 556 | | Income from discontinued operations, net of income taxes | | | — | | | | — | | | | — | | | | — | | | | 17 | | | | — | | | | — | | | | — | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income/(loss) | | | 485 | | | | 401 | | | | 4 | | | | 36 | | | | 117 | | | | 36 | | | | (497 | ) | | | (9 | ) | | | 573 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Income/(loss) attributable to NRG Energy, Inc. | | $ | 485 | | | $ | 401 | | | $ | 4 | | | $ | 36 | | | $ | 117 | | | $ | 36 | | | $ | (497 | ) | | $ | (9 | ) | | $ | 573 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2007 | | | | Wholesale Power Generation | | | | | | | | | | | | | | | | | | | | | | South
| | | | | | | | | | | | | | | | | | | | | | Texas | | | Northeast | | | Central | | | West | | | International | | | Thermal | | | Corporate | | | Elimination | | | Total | | | | (In millions) | | | Operating revenues | | $ | 3,287 | | | $ | 1,605 | | | $ | 658 | | | $ | 127 | | | $ | 140 | | | $ | 159 | | | $ | 30 | | | $ | (17 | ) | | $ | 5,989 | | Operating expenses | | | 1,849 | | | | 1,045 | | | | 533 | | | | 85 | | | | 112 | | | | 125 | | | | 47 | | | | (8 | ) | | | 3,788 | | Depreciation and amortization | | | 469 | | | | 102 | | | | 68 | | | | 3 | | | | — | | | | 11 | | | | 5 | | | | — | | | | 658 | | Gain/(loss) on sale of assets | | | — | | | | — | | | | — | | | | — | | | | — | | | | 18 | | | | (1 | ) | | | — | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating income/(loss) | | | 969 | | | | 458 | | | | 57 | | | | 39 | | | | 28 | | | | 41 | | | | (23 | ) | | | (9 | ) | | | 1,560 | | Equity in earnings/(loss) of unconsolidated affiliates | | | — | | | | — | | | | — | | | | (3 | ) | | | 57 | | | | — | | | | — | | | | — | | | | 54 | | Gains on sale of equity method investment | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | 1 | | Other income, net | | | 7 | | | | — | | | | — | | | | — | | | | 8 | | | | 1 | | | | 58 | | | | (19 | ) | | | 55 | | Refinancing expenses | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (35 | ) | | | — | | | | (35 | ) | Interest expense | | | (164 | ) | | | (57 | ) | | | (53 | ) | | | — | | | | (5 | ) | | | (6 | ) | | | (423 | ) | | | 19 | | | | (689 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations before income taxes | | | 812 | | | | 401 | | | | 4 | | | | 36 | | | | 88 | | | | 36 | | | | (422 | ) | | | (9 | ) | | | 946 | | Income tax expense/(benefit) | | | 327 | | | | — | | | | — | | | | — | | | | (12 | ) | | | — | | | | 62 | | | | — | | | | 377 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations | | | 485 | | | | 401 | | | | 4 | | | | 36 | | | | 100 | | | | 36 | | | | (484 | ) | | | (9 | ) | | | 569 | | Income from discontinued operations, net of income taxes | | | — | | | | — | | | | — | | | | — | | | | 17 | | | | — | | | | — | | | | — | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income/(loss) | | $ | 485 | | | $ | 401 | | | $ | 4 | | | $ | 36 | | | $ | 117 | | | $ | 36 | | | $ | (484 | ) | | $ | (9 | ) | | $ | 586 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity investments in affiliates | | $ | — | | | $ | 1 | | | $ | — | | | $ | 27 | | | $ | 397 | | | $ | — | | | $ | — | | | $ | — | | | $ | 425 | | Capital expenditures | | | 190 | | | | 106 | | | | 30 | | | | 80 | | | | — | | | | 6 | | | | 69 | | | | — | | | | 481 | | Goodwill | | | 1,781 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 5 | | | | — | | | | 1,786 | | Total assets | | $ | 12,165 | | | $ | 1,572 | | | $ | 995 | | | $ | 246 | | | $ | 1,169 | | | $ | 211 | | | $ | 12,847 | | | $ | (9,931 | ) | | $ | 19,274 | |
194202
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2006 | | | | Wholesale Power Generation | | | | | | | | | | | | | | | | | | | | | | South
| | | | | | | | | | | | | | | | | | | | | | Texas | | | Northeast | | | Central | | | West | | | International | | | Thermal | | | Corporate | | | Elimination | | | Total | | | | (In millions) | | | Operating revenues | | $ | 3,088 | | | $ | 1,543 | | | $ | 570 | | | $ | 146 | | | $ | 135 | | | $ | 152 | | | $ | 12 | | | $ | (61 | ) | | $ | 5,585 | | Operating expenses | | | 1,794 | | | | 993 | | | | 397 | | | | 135 | | | | 110 | | | | 121 | | | | 30 | | | | (3 | ) | | | 3,577 | | Depreciation and amortization | | | 413 | | | | 89 | | | | 68 | | | | 3 | | | | — | | | | 12 | | | | 5 | | | | — | | | | 590 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating income/(loss) | | | 881 | | | | 461 | | | | 105 | | | | 8 | | | | 25 | | | | 19 | | | | (23 | ) | | | (58 | ) | | | 1,418 | | Equity in earnings of unconsolidated affiliates | | | — | | | | — | | | | — | | | | 1 | | | | 57 | | | | — | | | | 2 | | | | — | | | | 60 | | Gains on sales of equity method investments | | | — | | | | — | | | | — | | | | — | | | | 3 | | | | — | | | | 5 | | | | — | | | | 8 | | Other income, net | | | 9 | | | | 6 | | | | — | | | | 1 | | | | 7 | | | | 1 | | | | 152 | | | | (20 | ) | | | 156 | | Refinancing expenses | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (187 | ) | | | — | | | | (187 | ) | Interest expense | | | (138 | ) | | | (63 | ) | | | (57 | ) | | | — | | | | (1 | ) | | | (7 | ) | | | (344 | ) | | | 20 | | | | (590 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations before income taxes | | | 752 | | | | 404 | | | | 48 | | | | 10 | | | | 91 | | | | 13 | | | | (395 | ) | | | (58 | ) | | | 865 | | Income tax expense/(benefit) | | | 23 | | | | — | | | | — | | | | (2 | ) | | | 23 | | | | — | | | | 278 | | | | — | | | | 322 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income/(loss) from continuing operations | | | 729 | | | | 404 | | | | 48 | | | | 12 | | | | 68 | | | | 13 | | | | (673 | ) | | | (58 | ) | | | 543 | | Income from discontinued operations, net of income taxes | | | — | | | | — | | | | — | | | | — | | | | 61 | | | | — | | | | 17 | | | | — | | | | 78 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income/(loss) | | $ | 729 | | | $ | 404 | | | $ | 48 | | | $ | 12 | | | $ | 129 | | | $ | 13 | | | $ | (656 | ) | | $ | (58 | ) | | $ | 621 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
195
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The income tax provision from continuing operations for the years ended December 31, 2009, 2008 2007 and 20062007 consisted of the following amounts: | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | | | | (In millions) | | | (In millions) | | | Current | | | | | | | | | | | | | | | | | | | | | | | | | US Federal | | $ | 89 | | | $ | (6 | ) | | $ | (26 | ) | | U.S. Federal | | | $ | 99 | | | $ | 89 | | | $ | (6 | ) | State | | | 31 | | | | (1 | ) | | | (1 | ) | | | 20 | | | | 31 | | | | (1 | ) | Foreign | | | 17 | | | | 20 | | | | 19 | | | | 18 | | | | 17 | | | | 20 | | | | | | | | | | | | | | | | | | | | 137 | | | | 13 | | | | (8 | ) | | | 137 | | | | 137 | | | | 13 | | | | | | | | | | | | | | | | | Deferred | | | | | | | | | | | | | | | | | | | | | | | | | US Federal | | | 539 | | | | 347 | | | | 288 | | | U.S. Federal | | | | 599 | | | | 539 | | | | 347 | | State | | | 35 | | | | 47 | | | | 38 | | | | 1 | | | | 35 | | | | 47 | | Foreign | | | 2 | | | | (30 | ) | | | 4 | | | | (9 | ) | | | 2 | | | | (30 | ) | | | | | | | | | | | | | | | | | | | 576 | | | | 364 | | | | 330 | | | | 591 | | | | 576 | | | | 364 | | | | | | | | | | | | | | | | | Total income tax | | $ | 713 | | | $ | 377 | | | $ | 322 | | | $ | 728 | | | $ | 713 | | | $ | 377 | | | | | | | | | | | | | | | | | Effective tax rate | | | 41.2 | % | | | 39.9 | % | | | 37.2 | % | | | 43.6 | % | | | 40.4 | % | | | 40.4 | % |
The following represents the domestic and foreign components of income from continuing operations before income tax expense for the years ended December 31, 2009, 2008 2007 and 2006:2007: | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | | | | (In millions) | | | (In millions) | | | US | | $ | 1,644 | | | $ | 860 | | | $ | 767 | | | U.S. | | | $ | 1,508 | | | $ | 1,681 | | | $ | 847 | | Foreign | | | 85 | | | | 86 | | | | 98 | | | | 161 | | | | 85 | | | | 86 | | | | | | | | | | | | | | | | | Total | | $ | 1,729 | | | $ | 946 | | | $ | 865 | | | $ | 1,669 | | | $ | 1,766 | | | $ | 933 | | | | | | | | | | | | | | | | |
196
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
A reconciliation of the USU.S. federal statutory rate of 35% to NRG’s effective rate from continuing operations for the years ended December 31, 2009, 2008 2007 and 20062007 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | Year Ended December 31, | | | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | | | | (In millions, except percentages) | | | (In millions, except percentages) | | | Income from continuing operations before income taxes | | $ | 1,729 | | | $ | 946 | | | $ | 865 | | | $ | 1,669 | | | $ | 1,766 | | | $ | 933 | | | | | | | | | | | | | | | | | Tax at 35% | | | 605 | | | | 331 | | | | 303 | | | | 584 | | | | 618 | | | | 327 | | State taxes, net of federal benefit | | | 73 | | | | 46 | | | | 34 | | | | 23 | | | | 74 | | | | 46 | | Foreign operations | | | (10 | ) | | | (13 | ) | | | (21 | ) | | | (53 | ) | | | (10 | ) | | | (13 | ) | Subpart F taxable income | | | 2 | | | | — | | | | 11 | | | | — | | | | 2 | | | | — | | Valuation allowance, including change in state effective rate | | | (12 | ) | | | 6 | | | | (10 | ) | | Valuation allowance | | | | 119 | | | | (12 | ) | | | 6 | | Expiration of capital losses | | | | 249 | | | | — | | | | — | | Reversal of valuation allowance on expired capital losses | | | | (249 | ) | | | — | | | | — | | Change in state effective tax rate | | | (11 | ) | | | — | | | | 21 | | | | (5 | ) | | | (11 | ) | | | — | | Claimant reserve settlements | | | — | | | | — | | | | (28 | ) | | Change in local German effective tax rates | | | — | | | | (29 | ) | | | — | | | | — | | | | — | | | | (29 | ) | Foreign dividends | | | 32 | | | | 26 | | | | 1 | | | Foreign dividends and foreign earnings | | | | 33 | | | | 32 | | | | 26 | | Non-deductible interest | | | 26 | | | | 10 | | | | 3 | | | | 10 | | | | 12 | | | | 10 | | Permanent differences, reserves, other | | | 8 | | | | — | | | | 8 | | | FIN 48 interest | | | | 9 | | | | 8 | | | | — | | Production tax credit | | | | (10 | ) | | | — | | | | — | | Other | | | | 18 | | | | — | | | | 4 | | | | | | | | | | | | | | | | | Income tax expense | | $ | 713 | | | $ | 377 | | | $ | 322 | | | $ | 728 | | | $ | 713 | | | $ | 377 | | | | | | | | | | | | | | | | | Effective income tax rate | | | 41.2 | % | | | 39.9 | % | | | 37.2 | % | | | 43.6 | % | | | 40.4 | % | | | 40.4 | % |
The effective income tax rate for the year ended December 31, 2009, 2008 and 2007 differs from the USU.S. statutory rate of 35% due to changes in the valuation allowance as a taxable dividend from foreign operations, includingresult of capital gain or losses generated 203
during the provision of deferred taxes in 2008 on foreign income no longer expected to be permanently reinvested overseas, and non-deductible interest.period. In addition, the current earnings in foreign jurisdictions are taxed at rates lower than the USU.S. statutory rate, including the impactsale of a law change that reduced the GermanMIBRAG in 2009 which resulted in minimal tax rate. For the year ended December 31, 2006, the effective tax rate differs from the US. statutory rate of 35% due to settlements paid from a claimant reserve established at bankruptcy as well as earnings in foreign jurisdictions that are taxed at rates lower than the US statutory rate.local jurisdiction. For the year ended December 31, 2008,2009, NRG’s state effective income tax rate has been reduced to 6%3%, which is lower than its 20072008 rate of 7%6%, due to increased operational activities within the state of Texas in the current year. For the year ended December 31, 2006, the Company decreased the estimated state effective income tax rate to 7% from the prior year state income tax rate of 9%. This decrease was primarily due to the acquisition of Texas Genco LLC,Reliant Energy which operates in the state of Texas where there was no state income tax as of December 31, 2006. A decrease to the net deferred tax asset balance of approximately $24 million, of which $21 million is derived from continuing operations and $3 million is from discontinued operations, has been recorded for this change during 2006. In addition, a reduction of $22 million, of which $19 million is generated from continuing operations and $3 million is from discontinued operations, reflected in our domestic valuation allowance, was recorded due to a change in our estimated state effective income tax rate during 2006.
197
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Texas.
The temporary differences, which gave rise to the Company’s deferred tax assets and liabilities as of December 31, 20082009 and 2007,2008, consisted of the following: | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | | | | 2008 | | 2007 | | | 2009 | | 2008 | | | | (In millions) | | | (In millions) | | | Deferred tax liabilities: | | | | | | | | | | | | | | | | | Discount/premium on notes | | $ | 13 | | | $ | 23 | | | $ | 12 | | | $ | 13 | | Emissions allowances | | | 112 | | | | 109 | | | | 119 | | | | 112 | | Difference between book and tax basis of property | | | 1,477 | | | | 1,568 | | | | 1,604 | | | | 1,477 | | Derivatives, net | | | 440 | | | | — | | | | 434 | | | | 440 | | Goodwill | | | 73 | | | | 45 | | | | 93 | | | | 73 | | Anticipated repatriation of foreign earnings | | | 26 | | | | — | | | | 6 | | | | 26 | | Cumulative translation adjustments | | | 22 | | | | — | | | | 29 | | | | 22 | | Development costs | | | | 16 | | | | — | | Intangibles amortization (excluding goodwill) | | | | 242 | | | | — | | Investment in projects | | | — | | | | 6 | | | | 32 | | | | — | | | | | | | | | | | | | Total deferred tax liabilities | | | 2,163 | | | | 1,751 | | | | 2,587 | | | | 2,163 | | | | | | | | | | | | | Deferred tax assets: | | | | | | | | | | | | | | | | | Deferred compensation, pension, accrued vacation and other reserves | | | 126 | | | | 129 | | | | 195 | | | | 126 | | Derivatives, net | | | — | | | | 125 | | | Differences between book and tax basis of contracts | | | 377 | | | | 577 | | | | 270 | | | | 377 | | Non-depreciable property | | | 19 | | | | 19 | | | | 19 | | | | 19 | | Intangibles amortization (excluding goodwill) | | | 164 | | | | 152 | | | | — | | | | 164 | | Equity compensation | | | 22 | | | | 15 | | | | 26 | | | | 22 | | Claimants reserve | | | 10 | | | | 7 | | | | — | | | | 10 | | US capital loss carryforwards | | | 274 | | | | 439 | | | U.S. capital loss carryforwards | | | | 135 | | | | 274 | | Foreign net operating loss carryforwards | | | 66 | | | | 80 | | | | 78 | | | | 66 | | State net operating loss carryforwards | | | 28 | | | | — | | | | 28 | | | | 28 | | Foreign capital loss carryforwards | | | 1 | | | | 1 | | | | 1 | | | | 1 | | Investments in projects | | | 10 | | | | — | | | | — | | | | 10 | | Deferred financing costs | | | 10 | | | | 12 | | | | 7 | | | | 10 | | Alternative minimum tax | | | 20 | | | | 3 | | | | 40 | | | | 20 | | Federal benefit on state FIN 48 liabilities | | | | 30 | | | | — | | Other | | | 4 | | | | 12 | | | | 11 | | | | 4 | | | | | | | | | | | | | Total deferred tax assets | | | 1,131 | | | | 1,571 | | | | 840 | | | | 1,131 | | Valuation allowance | | | (359 | ) | | | (539 | ) | | | (233 | ) | | | (359 | ) | | | | | | | | | | | | Net deferred tax assets | | | 772 | | | | 1,032 | | | | 607 | | | | 772 | | | | | | | | | | | | | Net deferred tax liability | | $ | 1,391 | | | $ | 719 | | | $ | 1,980 | | | $ | 1,391 | | | | | | | | | | | | |
198
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes NRG’s net deferred tax position as of December 31, 20082009 and 2007:2008: | | | | | | | | | | | | | | | | | | | As of December 31, | | | As of December 31, | | | | 2008 | | 2007 | | | 2009 | | 2008 | | | | (In millions) | | | (In millions) | | | Current deferred tax asset | | $ | — | | | $ | 124 | | | Current deferred tax liability | | | 201 | | | | — | | | $ | 197 | | | $ | 201 | | Non-current deferred tax liability | | | 1,190 | | | | 843 | | | | 1,783 | | | | 1,190 | | | | | | | | | | | | | Net deferred tax liability | | $ | 1,391 | | | $ | 719 | | | $ | 1,980 | | | $ | 1,391 | | | | | | | | | | | | |
204
Tax Receivable and Payable As of December 31, 2008,2009, NRG recorded a current tax payable of approximately $30$32 million that represents a tax liability due to afor domestic state taxtaxes of approximately $24$20 million, as well as foreign taxes payable of approximately $6$12 million. In addition, NRG has a domestic tax receivable of $54 million.$153 million, of which $102 million is federal cash grant receivable on Blythe Solar and Langford plants. Deferred tax assets and valuation allowance Net deferred tax balance — As of December 31, 20082009, and 2007,2008, NRG recorded a net deferred tax liability of $1,032$1,747 million and $180$1,032 million, respectively. However, due to an assessment of positive and negative evidence, including projected capital gains and available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $359$233 million and $539$359 million of tax assets, thus a valuation allowance has remained, resulting in a net deferred tax liability of $1,391$1,980 million and $719$1,391 million as of December 31, 20082009 and 2007,2008, respectively. NRG believes it is more likely than not that future earnings will be sufficient to utilize the Company’s deferred tax assets, net of the existing valuation allowances at December 31, 2008.2009. NOL carryforwards — For the years endedAt December 31, 20082009, and 2007,2008, the Company generated total domestic pretax book income of $1,644 million and $860 million, respectively. As a result, ahad cumulative domesticstate net operating loss,losses, or NOL, in the amount $245 million had been fully utilized asNOLs, of December 31, 2007 with the exception of certain state NOLs.$28 million. These NOLs will expire starting 2010. In addition, as of December 31, 2008,2009, NRG has cumulative foreign NOL carryforwards of $239$280 million of which $41$82 million will expire starting 2011 through 2017 and of which $198 million do not have an expiration date. Valuation allowance — As of December 31, 2008,2009, the Company’s valuation allowance and other deferred tax items werewas reduced by $249 million as a result of the reduction in NRG’s net deferred tax assets. In accordance withSOP 90-7, these movements resulted in an increase in Additional Paid in Capital and income tax benefitexpiration of approximately $162 million and $12 million respectively. In accordance with SFAS 141R, any future reductions tounused capital loss carryforwards. The valuation allowance occurring after January 1, 2009 will be credited to incomewas increased by $123 million primarily for certain derivative contracts that are eligible for capital loss treatment for tax expense rather than APIC. APIC adjustment —During 2008, the Company recorded $14 million through APIC for various Fresh-Start related book-tax differences.
APB Opinion 23
Through 2007, it was management’s intent to permanently reinvest unremitted earnings overseaspurposes resulting in accordance with APB Opinion No. 23Accounting for Income Taxes — Special Areas, or APB 23. If NRG does not permanently reinvest earnings, then deferred taxesa net reduction of approximately $39 million would have been recognized for the cumulative translation adjustment as of December 31, 2007.
199
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)$126 million.
Uncertain tax benefits NRG has identified certain unrecognized tax benefits whose after-tax value was $527$643 million of which $36 millionthat if recognized, would impact the Company’s income tax expense. Of the $527 million in unrecognized tax benefits, $491 million relates to periods prior to the Company’s emergence from bankruptcy. In accordance with Statement of Position90-7,Financial Reporting by Entities in Reorganization under the Bankruptcy Code, and the application of fresh start accounting, recognition of previously unrecognized tax benefits existing pre-emergence would not impact the Company’s effective tax rate but would increase Additional Paid in Capital, or APIC. In accordance with SFAS 141R, any changes to our uncertain tax benefits occurring after January 1, 2009 will be credited to income tax expense rather than APIC. As of December 31, 2009, and 2008, NRG has recorded a $208 million non-current tax liability of $347 and $208 million, respectively, for unrecognized tax benefits resulting from taxable earnings for the period for which there are no NOLs available to offset for financial statement purposes. NRG accrued interest and penalties related to these unrecognized tax benefits of approximately $8 million as of December 31, 2008. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2009, and 2008, the Company recognized approximately $9 million, and $8 million, respectively, in interest and penalties. For the year ended December 31, 2007, the Company incurred an immaterial amount of interest and penalties related to its unrecognized tax benefits.benefit. As of December 31, 2009, and 2008, NRG had accrued interest and penalties related to these unrecognized tax benefits of approximately $17 and $8 million, respectively. Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the USU.S. federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to USU.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company’s significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2000. The Company has been contacted forcontinues to be under examination by the Internal Revenue Service, or IRS, for years 2004 through 2006. The audit commencedIt is possible that the IRS examination may conclude during 2010 but because of a possible extension, an estimate of the third quarter 2008 and is expected to continue for approximately 18 to 24 months.range of reasonably possible changes in unrecognized tax benefits cannot be made. Sale of ITISA — On April 28, 2008, NRG completed the sale of its 100% interest in Tosli Acquisition B.V., or Tosli, which held all NRG’s interest in ITISA, to Brookfield Renewable Power Inc. (previously Brookfield Power Inc.), a wholly-owned subsidiary of Brookfield Asset Management Inc. In addition, the purchase price adjustment contingency under the sale agreement was resolved on August 7, 2008. In connection with the sale, NRG recorded a capital gain of $215$218 million which further reduced ourthe Company’s uncertain tax benefits. 205
The following table reconciles the total amounts of unrecognized tax benefits at the beginning and end of the respective periods: | | | | | | | | | | | | | | | | | | | As of
| | As of
| | | As of
| | As of
| | | | December 31,
| | December 31,
| | | December 31,
| | December 31,
| | | | 2008 | | 2007 | | | 2009 | | 2008 | | | | (In millions) | | (In millions) | | | (In millions) | | | Balance as of January 1 | | $ | 683 | | | $ | 712 | | | $ | 527 | | | $ | 683 | | Increase due to current year positions | | | 18 | | | | 76 | | | | 80 | | | | 18 | | Decrease due to current year positions | | | (183 | ) | | | (105 | ) | | | — | | | | (183 | ) | Increase due to prior year positions | | | 9 | | | | — | | | | 40 | | | | 9 | | Decrease due to prior year positions | | | — | | | | — | | | | (4 | ) | | | — | | Decrease due to settlements and payments | | | — | | | | — | | | | — | | | | — | | Decrease due to statute expirations | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | Unrecognized tax benefits as of December 31 | | $ | 527 | | | $ | 683 | | | $ | 643 | | | $ | 527 | | | | | | | | | | | | |
200
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Due toIncluded in the classification of NOL’s as capital losses for financial statement purposes, $292balance at December 31, 2009, are $43 million of tax positions for which the Company’s $527 million unrecognizedultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax benefit will expire asaccounting, other than interest and penalties, the disallowance of December 31, 2009.the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash or use of net operating loss carryforwards to an earlier period.
German Tax Reform Act 2008 On July 6, 2007, the German government passed the Tax Reform Act of 2008, which reduces the German statutory and resulting effective tax rates on earnings from approximately 36% to approximately 27% effective January 1, 2008. Due to this reduction in the statutory and resulting effective tax rate in 2007, NRG recognized a $29 million tax benefit and as of December 31, 2007, NRG had a German net deferred tax liability of approximately $84 million which includes the impact of this tax rate change. | | Note 1920 — | Stock-Based Compensation |
The Company adopted SFAS 123R, effective January 1, 2006, with no material effect on NRG’s consolidated statements of operations.
Long-Term Incentive Plan, or LTIP As of December 31, 20082009, and 2007,2008, a total of 16,000,000 shares of NRG common stock were authorized for issuance under the LTIP, subject to adjustments in the event of reorganization, recapitalization, stock split, reverse stock split, stock dividend, and a combination of shares, merger or similar change in NRG’s structure or outstanding shares of common stock. It is NRG’s policy to issue treasury shares upon exercise of a LTIP award. If there are no treasury shares available, new shares of common stock will be issued. There were 6,798,0745,129,593 and 7,941,7586,798,074 shares of common stock remaining available for grants under NRG’s LTIP as of December 31, 20082009, and 2007,2008, respectively. Non-Qualified Stock Options, or NQSO’s NQSO’s granted under the LTIP typically have a three-year graded vesting schedule beginning on the grant date and become exercisable at the end of the requisite service period. NRG recognizes compensation costs for NQSO’s on a straight-line basis over the requisite service period for the entire award. The maximum contractual term is ten years for approximately 1.1 million of NRG’s outstanding NQSO’s, and six years for the remaining 2.93.7 million NQSO’s. 206
The following table summarizes the Company’s NQSO activity as of December 31, 20082009, and changes during the year then ended: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted
| | | | | | | | | Weighted
| | | | | | | | | | Average
| | | | | | | | | Average
| | | | | | | | Weighted
| | Remaining
| | Aggregate
| | | | | Weighted
| | Remaining
| | Aggregate
| | | | | | Average
| | Contractual Term
| | Intrinsic Value
| | | | | Average
| | Contractual Term
| | Intrinsic Value
| | | | Shares | | Exercise Price | | (in years) | | (In millions) | | | Shares | | Exercise Price | | (In years) | | (In millions) | | | | (In whole) | | | | | | | (In whole) | | | | | | | Outstanding at December 31, 2007 | | | 3,579,775 | | | $ | 19.98 | | | | | | | | | | | Outstanding at December 31, 2008 | | | | 4,008,188 | | | $ | 25.84 | | | | 4 | | | $ | 14 | | Granted | | | 1,206,800 | | | | 39.94 | | | | | | | | | | | | 1,406,500 | | | | 23.62 | | | | | | | | | | Forfeited | | | (250,401 | ) | | | 30.09 | | | | | | | | | | | | (506,103 | ) | | | 29.86 | | | | | | | | | | Exercised | | | (527,986 | ) | | | 16.41 | | | | | | | | | | | | (115,000 | ) | | | 13.21 | | | | | | | | | | | | | | | | | Outstanding at December 31, 2008 | | | 4,008,188 | | | | 25.84 | | | | 4 | | | $ | 14 | | | Outstanding at December 31, 2009 | | | | 4,793,585 | | | | 25.07 | | | | 4 | | | | 13 | | | | | | | | | Exercisable at December 31, 2008 | | | 2,009,205 | | | | 17.55 | | | | 4 | | | | 14 | | | Exercisable at December 31, 2009 | | | | 2,766,165 | | | | 22.21 | | | | 3 | | | | 13 | | | | | | | | |
201
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The weighted average grant date fair value of options granted during the years ended December 31, 2009, 2008 and 2007 was $8.64, $10.33, and 2006 was $10.33, $8.28, and $7.26, respectively. The total intrinsic value of options exercised during the years ended December 31, 2009, 2008 and 2007 and 2006 was $1.4 million, $14 million $11 million and $1$11 million, respectively and cash received from the exercise of these options was $2 million, $9 million $7 million and $1$7 million, respectively. The fair value of the Company’s NQSO’s is estimated on the date of grant using the Black-Scholes option-pricing model. Significant assumptions used in the fair value model for the years ended December 31, 2009, 2008, 2007 and 20062007 with respect to the Company’s NQSO’s are summarized below: | | | | | | | | | | | | | | | 2008 | | 2007 | | 2006 | | 2009 | | 2008 | | 2007 | | Expected volatility | | 26.75%-44.00% | | 25.88%-27.28% | | 27.95%-29.64% | | 44.36%-48.29% | | 26.75%-44.00% | | 25.88%-27.28% | Expected term (in years) | | 4 | | 4 | | 4-6 | | 4 | | 4 | | 4 | Risk free rate | | 1.33%-3.09% | | 4.58%-4.68% | | 4.30%-5.05% | | 1.43%-1.93% | | 1.33%-3.09% | | 4.58%-4.68% |
For 2006, expected volatility was calculated based on a blended average of NRG and NRG’s industry peers’ historical two-year stock price volatility data. For2009, 2008, and 2007, as more historical NRG data has become available, expected volatility is calculated based on NRG’s historical stock price volatility data over the period commensurate with the expected term of the stock option. Typically, the expected term for the Company’s NQSO’s is based on the simple average of the contractual term and vesting term. The Company uses this simplified method as it does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate the expected term. Restricted Stock Units, or RSU’s Typically, RSU’s granted under the Company’s LTIP fully vest three years from the date of issuance. Fair value of the RSU’s is based on the closing price of NRG common stock on the date of grant. The following table summarizes the Company’s non-vested RSU awards as of December 31, 20082009, and changes during the year then ended: | | | | | | | | | | | | | | | | | | | | | Weighted Average
| | | | | Weighted Average
| | | | | | Grant-Date Fair
| | | | | Grant-Date Fair
| | | | Units | | Value per Unit | | | Units | | Value per Unit | | | | (In whole) | | | (In whole) | | | Non-vested at December 31, 2007 | | | 1,588,316 | | | $ | 26.99 | | | Non-vested at December 31, 2008 | | | | 1,061,996 | | | $ | 32.97 | | Granted | | | 166,400 | | | | 39.84 | | | | 1,021,800 | | | | 26.13 | | Forfeited | | | (81,900 | ) | | | 32.23 | | | | (119,955 | ) | | | 31.79 | | Vested | | | (610,820 | ) | | | 19.38 | | | | (349,072 | ) | | | 23.50 | | | | | | | | | Non-vested at December 31, 2008 | | | 1,061,996 | | | | 32.97 | | | Non-vested at December 31, 2009 | | | | 1,614,769 | | | | 30.78 | | | | | | | | |
The total fair value of RSU’s vested during the years ended December 31, 2009, 2008, and 2007, and 2006, was $8 million, $22 million and $40 million, respectively. The weighted average grant date fair value of RSU’s granted during the years ended December 31, 2009, 2008 and $11 million,2007 was $26.13, $39.84 and $38.61, respectively. 207
Deferred Stock Units, or DSU’s DSU’s represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established under the terms of the award. DSU’s granted under the Company’s LTIP are fully vested at the date of issuance. Fair value of the DSU’s, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in the period of grant.
202
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes the Company’s outstanding DSU awards as of December 31, 20082009, and changes during the year then ended: | | | | | | | | | | | | | | | | | | | | | Weighted Average
| | | | | Weighted Average
| | | | | Grant-Date Fair
| | | | | Grant-Date Fair
| | | Units | | Value per Unit | | | Units | | Value per Unit | | | (In whole) | | | (In whole) | | Outstanding at December 31, 2007 | | | 268,994 | | | $ | 18.06 | | | Outstanding at December 31, 2008 | | | | 260,768 | | | $ | 18.50 | | Granted | | | 29,614 | | | | 35.12 | | | | 65,437 | | | | 22.77 | | Conversions | | | (37,840 | ) | | | 28.41 | | | | (22,156 | ) | | | 23.69 | | | | | | | | | Outstanding at December 31, 2008 | | | 260,768 | | | | 18.50 | | | Outstanding at December 31, 2009 | | | | 304,049 | | | | 19.34 | | | | | | | | |
The aggregate intrinsic values for DSU’s outstanding as of December 31, 2009, 2008, 2007 and 20062007 were approximately $7 million, $6 million, $12 million, and $8$12 million respectively. The aggregate intrinsic values for DSU’s converted to common stock for the years ended December 31, 2009, 2008 and 2007 and 2006 were $0.5 million, $1.5 million and $1.2 million, respectively. The weighted average grant date fair value of DSU’s granted during the years ended December 31, 2009, 2008 and $0.4 million,2007 was $22.77, $35.12 and $44.43, respectively. Performance Units, or PU’s PU’s granted under the Company’s LTIP fully vest three years from the date of issuance. PU’s granted prior to January 1, 2009, are paid out upon vesting if the average closing price of NRG’s common stock for the ten trading days prior toon the vesting date, or the Measurement Price, is equal to or greater than the Target Price. APU’s granted after January 1, 2009, are paid out upon vesting if the Measurement Price is equal to or greater than Threshold Price. The Threshold Price, Target Price and Maximum Price are determined on the date of issuance. The payout for each PU will be equal to: (i) a pro-rata amount between 0.5 and 1 share of common stock, if the Measurement Price is equal to or greater than the target Threshold Price but less than the Target Price, for grants made after January 1, 2009; (ii) one share of common stock, if the Measurement Price equals the Target Price; (ii)(iii) a pro-rata amount between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price; and (iii) two shares of common stock, if the Measurement Price is equal to, or greater than, the Maximum Price. PU’s granted after January 1, 2009 are paid out upon vesting if the Measurement Price is equal to or greater than 9% growth in the NRG stock price compounded annually over three years, or the Threshold Price. The payout for each PU will be equal to a pro-rated amount in between one-half and one share of common stock if the Measurement Price equals or exceeds the Threshold Price but less than the Target Price. The payout for each PU will be equal to a pro-rated amount in between one and two shares of common stock, if the Measurement Price is equal to the Target Price but less than the Maximum Price. The payout for each PU will be equal to(iv) two shares of common stock, if the Measurement Price is equal to, or greater than, the Maximum Price. The following table summarizes the Company’s non-vested PU awards as of December 31, 20082009, and changes during the year then ended: | | | | | | | | | | | | | | | | | | | | | Weighted Average
| | | | | Weighted Average
| | | Outstanding
| | Grant-Date Fair
| | | Outstanding
| | Grant-Date Fair
| | | Units | | Value per Unit | | | Units | | Value per Unit | | | (In whole except weighted average data) | | | (In whole except weighted average data) | | Non-vested at December 31, 2007 | | | 536,764 | | | $ | 20.18 | | | Non-vested at December 31, 2008 | | | | 659,564 | | | $ | 22.81 | | Granted | | | 233,700 | | | | 26.99 | | | | 339,300 | | | | 22.91 | | Vested | | | (50,000 | ) | | | 15.74 | | | Forfeited | | | (60,900 | ) | | | 21.65 | | | | (381,564 | ) | | | 20.86 | | | | | | | | | Non-vested at December 31, 2008 | | | 659,564 | | | | 22.81 | | | Non-vested at December 31, 2009 | | | | 617,300 | | | | 24.27 | | | | | | | | |
The weighted average grant date fair value of PU’s granted during the years ended December 31, 2009, 2008 and 2007 was $22.91, $26.99 and 2006 was $26.99, $22.43, and $17.62, respectively.
203208
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The fair value of PU’s is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period. Significant assumptions used in the fair value model for the years ended December 31, 2009, 2008 2007 and 20062007 with respect to the Company’s PU’s are summarized below: | | | | | | | | | | | | | | | 2008 | | 2007 | | 2006 | | 2009 | | 2008 | | 2007 | | Expected volatility | | 27.81%-48.06% | | 25.91%-27.28% | | 27.95%-29.64% | | 48.48%-53.00% | | 27.81%-48.06% | | 25.91%-27.28% | Expected term (in years) | | 3 | | 3 | | 3-5 | | 3 | | 3 | | 3 | Risk free rate | | 1.13%-2.89% | | 4.54%-4.69% | | 4.30%-5.04% | | 1.14%-1.48% | | 1.13%-2.89% | | 4.54%-4.69% |
For 2006, expected volatility was calculated based on a blended average of NRG and NRG’s industry peers’ historical two-year stock price volatility data. For2009, 2008, and 2007, as more historical NRG data has become available, expected volatility is calculated based on NRG’s historical stock price volatility data over the period commensurate with the expected term of the PU, which equals the vesting period. Supplemental Information The following table summarizes NRG’s total compensation expense recognized in accordance with SFAS 123RASC 718 for the years ended December 31, 2009, 2008, 2007 and 20062007 for each of the four types of awards issued under the Company’s LTIP, as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2008.2009. Minimum tax withholdings of $3 million, $10 million, $17 million and $5$17 million paid by the Company during 2009, 2008, 2007 and 2006,2007, respectively, are reflected as a reduction to additional paid in capitalAdditional Paid-in Capital on the Company’s statement of financial position, and are reflected as operating activities on the Company’s statement of cash flows. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Non-vested Compensation Cost | | | | | | | | | Non-vested Compensation Cost | | | | | | | | | | | | Weighted Average
| | | | | | | | | | | Weighted Average
| | | | | | | | | | | | Recognition Period
| | | | | | | | | | | Recognition Period
| | | | | | | | | | Unrecognized
| | Remaining
| | | | | | | | | Unrecognized
| | Remaining
| | | | Compensation Expense | | Total Cost | | (In years) | | | Compensation Expense | | Total Cost | | (In years) | | | | Year Ended December 31 | | As of December 31 | | | Year Ended December 31 | | As of December 31 | | Award | | 2008 | | 2007 | | 2006 | | 2008 | | 2008 | | | 2009 | | 2008 | | 2007 | | 2009 | | 2009 | | | | (In millions, except weighted average data) | | | (In millions, except weighted average data) | | | NQSO’s | | $ | 8 | | | $ | 5 | | | $ | 5 | | | $ | 11 | | | | 1.2 | | | $ | 9 | | | $ | 8 | | | $ | 5 | | | $ | 10 | | | | 2.2 | | RSU’s | | | 12 | | | | 10 | | | | 10 | | | | 18 | | | | 1.2 | | | | 11 | | | | 12 | | | | 10 | | | | 31 | | | | 1.8 | | DSU’s | | | 1 | | | | 1 | | | | 1 | | | | — | | | | — | | | | 1 | | | | 1 | | | | 1 | | | | — | | | | — | | PU’s | | | 5 | | | | 3 | | | | 2 | | | | 6 | | | | 1.1 | | | | 5 | | | | 5 | | | | 3 | | | | 6 | | | | 1.5 | | | | | | | | | | | | | | | | | | | | | Total | | $ | 26 | | | $ | 19 | | | $ | 18 | | | $ | 35 | | | | | | | $ | 26 | | | $ | 26 | | | $ | 19 | | | $ | 47 | | | | | | | | | | | | | | | | | | | | | | | | | Tax benefit recognized | | $ | 10 | | | $ | 8 | | | $ | 7 | | | | | | | | | | | $ | 10 | | | $ | 10 | | | $ | 8 | | | | | | | | | | | | | | | | | | | | | | | | |
Employee Stock Purchase Plan
In May 2008, NRG shareholders approved the adoption of the NRG Energy, Inc. Employee Stock Purchase Plan, or ESPP, pursuant to which eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at 85% of its fair market value on the exercise date. An exercise date occurs each June 30 and December 31. The initial six month employee withholding period began July 1, 2008 and ended December 31, 2008. As of December 31, 2008, there were 500,000 shares of treasury stock reserved for issuance under the ESPP. In January 2009, 41,706 shares were issued to employees accounts from the treasury stock reserve for the ESPP.
204
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other Compensation Arrangements Beginning in 2008, NRG also sponsorssponsored certain cash-settled equity award programs, under which employees are eligible to receive future cash compensation upon fulfillment of the vesting criteria for the particular program. The aggregate compensation expense for these arrangements was approximately $2 million and $1 million for the yearyears ended December 31, 2008.2009, and 2008, respectively. 209
| | Note 2021 — | Related Party Transactions |
Operating AgreementsThe following table summarizes NRG’s material related party transactions with affiliates that are included in the Company’s operating revenues, operating costs and other income and expense:
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2009 | | | 2008 | | | 2007 | | | | (In millions) | | | Revenues from Related Parties Included in Operating Revenues | | | | | | | | | | | | | MIBRAG(a) | | $ | 2 | | | $ | 4 | | | $ | 4 | | Gladstone | | | 2 | | | | 2 | | | | 1 | | GenConn | | | 7 | | | | 1 | | | | — | | Sherbino | | | — | | | | 1 | | | | — | | | | | | | | | | | | | | | Total | | $ | 11 | | | $ | 8 | | | $ | 5 | | | | | | | | | | | | | | | Expenses from Related Parties Included in Cost of Operations | | | | | | | | | | | | | MIBRAG(a) | | | | | | | | | | | | | Cost of purchased coal | | $ | 43 | | | $ | 57 | | | $ | 43 | | | | | | | | | | | | | | | Interest income from Related Parties Included in Other Income and Expense | | | | | | | | | | | | | GenConn(b) | | | 2 | | | | — | | | | — | | Kraftwerke Schkopau GBR | | | 4 | | | | 4 | | | | 4 | | | | | | | | | | | | | | | Total | | $ | 6 | | | $ | 4 | | | $ | 4 | | | | | | | | | | | | | | |
| | | (a) | | The period in 2009 is from January 1, 2009 to June 10, 2009. | | (b) | | For the period Apri1 1, 2009 to June 10, 2009. |
Gladstone- NRG has entered intoprovides services to Gladstone, an equity method investment, under an operation and maintenance, agreements, or O&M, agreements, with certain Company equity investments.agreement Fees for services under these contractsthis contract primarily include recovery of NRG’s costs of operating the plant as approved in the annual budget, as well as a base monthly fee. In addition, NRG has entered into GenConn and Sherbino -Under construction management, agreements, or CMA, agreements with GenConn and Sherbino. Under the CMA agreementsSherbino, NRG will receivehas received fees for management, design and construction services. The construction at Sherbino was completed during 2008. In addition, NRG also rendersentered into a loan agreement with GenConn during 2009, pursuant to which it receives interest income. See further discussion in Note 16,Investments Accounted for by the Equity Method. MIBRAG -Prior to NRG’s sale of its 50% ownership in MIBRAG on June 10, 2009, NRG rendered technical consulting services to MIBRAG under a consulting agreement and has alsohad entered into long-term coal purchase agreements with MIBRAG to supply coal to Schkopau. See further discussion in Note 4,Discontinued Operations and Dispositions. These feesKraftwerke Schkopau GBR -A subsidiary of NRG, Saale Energie GmbH has entered into a loan agreement with Kraftwerke Schkopau GBR, a partnership between Saale and expenses are includedE.ON Kraftwerke GmbH, pursuant to which NRG receives interest income. See further discussion in the Company’s operating revenuesNote 9,Capital Leases and operating costs in the consolidated statements of operations and consisted of the following:Notes Receivable.
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2008 | | | 2007 | | | 2006 | | | | (In millions) | | | Revenues from Related Parties Included in Operating Revenues | | | | | | | | | | | | | MIBRAG | | $ | 4 | | | $ | 4 | | | $ | 4 | | Gladstone | | | 2 | | | | 1 | | | | 2 | | GenConn | | | 1 | | | | — | | | | — | | Sherbino | | | 1 | | | | — | | | | — | | WCP(a) | | | — | | | | — | | | | 1 | | | | | | | | | | | | | | | Total | | $ | 8 | | | $ | 5 | | | $ | 7 | | | | | | | | | | | | | | | Expenses from Related Parties Included in Cost of Operations | | | | | | | | | | | | | MIBRAG | | | | | | | | | | | | | Cost of purchased coal | | $ | 57 | | | $ | 43 | | | $ | 43 | | | | | | | | | | | | | | |
| | | (a) | | For the period January 1, 2006 to March 31, 2006. |
| | Note 2122 — | Commitments and Contingencies |
Operating Lease Commitments NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2027.2040. NRG also has certain tolling arrangements to purchase power which qualifies as operating leases. Certain operating lease agreements over their lease term include provisions such as scheduled rent increases, leasehold incentives, and rent concessions. The Company recognizes the effects of these scheduled rent increases, leasehold incentives, and rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. RentalLease expense under operating leases was approximately $40$102 million, $40$54 million, and $37$40 million for the years ended December 31, 2009, 2008, 2007 and 2006,2007, respectively.
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Future minimum lease commitments under operating leases for the years ending after December 31, 20082009 are as follows: | | | | | | | | | Period | | (In millions) | | | (In millions) | | | 2009 | | $ | 43 | | | 2010 | | | 41 | | | $ | 100 | | 2011 | | | 38 | | | | 66 | | 2012 | | | 33 | | | | 54 | | 2013 | | | 29 | | | | 50 | | 2014 | | | | 48 | | Thereafter | | | 193 | | | | 264 | | | | | | | | | Total | | $ | 377 | | | $ | 582 | | | | | | | | |
Coal, Gas and Transportation Commitments NRG has entered into long-term contractual arrangements to procure fuel and transportation services for the Company’s generation assets and for the years ended December 31, 2009, 2008, 2007, and 2006,2007, the Company purchased approximately $1.8$1.4 billion, $1.7$2.0 billion, and $1.8$1.7 billion, respectively, under such arrangements. As of December 31, 2008,2009, the Company’s commitments under such outstanding agreements are estimated as follows: | | | | | | | | | Period | | (In millions) | | | (In millions) | | | 2009 | | $ | 1,513 | | | 2010 | | | 294 | | | $ | 1,011 | | 2011 | | | 183 | | | | 225 | | 2012 | | | 151 | | | | 180 | | 2013 | | | 31 | | | | 65 | | 2014 | | | | 75 | | Thereafter | | | 206 | | | | 600 | | | | | | | | | Total(a) | | $ | 2,378 | | | $ | 2,156 | | | | | | | | |
| | | (a) | | Includes those coal transportation and lignite commitments for 20092010 as no other nominations were made as of December 31, 2008.2009. Natural gas nomination is through February 2010.2011. |
Purchased Power Commitment NRG has purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities and do not qualify as operating leases. These contracts are not included in the consolidated balance sheet as of December 31, 2009. Minimum purchase commitment obligations under these agreements are as follows as of December 31, 2009: | | | | | | | | | | | | | | Variable | | Period | | Fixed Pricing(a) | | | Pricing(b) | | | | (In millions) | | | 2010 | | $ | 53 | | | $ | 2 | | 2011 | | | 30 | | | | 4 | | 2012 | | | 21 | | | | 1 | | 2013 | | | 10 | | | | — | | | | | | | | | | | Total(a) | | $ | 114 | | | $ | 7 | | | | | | | | | | |
| | | (a) | | As of December 31, 2010, the maximum remaining term under any individual purchased power contract is four years. | (b) | | For contracts with variable pricing components, estimated prices are based on forward commodity curves as of December 31, 2009. |
Other As a result of the acquisition of Reliant Energy, the Company acquired the naming rights, including advertising and other benefits, for a football stadium and other convention and entertainment facilities included in the stadium complex in Houston, Texas. Pursuant to this agreement, the Company is required to pay $10 million per year through 2031. 211
Lignite Contract with Texas Westmoreland Coal Co. The lignite used to fuel the Texas region’s Limestone facility is obtained from a surface mine, or the Jewett mine, adjacent to the Limestone facility under an amendeda long-term contract with Texas Westmoreland Coal Co,Co., or TWCC. During 2007, NRG and TWCC renegotiated a long-term contract that significantly changed the contractual structure as well as extended the mining period. The new contract is based on a cost-plus arrangement with incentives and penalties to ensure proper management of the mine. NRG has the flexibility to increase or decrease lignite purchases from the mine within certain ranges, including the ability to suspend or terminate lignite purchases with adequate notice. The mining period was extended through 2018 with an option to extend the mining period by two five-year intervals. TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, NRG will be responsible for final mine reclamation obligations. Due to an increase in reclamation estimates offset by the negotiated three-year extension of the mining contract, the Company’s ARO for mine reclamation costs increased by $5 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Railroad Commission of Texas has imposed a bond obligation of approximately $83 million on TWCC for the reclamation of this lignite mine. Pursuant to the contract with TWCC, an affiliate of CenterPoint Energy, Inc. has guaranteed $50$107 million of this obligation. The remaining sum ofobligation and approximately $33 million has been bonded by the mine operator, TWCC. Approximately $7$32 million of such amount is supported by a letterletters of credit posted by NRG. Under the terms of the new cost plus agreement with TWCC, NRG is required to maintain a corporate guarantee of TWCC’s bond obligation in the amount of $50 million ifwhen CenterPoint Energy, Inc.’s obligation lapses in April 2010, or pay the costs of obtaining replacement performance assurance. Additionally, NRG is required to provide additional performance assurance over TWCC’s current bond obligations if required by the Commission. International Commitments
Two of the Company’s wholly-owned, indirect subsidiaries are severally responsible for the pro rata payments of principal, interest and related costs incurred in connection On January 14, 2010, NRG made a filing with the financingRailroad Commission of NRG’s equity investmentTexas to provide a corporate guaranty and indemnity in the unincorporated joint venture Gladstone Power Station. At December 31, 2008,amount of $50 million in support of TWCC’s bond obligation. NRG’s corporate guaranty and indemnity will become effective on April 14, 2010, upon acceptance by the Company was obligated for the loan of AUD 20 million (approximately US $14 million) in principal. This loan is scheduled to be fully repaid on March 31, 2009.Texas Railroad Commission.
First and Second Lien Structure NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets. NRG uses the first or second lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations underout-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty arein-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volumes that can be hedged, not the value of underlyingout-of-the money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first and second lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date. The Company’sNRG’s lien counterparties may have a claim on ourthe Company’s assets to the extent market prices exceed the hedged price. As of December 31, 20082009, and February 2, 2009, the first lien exposure of net out-of-the-money positions to counterparties on hedges was $88 million and $43 million, respectively. As of December 31, 2008 and February 2, 2009, there was no exposure to out-of-the-money positions to counterparties on9, 2010, all hedges under the first and second lien.liens werein-the-money on a counterparty aggregate basis.
RepoweringNRG Initiatives NRG has made non-refundable payments of $188 million in support of expected deliveries of wind turbines totaling approximately $215 million through 2009. The Company believes that these payments are necessary for the timely and successful execution of relatedRepoweringNRG initiatives. In addition, NRG has capitalized $30$33 million through December 31, 20082009, for the repowering of its El Segundo generating facility in California. As a result ofAir permitting delays relatedlitigation unrelated to on-going Natural Resource Defense Counsel claims, the El Segundo project is unlikely to reachhas delayed receipt of certain required permits and prevented, the El Segundo project from meeting its original completion date of June 1, 2011.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The Company is working with the counterparty to consider certain PPA modifications including the commercial operations date currently expected to be the summer of 2013.
Contingencies Set forth below is a description of the Company’s material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of SFAS No. 5,Accounting for Contingencies,or SFAS 5,ASC 450 and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In 212
addition legal costcosts are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company’s liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material. In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect NRG’s consolidated financial position, results of operations, or cash flows. Exelon Related Litigation
Delaware Chancery Court
On November 11, 2008, Exelon and its wholly-owned subsidiary Exelon Xchange filed a complaint against NRG and NRG’s Board of Directors. The complaint alleges, among other things, that NRG’s Board of Directors failed to give due consideration and to take appropriate action in response to the acquisition proposal announced by Exelon on October 19, 2008, in which Exelon offered to acquire all of the outstanding shares of NRG common stock at an exchange ratio of 0.485 Exelon shares for each NRG common share. The complaint seeks, among other things, declaratory and injunctive relief: (1) declaring that NRG’s Board of Directors has breached its fiduciary duties to the NRG stockholders by rejecting and refusing to consider Exelon’s acquisition proposal and by failing to exempt the proposed transaction from application of Section 203 of the Delaware General Corporation Law; (2) compelling NRG’s Board of Directors to approve Exelon’s acquisition proposal for purposes of Section 203 of the Delaware General Corporations Law; (3) declaring that the adoption of any measure that would have the effect of impeding or interfering with Exelon’s acquisition proposal constitutes a breach of NRG’s Board of Directors fiduciary duties; and (4) enjoining the defendants from adopting any measures that would have the effect of impeding or interfering with Exelon’s acquisition proposal. On November 14, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss Exelon’s complaint on the grounds that it failed to state a claim upon which relief can be granted. On January 28, 2009, NRG and NRG’s Board of Directors filed their brief in support of their motion to dismiss.
On December 11, the Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System, on behalf of themselves and all others similarly situated, served a previously filed complaint on NRG and its Board of Directors alleging substantially similar allegations as the Exelon complaint. On December 23, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss the complaint on the grounds that it failed to state a claim upon which relief can be granted. On January 28, 2009, NRG and NRG’s Board of Directors filed their brief in support of their motion to dismiss.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Mercer County, New Jersey Superior Court
On January 6, 2009, three lawsuits previously filed against NRG and NRG’s Board of Directors on behalf of individual shareholders and all others similarly situated were consolidated into one case in the Law Division of the Superior Court of Mercer County, New Jersey. On January 21, 2009, the plaintiffs filed an Amended Consolidated Complaint in which they allege a single count of breach of fiduciary duty against NRG’s Board of Directors and seek injunctive relief: (1) declaring that the action is a class action and certifying plaintiffs as class plaintiffs and counsel as class counsel; (2) declaring that defendants breached their fiduciary duties by summarily rejecting the Exelon offer; (3) ordering defendants to negotiate with respect to the Exelon offer or with respect to another transaction to maximize shareholder value; (4) ordering defendants to exempt Exelon’s offer from Section 203 of the Delaware General Corporations Law; (5) awarding compensatory damages including interest; (6) awarding plaintiffs costs and fees; and (7) granting other relief the Court deems proper. A response is due on or before February 20, 2009.
California Department of Water Resources This matter concerns, among other contracts and other defendants, the CDWR and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the or FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the USU.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC’s review of the contracts at issue, the FERC could not rely on theMobil-SierraMobile-Sierrastandard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the USU.S. Supreme Court. WCP’s appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008 the Supreme Court ruled (1)ruled: (i) that theMobil-SierraMobile-Sierrapublic interest standard of review applied to contracts made under a seller’s market-based rate authority; (2)(ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (3)(iii) that theMobil-SierraMobile-Sierrapresumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the USU.S. Supreme Court affirmed the Ninth Circuit’s decision agreeing that the case should be remanded to the FERC to clarify the FERC’s 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the USU.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008 decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the USU.S. Supreme Court did not address in its June 26, 2008, decision; whether theMobil-SierraMobile-Sierradoctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in thethat case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the USU.S. Supreme Court’s June 26, 2008 decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand, and on January 28, 2009, WCP and the other seller-defendants filed their reply.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG’s financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy’s 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss 213
arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy. On January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding involving theMobile-Sierradoctrine that will affect the standard of review applied to the CDWR contract on remand before the FERC. InNRG Power Marketing v. Maine Public Utilities Commission, the Supreme Court held that theMobile-Sierrapresumption regarding the reasonableness of contract rates does not depend on the identity of the complainant who seeks a FERC investigation/refund. The Supreme Court proceeding arose following an appeal by the Attorneys General of the State of Connecticut and of the Commonwealth of Massachusetts regarding the settlement establishing the New England Forward Capacity Market. The settlement, filed with the FERC on March 7, 2006, provides for interim capacity transition payments for all generators in New England for the period from December 1, 2006 through May 31, 2010 and for the Forward Capacity Market auction rates thereafter. The Court of Appeals for the DC Circuit, or DC Circuit, had rejected all substantive challenges to the settlement, but had sustained one procedural argument relating to the applicability of theMobile-Sierradoctrine to third parties. The Supreme Court reversed the DC Circuit on this point, and remanded the case for further consideration of whether the transition payments and auction rates qualify as contract rates. Disputed Claims ReserveLouisiana Generating, LLC
As partOn February 11, 2009, the U.S. Department of NRG’s plan of reorganization, NRG funded a disputed claims reserve forJustice acting at the satisfaction of certain general unsecured claims that were disputed claims asrequest of the effective dateU.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the plan. UnderClean Air Act, or CAA, at the termsBig Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990’s, several years prior to NRG’s acquisition of the plan, as such claims are resolved, the claimants are paidBig Cajun II power plant from the reserve onCajun Electric bankruptcy and several years prior to the same basis as if they had been paid outNRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxidesand/or sulfur dioxides. The relief sought in the bankruptcy. Tocomplaint includes a request for an injunction to: (i) preclude the extentoperation of Units 1 and 2 except in accordance with the aggregate amount requiredCAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to be paid onregulation under the disputed claims exceedsCAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the amount remaining insurrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy the claims. Any excess funds in the disputed claims reserve will be reallocatedCAA’s Prevention of Significant Deterioration program; (vi) award to the creditor poolDepartment of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for the pro rata benefit of all allowed claims. The contributed common stockeach CAA violation found to have occurred between January 31, 1997, and cash in the reserves is held by an escrow agentMarch 15, 2004, up to complete the distribution$32,500 for each CAA violation found to have occurred between March 15, 2004, and settlement process. Since NRG has surrendered control over the common stockJanuary 12, 2009, and cash providedup to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from the balance sheet. Similarly, NRG removed the obligations relevant$37,500 for each CAA violation found to the claims from the balance sheet when the common stock was issued and cash contributed.have occurred after January 12, 2009.
On April 3, 2006,27, 2009, Louisiana Generating, LLC made several filings. It filed an objection in the Company made a supplemental distribution to creditors underCajun Electric Cooperative Power, Inc.’s bankruptcy proceeding in the Company’s Chapter 11 bankruptcy plan, totaling $25 million in cash and 5,082,000 shares of common stock. On December 18, 2008, NRG filed with the USU.S. Bankruptcy Court for the SouthernMiddle District of New YorkLouisiana to seek to prevent the bankruptcy from closing. It also filed a Closing Reportcomplaint in the same bankruptcy proceeding in the same court seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric; and an Application(iii) Cajun Electricand/or the Bankruptcy Trustee are exclusively liable for Final Decree Closing the Chapterviolations alleged in the February 11, Case for NRG Energy, Inc. et al2009, lawsuit to the extent that such claims are determined to have merit. On June 8, 2009, the parties filed a joint status report setting forth their views of the case and proposing a trial schedule. On June 18, 2009, Louisiana Generating, LLC filed a motion to bifurcate the Department of Justice lawsuit into separate liability and remedy phases, and on December 29, 2008,June 30, 2009, the court enteredDepartment of Justice filed its opposition. On August 24, 2009, Louisiana Generating, LLC filed a motion to dismiss this lawsuit, and on September 25, 2009, the Final Decree. AsDepartment of December 21, 2008, the reserve held approximately $9,776,880 in cash and 1,282,783 shares of common stock. On December 21, 2008, the Company issued an instruction letter to The Bank of New York Mellon to distribute all remaining cash and stock in the Disputed Claims Reserve to NRG’s creditors. On January 12, 2009, The Bank of New York Mellon commenced the distribution of all remaining cash and stock in the Disputed Claim ReserveJustice filed its opposition to the Company’s creditors pursuantmotion to NRG’s Chapter 11dismiss. A new federal bankruptcy plan.judge was appointed on October 9, 2009.
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On February 18, 2010, the LDEQ filed a motion to intervene in the above lawsuit and a complaint against Louisiana Generating LLC for alleged violations of Louisiana’s PSD regulations and Louisiana’s Title V operating permit program. LDEQ seeks similar relief to that requested by the Department of Justice. Specifically, LDEQ seeks injunctive relief to: (1) preclude the operation of Units 1 and 2 except in accordance with the CAA; (2) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (3) obtain all necessary permits for Units 1 and 2 pursuant to the requirements of PSD and the Louisiana Title V operating permits program; (4) conduct audits to determine if any additional modifications have occurred which would require it to meet the requirements of PSD and report the results of the audit to the LDEQ and EPA; (5) order the surrender of emission allowances or credits; (6) take other appropriate actions to remedy, mitigate and offset the harm to public health and the environment caused by violations of the CAA; (7) assess civil penalties; and (8) award to the LDEQ its costs in prosecuting the litigation. On February 19, 2010, the district court granted LDEQ’s motion to intervene. Nuclear Innovation North America, LLC On December 6, 2009, CPS commenced a lawsuit against two NINA entities asking the court to declare the rights, obligations, and remedies of the parties pursuant to the 1997 and 2007 agreements between the parties should CPS unilaterally withdraw from the proposed STP Units 3 and 4 Project. On December 23, 2009, CPS amended its original December 6 complaint adding NRG, Toshiba Corporation, and NINA LLC as defendants and not only continued to request that the Court declare the rights, obligations, and remedies of the parties under the two operative governing agreements, but also sought $32 billion in damages. CPS amended its complaint again on December 28, 2009. On January 6, 2010, CPS amended its complaint for the third time. In addition to requesting immediate injunctive relief, the amended complaint alleges that NRG, Toshiba, and NINA have been involved in a conspiracy to defraud CPS, that they purposefully misled CPS in inducing it to be a partner in the STP Units 3 and 4 Project, that they maliciously interfered with CPS contracts and business relationships, and that they willfully disparaged CPS. It sought declarations that: (i) owner consensus is required for all development decisions; (ii) there is a right to voluntary withdrawal, after which no further obligations accrue but undiluted ownership continues; (iii) both the partition waiver and forfeiture provisions are unenforceable against CPS under Texas law if they did apply; and (iv) CPS is not currently in breach. In addition, CPS sought relief among the following alternatives: partition by sale; an order forcing NRG and NINA to buy CPS’ undiluted share at an independent valuation; an order requiring NRG to compensate CPS $350 million investment and fair value for the site; an order granting CPS twelve months following withdrawal to sell its stake in the project; or an order that no further development take place without consensus of all project owners. This case was removed and remanded to and from federal court on three separate occasions. On January 19, 2010, CPS dismissed Toshiba from the lawsuit. The parties agreed to a January 25, 2010, phased trial wherein all other claims would be reserved for an undetermined future phase II date and a trial would go forward in phase I only on CPS’ request for declaratory relief to determine the respective rights, obligations, and remedies of the parties under the two operative governing agreements should CPS withdraw from the STP Units 3 and 4 Project. On January 25, 2010, the parties argued the NINA entities and NRG’s Motion for Summary Judgment which was denied on January 26, 2010. After atwo-day trial, the court issued its ruling on January 29, 2010, making a number of findings. It ruled that as of January 29, 2010, CPS and NINA were each 50% equity owners as tenants in common under Texas law in the STP Units 3 and 4 Project. The court found that while a withdrawing party does not forfeit its 50% interest upon a withdrawal, the governing agreements are silent as to whether that withdrawing party can recoup its sunk costs upon withdrawal. Finally, the court noted that for CPS to remain a 50% equity owner, it must pay all appropriate costs. Failure to do so, the court determined, would result in a complete loss of CPS’ equity share. On February 17, 2010, an agreement in principle was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project through a settlement of all pending litigation between the parties. As part of that agreement, all litigation would be dismissed with prejudice, including all phase II claims, thereby ending this matter. The parties continue to negotiate terms regarding final documentation of the agreement in principle. 215
NRG ENERGY, INC. AND SUBSIDIARIESDunkirk Construction Litigation
In 2005, NRG entered into a Consent Decree with the New York State Department of Environmental Conservation whereby it agreed to reduce certain emissions generated by its Huntley and Dunkirk power plants. Pursuant to the Consent Decree, on November 21, 2007, Clyde Bergemann EEC, or CBEEC, and NRG entered into a firm fixed price contract for the supply of equipment, material and services for six fabric filters for NRG’s Dunkirk Electric Power Generating Station. Subsequent to contracting with NRG, CBEEC subcontracted with Hohl Industrial Services, Inc., or Hohl, to perform steel erection and equipment installation at Dunkirk. On August 28, 2009, Hohl filed its original complaint against NRG, its subsidiary Dunkirk Power LLC, or Dunkirk Power, and CBEEC among others for claims of breach of contract, quantum meruit, unjust enrichment and foreclosure of mechanics’ liens. As part of CBEEC’s contractual obligation to NRG, CBEEC agreed to defend, under a reservation of rights, NRG’s interest in this lawsuit. CBEEC filed an answer to the above complaint on behalf of itself, NRG and Dunkirk Power on October 5, 2009. On December 16, 2009, CBEEC filed a Motion for Summary Judgment on behalf of itself, NRG, and Dunkirk Power, which has yet to be decided. On February 1, 2010, NRG and Dunkirk Power filed a Motion for Leave to file an Amended Answer with Cross-Claims against CBEEC. NRG asserted breach of contract claims seeking liquidated damages for the delays caused by CBEEC. NRG also retained its own counsel to represent its interest in the cross-claims and reserved its rights to seek reimbursement from CBEEC. On February 17, 2010, CBEEC filed an Amended Answer with Affirmative Defenses, Counterclaims and Cross-Claims against NRG. CBEEC is seeking approximately $30 million alleging breach of contract, quantum meruit, unjust enrichment, and foreclosure of two mechanic’s liens, as a result of alleged delays caused by NRG and Dunkirk Power. A court ordered hearing and settlement conference is scheduled for February 23, 2010. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Excess Mitigation Credits
Note 22 — Regulatory MattersFrom January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers’ monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI, totaled $385 million for RERS’s “Price to Beat” Customers. It is unclear what the actual number may be. “Price to Beat” was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT’s order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower court’s decision ruling that CenterPoint Energy’s stranded cost recovery should exclude only EMCs credited to RERS for its “Price to Beat” customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009.
In November 2008, CenterPoint Energy and RRI, on behalf of itself and affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy is ultimately not allowed to include in its stranded cost calculation those EMCs previously credited to RERS. Regardless of the outcome of the Texas Supreme Court proceeding, NRG believes that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack legal merit. No such claim has been filed. 216
| | Note 23 — | Regulatory Matters |
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which NRG participates. These wholesale power markets are subject to ongoing legislative and regulatory changes.changes that may impact NRG’s wholesale and retail businesses. New England —On July 16, 2007,In addition to the FERC conditionally accepted, subjectregulatory proceedings noted below, NRG and its subsidiaries are a party to refund,other regulatory proceedings arising in the RMR agreement filed on April 26, 2007 by Norwalk Power for its units 1 and 2, specifying a June 19, 2007 effective date. On December 4, 2008, Norwalk Power filed a Settlement Agreement resolvingordinary course of business or have other regulatory exposure. In management’s opinion, the RMR agreement eligibility and rate issues. The Settlement Agreement provides for an Annual Fixed Revenue Requirementdisposition of $34 million for 2008 and $32 million for 2009, continuing at a ratethese ordinary course matters will not materially adversely affect NRG’s consolidated financial position, results of $32 million per year until FCM is implemented on June 1, 2010. The FERC accepted the Settlement Agreement on December 30, 2008.operations, or cash flows.
PJM —On August 23, 2007, several entities, including the New Jersey BoardJune 18, 2009, FERC denied rehearing of Public Utilities, the District of Columbia Office of the People’s Counsel, and the Maryland Office of People’s Counsel, filed appeals of the FERC orders accepting the settlement of the locational capacity market for PJM. The settlement, filed at the FERC on September 29, 2006, provides for a capacity market mechanism known as the RPM which is designed to provide a long-term price signal through competitive forward auctions. On December 22, 2006, the FERC issued an order accepting the settlement, which was reaffirmed on rehearing byits order dated June 25, 2007. The RPM auctions have been conducted and capacity payments pursuant to the RPM mechanism have commenced. A successful appealSeptember 19, 2008, dismissing a complaint filed by the appellants could disturb the settlement and create a refund obligation of capacity payments. On May 30, 2008, the Maryland Public Service Commission, or MDPSC, together with other load interests, filed at the FERC a complaint against PJM challenging the results of the RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint seekshad sought to replace the auction-determined results for installed capacity for the 2008/2009, 2009/2010, and 2010/2011 delivery years with administratively-determined prices. On August 14, 2009, the MDPSC and the New Jersey Board of Public Utilities filed an appeal of FERC’s orders to the U.S. Court of Appeals for the Fourth Circuit, and a successful appeal could disrupt the auction-determined results and create a refund obligation for market participants. The case has been transferred to the U.S. Court of Appeals for the DC Circuit.
Retail (Replacement Reserve) —On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 19,27, 2006. Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol. Reliant Energy Power Supply, or REPS, other market participants, ERCOT, and PUCT staff opposed Constellation’s complaint. On January 25, 2008, the FERC dismissedPUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation’s complaint. The parties representing load interests have sought rehearingOn April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the dismissaltrial court’s decision. If all appeals are unsuccessful, on remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial court’s decision. It is not known at this time whether only Constellation’s under-scheduling charges, the under-scheduling charges of all other QSEs that disputed REPS charges for the same time frame, the entire market, or some other approach would be used for any resettlement. Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled capacity within any of ERCOT’s four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs. Under the Court’s decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity. If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPS’s share of the complaint. In a related proceeding, PJM filed proposed changestotal RPRS costs allocated to RPM on December 12, 2008.QSEs would increase. Note 23 — Environmental Matters
| | Note 24 — | Environmental Matters |
The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the US.U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. New legislation and regulations to mitigate the effects of GHG including CO2 from power plants, are under consideration at the federal and state levels. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Company’s operations. 217
Environmental Capital Expenditures Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures to be incurred from 20092010 through 20132014 to meet NRG’s environmental commitments will be approximately $1.2$0.9 billion (unaudited).and are primarily associated with controls on the Company’s Big Cajun and Indian River facilities. These capital expenditures, in general, are related to installation of particulate, SO2, NOx,NOx, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under the Phase II 316(b) rule.Rule. NRG continues to explore cost effective alternatives that can achieve desired results. While thisThis estimate reflects anticipated schedules and controls related to 2008 court rulings that affect requirementsthe CAIR, MACT for both CAIRmercury, and CAMR,the Phase II 316(b) Rule which are under remand to the U.S. EPA, and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined at this time.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Northeast Region NRG operates electric generating units located in Connecticut, Delaware, Maryland, Massachusetts and New York which are subject to RGGI. These units will have to surrender one allowance for every US ton of CO2 emitted with true up for2009-2011 occurring in 2012. Allowances will be partially allocated in the state of Delaware only. In 2008, NRG emitted approximately 12 million tonnes of CO2 in RGGI states. NRG believes that to the extent CO2 will not be fully reflected in wholesale electricity prices, the direct financial impact on the Company is likely to be negative as costs will be incurred in the course of securing the necessary RGGI allowances and offsets at auction and in the market.
In January 2006, NRG’s Indian River Operations, Inc. received a letter of informal notification from the DNREC stating that the Companyit may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill.landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with the DNREC to investigate the site through the VoluntaryClean-up Program. On February 4, 2008, the DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would adequately address shore line erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study are completed, the Company is unable to predict the impact of any required remediation. On May 29, 2008, the DNREC issued an invitation torequested that NRG’s Indian River Operations, Inc. to participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with the DNREC and other trustees to close out the property.assessment phase. South Central Region On January 27, 2004, NRG’sFebruary 11, 2009, the U.S. Department of Justice acting at the request of the U.S. EPA commenced a lawsuit against Louisiana Generating, LLC andin federal district court in the Company’s Big Cajun II plant received a request under Section 114Middle District of Louisiana alleging violations of the CAA from the USEPA seeking information primarily related to physical changes made at the Big Cajun II plant, and subsequently received a NOVpower plant. This is the same matter for which NOVs were issued to Louisiana Generating, LLC on February 15, 2005, alleging that NRG’s predecessors had undertaken projects that triggered requirements under the Preventionand on December 8, 2006. Further discussion on this matter can be found in Item 3— Legal Proceedings, United States of Significant Deterioration program, including the installation of emission controls. NRG submitted multiple responses commencing February 27, 2004 and ending on October 20, 2004. On May 9, 2006, these entities received from the Department of Justice, or DOJ, a Notice of Deficiency related to their responses, to which NRG responded on May 22, 2006. A document review was conducted at NRG’sAmerica v. Louisiana Generating, LLC offices by the DOJ during the week of August 14, 2006. On December 8, 2006, the USEPA issued a supplemental NOV updating the original February 15, 2005 NOV. NRG has evaluated the original and subsequent claims and believes they have no merit. Nonetheless, NRG has had discussions with the USEPA about resolving the claims and the Company cannot predict with certainty the outcome of this matter.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note 24 — Cash Flow Information
| | Note 25 — | Cash Flow Information |
Detail of supplemental disclosures of cash flow and non-cash investing and financing information was: | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2008 | | | 2007 | | | 2006 | | | | (In millions) | | | Interest paid, net of amount capitalized(a) | | $ | 563 | | | $ | 598 | | | $ | 450 | | Income taxes paid(b) | | | 46 | | | | 22 | | | | 18 | | Non-cash investing and financing activities: | | | | | | | | | | | | | (Reduction)/addition to fixed assets due to asset retirement obligations | | | (39 | ) | | | 7 | | | | 15 | | Additions to fixed assets for accrued capital expenditures | | | 116 | | | | — | | | | — | | Decrease to 5.75% preferred stock from conversion to common stock | | | (39 | ) | | | — | | | | — | |
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2009 | | | 2008 | | | 2007 | | | | (In millions) | | | Interest paid, net of amount capitalized(a) | | $ | 587 | | | $ | 563 | | | $ | 598 | | Income taxes paid(b) | | | 47 | | | | 46 | | | | 22 | | Non-cash investing and financing activities: | | | | | | | | | | | | | (Reduction)/addition to fixed assets due to asset retirement obligations | | | (1 | ) | | | (39 | ) | | | 7 | | Additions to fixed assets for accrued capital expenditures | | | 44 | | | | 116 | | | | — | | Decrease to fixed assets for accrued grants and related tax impact | | | (132 | ) | | | — | | | | — | | Decrease to 4.0% preferred stock from conversion to common stock | | | 257 | | | | — | | | | — | | Decrease to 5.75% preferred stock from conversion to common stock | | | 447 | | | | 39 | | | | — | | Decrease to treasury stock from the net impact of shares loaned to and returned by affiliates of CS | | | 160 | | | | — | | | | — | |
| | | (a) | | 2008 interest paid includes $45 million payment to settle the CSF I CAGR. |
| | | (b) | | 2009, 2008 and 2007 income taxes paid is net of $3, $2 and $6 million, respectively, of income tax refunds received. |
218
Note 25 — Guarantees
NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company’s business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is also obligated with respect to customer deposits associated with Reliant Energy. In some cases, NRG’s maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability. In accordance with FIN 45,ASC 460, NRG has estimated that the current fair value for issuing these guarantees was approximately $7$8.0 million as of December 31, 2008,2009, and the liability in this amount is included in the Company’s non-current liabilities. The following table summarizes NRG’s estimated guarantees, indemnity, and other contingent liability obligations by maturity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | By Remaining Maturity at December 31, | | | By Remaining Maturity at December 31, | | | | 2008 | | | | | 2009 | | | | | | Under
| | | | | | Over
| | | | 2007
| | | Under
| | | | | | Over
| | | | 2008
| | Guarantees | | 1 Year | | 1-3 Years | | 3-5 Years | | 5 Years | | Total | | Total | | | 1 Year | | 1-3 Years | | 3-5 Years | | 5 Years | | Total | | Total | | | | | | | | (In millions) | | | | | | | | | | | (In millions) | | | | | | | Synthetic letters of credit | | $ | 357 | | | $ | 83 | | | $ | — | | | $ | — | | | $ | 440 | | | $ | 743 | | | $ | 531 | | | $ | 186 | | | $ | — | | | $ | — | | | $ | 717 | | | $ | 440 | | Unfunded letters of credit and surety bonds | | | 5 | | | | — | | | | — | | | | — | | | | 5 | | | | 8 | | | | 61 | | | | 36 | | | | — | | | | — | | | | 97 | | | | 5 | | Asset sales guarantee obligations | | | — | | | | 112 | | | | — | | | | 17 | | | | 129 | | | | 148 | | | | — | | | | 118 | | | | — | | | | 8 | | | | 126 | | | | 129 | | Commercial sales arrangements | | | 192 | | | | 13 | | | | — | | | | 800 | | | | 1,005 | | | | 791 | | | | 104 | | | | 44 | | | | 103 | | | | 965 | | | | 1,216 | | | | 1,005 | | Other guarantees | | | 24 | | | | 30 | | | | — | | | | 26 | | | | 80 | | | | 32 | | | | — | | | | — | | | | — | | | | 117 | | | | 117 | | | | 80 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total guarantees | | $ | 578 | | | $ | 238 | | | $ | — | | | $ | 843 | | | $ | 1,659 | | | $ | 1,722 | | | $ | 696 | | | $ | 384 | | | $ | 103 | | | $ | 1,090 | | | $ | 2,273 | | | $ | 1,659 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Letters of credit and surety bonds —As of December 31, 2008,2009, NRG and its consolidated subsidiaries were contingently obligated for a total of approximately $445$814 million under letters of credit and surety bonds. Most of these letters of credit and surety bonds are issued in support of the Company’s obligations to perform under
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
commodity agreements, financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms. Asset sale guarantees —NRG is typically requested to provide certain assurances to the counter-parties of the Company’s asset sale agreements. Such assurances may take the form of a guarantee issued by the Company on behalf of a directly or indirectly held majority-owned subsidiary which include certain indemnifications to a third party, usually the buyer, as described below. Due to the inter-company nature of such arrangements, NRG is essentially guaranteeing its own performance, and the nature of the guarantee being provided. It is not the Company’s policy to recognize the value of such an obligation in its consolidated financial statements. Most of these guarantees provide an explicit cap on the Company’s maximum liability, as well as an expiration period, exclusive of breach of representations and warranties. In connection with the agreement to sell its 50% ownership interest in Mibrag B.V., NRG executed an agreement guaranteeing the performance of its subsidiary Lambique Beheer under the purchase and sale agreement. This agreement indemnifies the buyer for tax, environmental liability and other matters, as well as breaches of representations and warranties and is limited to EUR 206 million. Commercial sales arrangements —In connection with the purchase and sale of fuel, emission allowances and power generation products to and from third parties with respect to the operation of some of NRG’s generation facilities in the US,U.S., the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments. Other guarantees —NRG has issued guarantees of obligations that its subsidiaries may incur as a provision for environmental site remediation, payment of debt obligations, rail car leases, performance under purchase, EPC and 219
operating and maintenance agreements. NRG has executed guarantees with related parties for one of its subsidiary’s obligations as construction manager under EPC contracts for the construction of the Sherbino wind farm and two peaking power plants at GenConn’s Devon and Middletown sites. See Note 14,16,Investments Accounted for by the Equity Method,for more information on thesethis equity investments.investment. The Company does not believe that it will be required to perform under these guarantees. NRG signed a guarantee agreement on behalf of its subsidiary NRG Retail, LLC guaranteeing the payment and performance of its obligations under the LLC Membership Interest Purchase Agreement and related agreements with RRI in connection with the purchase of its retail business, including purchase price and acquired net working capital. In addition, GenConn has entered into turbine purchase agreements foraccordance with the Devon and Middletown sites.LLC Membership Interest Purchase Agreement, on May 1, 2009, NRG signed an agreement guaranteeing payments up to $85 million related to the Restated Power Purchase Agreement with FPL Energy Upton Wind II, LLC. NRG has issued guarantees for payment on its proportionate shareno reason to believe that the Company currently has any material liability relating to such routine indemnification obligations. In connection with the October 5, 2009, amendment of the unpaid amountsCSRA, NRG signed guarantee agreements on behalf of its subsidiary NRG Retail, LLC guaranteeing performance under each of thesepower purchase agreements. Eachand sales contracts. See Note 3, Business Acquisitions, for more information on the amendment of the guarantees will remain in place until such time as GenConn has obtained financing for each of the respective projects. As of December 31, 2008, NRG’s potential remaining obligation under the guarantees is $54 million in the aggregate.CSRA. The material indemnities, within the scope of FIN 45,ASC 460, are as follows: Asset purchases and divestitures —The purchase and sale agreements which govern NRG’s asset or share investments and divestitures customarily contain indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. For those indemnities in which liability is capped, the maximum exposures range from $1 million to $300 million. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations. Other indemnities —Other indemnifications NRG has provided cover operational, tax, litigation and breaches of representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to the Company. NRG’s maximum potential exposure under these indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any material payments under these indemnity provisions. Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company’s liability exposure, it may not be able to estimate what the Company’s liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts. Note 26 — Jointly Owned Plants
| | Note 27 — | Jointly Owned Plants |
Certain NRG subsidiaries own undivided interests in jointly-owned plants, described below. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries’ share of operating costs and direct expense and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company’s consolidated financial statements. 220
The following table summarizes NRG’s proportionate ownership interest in the Company’s jointly-owned facilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Ownership
| | Property, Plant &
| | Accumulated
| | Construction in
| | | Ownership
| | Property, Plant &
| | Accumulated
| | Construction in
| As of December 31, 2008 | | Interest | | Equipment | | Depreciation | | Progress | | | As of December 31, 2009 | | | Interest | | Equipment | | Depreciation | | Progress | | | (In millions unless otherwise stated) | | | (In millions unless otherwise stated) | | South Texas Project Units 1 and 2, Bay City, TX | | | 44.00 | % | | $ | 2,918 | | | $ | (503 | ) | | $ | 34 | | | | 44.00 | % | | $ | 3,003 | | | $ | (663 | ) | | $ | 32 | | Big Cajun II Unit 3, New Roads, LA | | | 58.00 | | | | 174 | | | | (48 | ) | | | 10 | | | | 58.00 | | | | 175 | | | | (58 | ) | | | 13 | | Cedar Bayou Unit 4, Baytown, TX | | | 50.00 | | | | — | | | | — | | | | 185 | | | | 50.00 | | | | 215 | | | | (5 | ) | | | — | | Keystone, Shelocta, PA | | | 3.70 | | | | 61 | | | | (15 | ) | | | 20 | | | | 3.70 | | | | 88 | | | | (19 | ) | | | 4 | | Conemaugh, New Florence, PA | | | 3.72 | | | | 74 | | | | (19 | ) | | | 1 | | | | 3.72 | | | | 74 | | | | (22 | ) | | | 2 | |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note 27 — Unaudited Quarterly Financial Data
Summarized unaudited quarterly financial data is as follows:
| | | | | | | | | | | | | | | | | | | Quarter Ended | | | | 2008 | | | | | | | September 30
| | | | | | | | | | December 31 | | | (As revised) | | | June 30 | | | March 31 | | | | (In millions, except per share data) | | | Operating revenues | | $ | 1,655 | | | $ | 2,612 | | | $ | 1,316 | | | $ | 1,302 | | Operating income | | | 595 | | | | 1,371 | | | | 57 | | | | 250 | | Income/(loss) from continuing operations, net of income taxes | | | 273 | | | | 734 | | | | (39 | ) | | | 48 | | Income from discontinued operations, net of income taxes | | | — | | | | — | | | | 168 | | | | 4 | | Net income | | $ | 273 | | | $ | 734 | | | $ | 129 | | | $ | 52 | | Weighted average number of common shares outstanding — basic | | | 233 | | | | 235 | | | | 236 | | | | 236 | | Income/(loss) from continuing operations per weighted average common share — basic | | $ | 1.11 | | | $ | 3.07 | | | $ | (0.22 | ) | | $ | 0.14 | | Income from discontinued operations per weighted average common share — basic | | | — | | | | — | | | | 0.71 | | | | 0.02 | | Net income per weighted average common share — basic | | $ | 1.11 | | | $ | 3.07 | | | $ | 0.49 | | | $ | 0.16 | | Weighted average number of common shares outstanding — diluted | | | 276 | | | | 277 | | | | 236 | | | | 245 | | Income/(loss) from continuing operations per weighted average common share — diluted | | $ | 0.98 | | | $ | 2.65 | | | $ | (0.22 | ) | | $ | 0.14 | | Income from discontinued operations per weighted average common share — diluted | | | — | | | | — | | | | 0.71 | | | | 0.02 | | Net income per weighted average common share — diluted | | $ | 0.98 | | | $ | 2.65 | | | $ | 0.49 | | | $ | 0.16 | |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | Quarter Ended | | | | 2007 | | | | December 31 | | | September 30 | | | June 30 | | | March 31 | | | | (In millions, except per share data) | | | Operating revenues | | $ | 1,382 | | | $ | 1,772 | | | $ | 1,536 | | | $ | 1,299 | | Operating income | | | 320 | | | | 546 | | | | 427 | | | | 267 | | Income from continuing operations, net of income taxes | | | 100 | | | | 265 | | | | 143 | | | | 61 | | Income from discontinued operations, net of income taxes | | | 4 | | | | 3 | | | | 6 | | | | 4 | | Net income | | $ | 104 | | | $ | 268 | | | $ | 149 | | | $ | 65 | | Weighted average number of common shares outstanding — basic | | | 239 | | | | 239 | | | | 240 | | | | 244 | | Income from continuing operations per weighted average common share — basic | | $ | 0.36 | | | $ | 1.05 | | | $ | 0.54 | | | $ | 0.19 | | Income from discontinued operations per weighted average common share — basic | | | 0.02 | | | | 0.02 | | | | 0.02 | | | | 0.02 | | Net income per weighted average common share — basic | | $ | 0.38 | | | $ | 1.07 | | | $ | 0.56 | | | $ | 0.21 | | Weighted average number of common shares outstanding — diluted | | | 270 | | | | 285 | | | | 288 | | | | 271 | | Income from continuing operations per weighted average common share — diluted | | $ | 0.34 | | | $ | 0.92 | | | $ | 0.49 | | | $ | 0.19 | | Income from discontinued operations per weighted average common share — diluted | | | 0.01 | | | | 0.01 | | | | 0.02 | | | | 0.01 | | Net income per weighted average common share — diluted | | $ | 0.35 | | | $ | 0.93 | | | $ | 0.51 | | | $ | 0.20 | |
Subsequent to filing of NRG’s Quarterly Report onForm 10-Q for the period ended September 30, 2008, the Company identified a $78 million overstatement of revenues resulting from an error in the accounting for energy options for the three months ended September 30, 2008. There was no impact to the Company’s year-to-date cash flows or liquidity position. The impact on the September 30, 2008 balance sheet was an understatement of the current derivative instruments valuation of $35 million and other current liabilities of $113 million. There was an insignificant impact on the 2007 results and 2008 first and second quarter statements of operations and thus, NRG is not revising the revenues reported in these previously issued interim financial statements. NRG determined that the revenue recognition practice used prior to September 30, 2008 resulted in the unintentional recognition of excess amortization of premiums during the earlier portion of the option contract terms. This excess was reversed upon termination of the options, resulting in no net misstatement over the life of the option. The interim periods however were subject to misstatement depending upon the volume and timing of option execution.
Although not material to the previously filed financial statements, the correction of the third quarter option revenue during the fourth quarter would have understated the fourth quarter operating revenues and income by
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$78 million. Accordingly, in thisForm 10-K, the unaudited quarterly financial data is revised for the quarter ended September 30, 2008. The net impact is as follows:
| | | | | | | | | | | | | | | Quarter Ended | | | | September 30, 2008 | | | | As reported | | | Adjustment | | | As revised | | | Operating revenues | | $ | 2,690 | | | $ | (78 | ) | | $ | 2,612 | | Operating income | | | 1,449 | | | | (78 | ) | | | 1,371 | | Income from continuing operations, net of income taxes | | | 784 | | | | (50 | ) | | | 734 | | Income from discontinued operations, net of income taxes | | | — | | | | — | | | | — | | Net income | | $ | 784 | | | $ | (50 | ) | | $ | 734 | | Weighted average number of common shares outstanding — basic | | | 235 | | | | — | | | | 235 | | Income from continuing operations per weighted average common share — basic | | $ | 3.28 | | | $ | (0.21 | ) | | $ | 3.07 | | Income from discontinued operations per weighted average common share — basic | | | — | | | | — | | | | — | | Net income per weighted average common share — basic | | $ | 3.28 | | | $ | (0.21 | ) | | $ | 3.07 | | Weighted average number of common shares outstanding — diluted | | | 277 | | | | — | | | | 277 | | Income from continuing operations per weighted average common share — diluted | | $ | 2.83 | | | $ | (0.18 | ) | | $ | 2.65 | | Income from discontinued operations per weighted average common share — diluted | | | — | | | | — | | | | — | | Net income per weighted average common share — diluted | | $ | 2.83 | | | $ | (0.18 | ) | | $ | 2.65 | |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | Note 28 — | Unaudited Quarterly Financial Data |
Summarized unaudited quarterly financial data is as follows: | | | | | | | | | | | | | | | | | | | Quarter Ended | | | 2009 | | | December 31 | | September 30 | | June 30 | | March 31 | | | (In millions, except per share data) | | Operating revenues | | $ | 2,141 | | | $ | 2,916 | | | $ | 2,237 | | | $ | 1,658 | | Operating income | | | 314 | | | | 611 | | | | 619 | | | | 615 | | Income from continuing operations, net of income taxes | | | 33 | | | | 278 | | | | 433 | | | | 198 | | Income from discontinued operations, net of income taxes | | | — | | | | — | | | | — | | | | — | | Net income attributable to NRG Energy, Inc. | | $ | 33 | | | $ | 278 | | | $ | 433 | | | $ | 198 | | Weighted average number of common shares outstanding — basic | | | 242 | | | | 249 | | | | 253 | | | | 237 | | Income from continuing operations per weighted average common share — basic | | $ | 0.11 | | | $ | 1.09 | | | $ | 1.68 | | | $ | 0.78 | | Net income per weighted average common share — basic | | $ | 0.11 | | | $ | 1.09 | | | $ | 1.68 | | | $ | 0.78 | | Weighted average number of common shares outstanding — diluted | | | 244 | | | | 272 | | | | 275 | | | | 275 | | Income from continuing operations per weighted average common share — diluted | | $ | 0.11 | | | $ | 1.02 | | | $ | 1.56 | | | $ | 0.70 | | Net income per weighted average common share — diluted | | $ | 0.11 | | | $ | 1.02 | | | $ | 1.56 | | | $ | 0.70 | |
221
| | | | | | | | | | | | | | | | | | | Quarter Ended | | | 2008 | | | December 31 | | September 30 | | June 30 | | March 31 | | | (In millions, except per share data) | | Operating revenues | | $ | 1,655 | | | $ | 2,612 | | | $ | 1,316 | | | $ | 1,302 | | Operating income | | | 595 | | | | 1,371 | | | | 57 | | | | 250 | | Income/(loss) from continuing operations, net of income taxes | | | 271 | | | | 778 | | | | (41 | ) | | | 45 | | Income from discontinued operations, net of income taxes | | | — | | | | — | | | | 168 | | | | 4 | | Net income attributable to NRG Energy, Inc. | | $ | 271 | | | $ | 778 | | | $ | 127 | | | $ | 49 | | Weighted average number of common shares outstanding — basic | | | 233 | | | | 235 | | | | 236 | | | | 236 | | Income from continuing operations per weighted average common share — basic | | $ | 1.10 | | | $ | 3.26 | | | $ | (0.23 | ) | | $ | 0.13 | | Income/(loss) from discontinued operations per weighted average common share — basic | | | — | | | | — | | | | 0.71 | | | | 0.02 | | Net income per weighted average common share — basic | | $ | 1.10 | | | $ | 3.26 | | | $ | 0.48 | | | $ | 0.15 | | Weighted average number of common shares outstanding — diluted | | | 276 | | | | 277 | | | | 236 | | | | 245 | | Income/(loss) from continuing operations per weighted average common share — diluted | | $ | 0.97 | | | $ | 2.81 | | | $ | (0.23 | ) | | $ | 0.12 | | Income from discontinued operations per weighted average common share — diluted | | | — | | | | — | | | | 0.71 | | | | 0.02 | | Net income per weighted average common share — diluted | | $ | 0.97 | | | $ | 2.81 | | | $ | 0.48 | | | $ | 0.14 | |
222
| | Note 29 — | Condensed Consolidating Financial Information |
As of December 31, 2008,2009, the Company had $1.2 billion of 7.25% Senior Notes due 2014, $2.4 billion of 7.375% Senior Notes due 2016 and $1.1 billion of 7.375%. Senior Notes due 2017 outstanding.and $700 million of 8.50% Senior Notes due 2019. These notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries. EachOn October 5, 2009, RERH became a guarantor subsidiary as a result of the CSRA Amendment. The consolidating financial statements hereinafter have been recast to reflect RERH as a guarantor subsidiary for the period ended December 31, 2009. RERH’s cash balance on the date it became a guarantor subsidiary was $734 million.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2008:2009: | | | Arthur Kill Power LLC | | NRG Construction LLCGeneration Holdings, Inc. | Astoria Gas Turbine Power LLC | | NRG DevonHuntley Operations Inc. | Berrians I Gas Turbine Power LLC | | NRG Dunkirk Operations, Inc.International LLC | Big Cajun II Unit 4 LLC | | NRG El Segundo Operations Inc.Kaufman LLC | Cabrillo Power I LLC | | NRG Generation Holdings, Inc.Mesquite LLC | Cabrillo Power II LLC | | NRG Huntley OperationsMidAtlantic Affiliate Services Inc. | Chickahominy River Energy Corp. | | NRG International LLC | Commonwealth Atlantic Power LLC | | NRG Kaufman LLC | Conemaugh Power LLC | | NRG Mesquite LLC | Connecticut Jet Power LLC | | NRG MidAtlantic Affiliate Services Inc. | Devon Power LLC | | NRG Middletown Operations Inc. | DunkirkCommonwealth Atlantic Power LLC | | NRG Montville Operations Inc. | Eastern Sierra Energy CompanyConemaugh Power LLC | | NRG New Jersey Energy Sales LLC | El SegundoConnecticut Jet Power LLC | | NRG New Roads Holdings LLC | Devon Power LLC | | NRG North Central Operations, Inc. | Dunkirk Power LLC | | NRG Northeast Affiliate Services Inc. | Eastern Sierra Energy Company | | NRG Norwalk Harbor Operations Inc. | El Segundo Power, LLC | | NRG Operating Services Inc. | El Segundo Power II LLC | | NRG North CentralOswego Harbor Power Operations Inc. | GCP Funding Company LLC | | NRG Northeast Affiliate Services Inc.Power Marketing LLC | Hanover Energy Company | | NRG Norwalk Harbor Operations Inc.Retail LLC | Hoffman Summit Wind Project LLC | | NRG Operating Services Inc.Rocky Road LLC | Huntley IGCC LLC | | NRG Oswego Harbor PowerSaguaro Operations Inc. | Huntley Power LLC | | NRG Power Marketing LLCSouth Central Affiliate Services Inc. | Indian River IGCC LLC | | NRG Rocky RoadSouth Central Generating LLC | Indian River Operations Inc. | | NRG SaguaroSouth Central Operations Inc. | Indian River Power LLC | | NRG South Central Affiliate Services Inc.Texas LP | James River Power LLC | | NRG South Central GeneratingTexas LLC | Kaufman Cogen LP | | NRG South Central Operations Inc.Texas C & I Supply LLC | Keystone Power LLC | | NRG South Texas LPHolding Inc. | Lake Erie Properties Inc. | | NRG Texas LLC | Louisiana Generating LLC | | NRG Texas Power LLC | MiddletownLangford Wind Power, LLC | | NRG West Coast LLC | Montville IGCCLouisiana Generating LLC | | NRG Western Affiliate Services Inc. | MontvilleMiddletown Power LLC | | Oswego Harbor Power LLC | NEO Chester-GenMontville IGCC LLC | | Padoma Wind Power, LLC | Montville Power LLC | | Reliant Energy Power Supply, LLC | NEO Chester-Gen LLC | | Reliant Energy Retail Holding, LLC | NEO Corporation | | Reliant Energy Retail Services, LLC | NEO Freehold-Gen LLC | | RE Retail Receivables, LLC | NEO Power Services Inc. | | RERH Holdings, LLC | New Genco GP LLC | | Reliant Energy Services Texas LLC | Norwalk Power LLC | | Reliant Energy Texas Retail LLC | NRG Affiliate Services Inc. | | Saguaro Power LLC | NEO Freehold-Gen LLCNRG Arthur Kill Operations Inc. | | San Juan Mesa Wind Project II, LLC | NEO Power Services Inc.NRG Asia-Pacific Ltd. | | Somerset Operations Inc. | New Genco GP LLCNRG Astoria Gas Turbine Operations Inc. | | Somerset Power LLC |
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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | Norwalk PowerNRG Bayou Cove LLC | | Texas Genco Financing Corp. | NRG Affiliate ServicesCabrillo Power Operations Inc. | | Texas Genco GP, LLC |
223
| | | NRG Arthur KillCadillac Operations Inc. | | Texas Genco Holdings, Inc. | NRG Asia-Pacific Ltd. | | Texas Genco LP, LLC | NRG Astoria Gas Turbine Operations Inc. | | Texas Genco Operating Services, LLC | NRG Bayou Cove LLC | | Texas Genco Services, LP | NRG Cabrillo Power Operations Inc. | | Vienna Operations, Inc. | NRG Cadillac Operations Inc. | | Vienna Power LLC | NRG California Peaker Operations LLC | | WCP (Generation) HoldingsTexas Genco LP, LLC | NRG Cedar Bayou Development Company LLC | | West Coast PowerTexas Genco Operating Services, LLC | NRG Connecticut Affiliate Services Inc. | | Texas Genco Services, LP | NRG Construction LLC | | Vienna Operations, Inc. | NRG Devon Operations Inc. | | Vienna Power LLC | NRG Dunkirk Operations, Inc. | | WCP (Generation) Holdings LLC | NRG El Segundo Operations Inc. | | West Coast Power LLC |
The non-guarantor subsidiaries include all of NRG’s foreign subsidiaries and certain domestic subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company’s ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG’s ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company’s Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries. The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance withRule 3-10 under the Securities and Exchange Commission’sRegulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities. In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis. 220224
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 20082009 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NRG Energy,
| | | | | | | | Guarantor
| | Non-Guarantor
| | | | | | Consolidated
| | | Guarantor
| | Non-Guarantor
| | Inc.
| | | | Consolidated
| | | | Subsidiaries | | Subsidiaries | | NRG Energy, Inc. | | Eliminations(a) | | Balance | | | Subsidiaries | | Subsidiaries | | (Note Issuer) | | Eliminations (a) | | Balance | | | | (In millions) | | | | | | | (In millions) | | | | | | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 6,504 | | | $ | 405 | | | $ | — | | | $ | (24 | ) | | $ | 6,885 | | | $ | 8,584 | | | $ | 357 | | | $ | 31 | | | $ | (20 | ) | | $ | 8,952 | | | | | | | | | | | | | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cost of operations | | | 3,321 | | | | 303 | | | | — | | | | (26 | ) | | | 3,598 | | | | 5,110 | | | | 236 | | | | 1 | | | | (24 | ) | | | 5,323 | | Depreciation and amortization | | | 618 | | | | 27 | | | | 4 | | | | — | | | | 649 | | | | 772 | | | | 40 | | | | 6 | | | | — | | | | 818 | | General and administrative | | | 64 | | | | 14 | | | | 241 | | | | — | | | | 319 | | | Selling, general and administrative | | | | 266 | | | | 11 | | | | 273 | | | | — | | | | 550 | | Acquisition-related transaction and integration costs | | | | — | | | | — | | | | 54 | | | | — | | | | 54 | | Development costs | | | (1 | ) | | | 7 | | | | 40 | | | | — | | | | 46 | | | | 6 | | | | 8 | | | | 34 | | | | — | | | | 48 | | | | | | | | | | | | | | | | | | | | | | | | | Total operating costs and expenses | | | 4,002 | | | | 351 | | | | 285 | | | | (26 | ) | | | 4,612 | | | | 6,154 | | | | 295 | | | | 368 | | | | (24 | ) | | | 6,793 | | | | | | | | | | | | | | | | | | | | | | | | | Operating Income/(Loss) | | | 2,502 | | | | 54 | | | | (285 | ) | | | 2 | | | | 2,273 | | | | 2,430 | | | | 62 | | | | (337 | ) | | | 4 | | | | 2,159 | | | | | | | | | | | | | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity in earnings of consolidated subsidiaries | | | 276 | | | | — | | | | 1,601 | | | | (1,877 | ) | | | — | | | | 166 | | | | — | | | | 1,503 | | | | (1,669 | ) | | | — | | Equity in earnings of unconsolidated affiliates | | | (2 | ) | | | 61 | | | | — | | | | — | | | | 59 | | | | 10 | | | | 31 | | | | — | | | | — | | | | 41 | | Other income/(expense), net | | | 23 | | | | 11 | | | | (15 | ) | | | (2 | ) | | | 17 | | | Gains on sales of equity method investments | | | | — | | | | 128 | | | | — | | | | — | | | | 128 | | Other income/(loss), net | | | | 9 | | | | (16 | ) | | | 6 | | | | (4 | ) | | | (5 | ) | Refinancing expense | | | | (1 | ) | | | — | | | | (19 | ) | | | — | | | | (20 | ) | Interest expense | | | (183 | ) | | | (114 | ) | | | (323 | ) | | | — | | | | (620 | ) | | | (106 | ) | | | (86 | ) | | | (442 | ) | | | — | | | | (634 | ) | | | | | | | | | | | | | | | | | | | | | | | | Total other income/(expense) | | | 114 | | | | (42 | ) | | | 1,263 | | | | (1,879 | ) | | | (544 | ) | | | 78 | | | | 57 | | | | 1,048 | | | | (1,673 | ) | | | (490 | ) | | | | | | | | | | | | | | | | | | | | | | | | Income From Continuing Operations Before Income Taxes | | | 2,616 | | | | 12 | | | | 978 | | | | (1,877 | ) | | | 1,729 | | | Income/(Losses) Before Income Taxes | | | | 2,508 | | | | 119 | | | | 711 | | | | (1,669 | ) | | | 1,669 | | Income tax expense/(benefit) | | | 1,001 | | | | 19 | | | | (307 | ) | | | — | | | | 713 | | | | 964 | | | | (5 | ) | | | (231 | ) | | | — | | | | 728 | | | | | | | | | | | | | | | | | | | | | | | | | Income From Continuing Operations | | | 1,615 | | | | (7 | ) | | | 1,285 | | | | (1,877 | ) | | | 1,016 | | | Income(loss) from discontinued operations, net of income taxes | | | — | | | | 269 | | | | (97 | ) | | | — | | | | 172 | | | Net Income/(Loss) | | | | 1,544 | | | | 124 | | | | 942 | | | | (1,669 | ) | | | 941 | | Less: Net loss attributable to noncontrolling interest | | | | (1 | ) | | | — | | | | — | | | | — | | | | (1 | ) | | | | | | | | | | | | | | | | | | | | | | | | Net Income | | $ | 1,615 | | | $ | 262 | | | $ | 1,188 | | | $ | (1,877 | ) | | $ | 1,188 | | | Net Income/(Loss) attributable to NRG Energy, Inc. | | | $ | 1,545 | | | $ | 124 | | | $ | 942 | | | $ | (1,669 | ) | | $ | 942 | | | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEETS
December 31, 2008
| | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | | ASSETS | Current Assets | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | (2 | ) | | $ | 159 | | | $ | 1,337 | | | $ | — | | | $ | 1,494 | | Funds deposited by counterparties | | | — | | | | — | | | | 754 | | | | — | | | | 754 | | Restricted cash | | | 7 | | | | 9 | | | | — | | | | — | | | | 16 | | Accounts receivable-trade, net | | | 422 | | | | 42 | | | | — | | | | — | | | | 464 | | Inventory | | | 443 | | | | 12 | | | | — | | | | — | | | | 455 | | Derivative instruments valuation | | | 4,600 | | | | — | | | | — | | | | — | | | | 4,600 | | Cash collateral paid in support of energy risk management activities | | | 494 | | | | — | | | | — | | | | — | | | | 494 | | Prepayments and other current assets | | | 130 | | | | 37 | | | | 278 | | | | (230 | ) | | | 215 | | | | | | | | | | | | | | | | | | | | | | | Total current assets | | | 6,094 | | | | 259 | | | | 2,369 | | | | (230 | ) | | | 8,492 | | | | | | | | | | | | | | | | | | | | | | | Net Property, Plant and Equipment | | | 10,725 | | | | 791 | | | | 29 | | | | — | | | | 11,545 | | | | | | | | | | | | | | | | | | | | | | | Other Assets | | | | | | | | | | | | | | | | | | | | | Investment in subsidiaries | | | 651 | | | | 18 | | | | 11,941 | | | | (12,610 | ) | | | — | | Equity investments in affiliates | | | 26 | | | | 464 | | | | — | | | | — | | | | 490 | | Capital leases and note receivable, less current portion | | | 598 | | | | 435 | | | | 3,177 | | | | (3,775 | ) | | | 435 | | Goodwill | | | 1,718 | | | | — | | | | — | | | | — | | | | 1,718 | | Intangible assets, net | | | 797 | | | | 16 | | | | 2 | | | | — | | | | 815 | | Nuclear decommissioning trust fund | | | 303 | | | | — | | | | — | | | | — | | | | 303 | | Derivative instruments valuation | | | 870 | | | | — | | | | 15 | | | | — | | | | 885 | | Other non-current assets | | | 9 | | | | 4 | | | | 112 | | | | — | | | | 125 | | | | | | | | | | | | | | | | | | | | | | | Total other assets | | | 4,972 | | | | 937 | | | | 15,247 | | | | (16,385 | ) | | | 4,771 | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | $ | 21,791 | | | $ | 1,987 | | | $ | 17,645 | | | $ | (16,615 | ) | | $ | 24,808 | | | | | | | | | | | | | | | | | | | | | | | | LIABILITIES AND STOCKHOLDERS’ EQUITY | Current Liabilities | | | | | | | | | | | | | | | | | | | | | Current portion of long-term debt and capital leases | | $ | 67 | | | $ | 235 | | | $ | 229 | | | $ | (67 | ) | | $ | 464 | | Accounts payable — trade | | | (1,302 | ) | | | 429 | | | | 1,324 | | | | — | | | | 451 | | Derivative instruments valuation | | | 3,976 | | | | 3 | | | | 2 | | | | — | | | | 3,981 | | Deferred income taxes | | | 503 | | | | 31 | | | | (333 | ) | | | — | | | | 201 | | Cash collateral received in support of energy risk management activities | | | 760 | | | | — | | | | — | | | | — | | | | 760 | | Accrued expenses and other current liabilities | | | 507 | | | | 48 | | | | 333 | | | | (164 | ) | | | 724 | | | | | | | | | | | | | | | | | | | | | | | Total current liabilities | | | 4,511 | | | | 746 | | | | 1,555 | | | | (231 | ) | | | 6,581 | | | | | | | | | | | | | | | | | | | | | | | Other Liabilities | | | | | | | | | | | | | | | | | | | | | Long-term debt and capital leases | | | 2,730 | | | | 1,021 | | | | 7,728 | | | | (3,775 | ) | | | 7,704 | | Nuclear decommissioning reserve | | | 284 | | | | — | | | | — | | | | — | | | | 284 | | Nuclear decommissioning trust liability | | | 218 | | | | — | | | | — | | | | — | | | | 218 | | Deferred income taxes | | | 705 | | | | (187 | ) | | | 672 | | | | — | | | | 1,190 | | Derivative instruments valuation | | | 348 | | | | 46 | | | | 114 | | | | — | | | | 508 | | Out-of-market contracts | | | 291 | | | | — | | | | — | | | | — | | | | 291 | | Other non-current liabilities | | | 405 | | | | 44 | | | | 220 | | | | — | | | | 669 | | | | | | | | | | | | | | | | | | | | | | | Total non-current liabilities | | | 4,981 | | | | 924 | | | | 8,734 | | | | (3,775 | ) | | | 10,864 | | | | | | | | | | | | | | | | | | | | | | | Total liabilities | | | 9,492 | | | | 1,670 | | | | 10,289 | | | | (4,006 | ) | | | 17,445 | | | | | | | | | | | | | | | | | | | | | | | Minority Interest | | | 7 | | | | — | | | | — | | | | — | | | | 7 | | 3.625% Preferred Stock | | | — | | | | — | | | | 247 | | | | — | | | | 247 | | Stockholders’ Equity | | | 12,292 | | | | 317 | | | | 7,109 | | | | (12,609 | ) | | | 7,109 | | | | | | | | | | | | | | | | | | | | | | | Total Liabilities and Stockholders’ Equity | | $ | 21,791 | | | $ | 1,987 | | | $ | 17,645 | | | $ | (16,615 | ) | | $ | 24,808 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2008
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | NRG
| | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | Energy,
| | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | | | | | | | | Net income | | $ | 1,615 | | | $ | 262 | | | $ | 1,188 | | | $ | (1,877 | ) | | $ | 1,188 | | Adjustments to reconcile net income to net cash provided by operating activities | | | | | | | | | | | | | | | | | | | | | Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | | | (274 | ) | | | (46 | ) | | | (1,601 | ) | | | 1,877 | | | | (44 | ) | Depreciation and amortization | | | 618 | | | | 27 | | | | 4 | | | | — | | | | 649 | | Amortization of nuclear fuel | | | 39 | | | | — | | | | — | | | | — | | | | 39 | | Amortization and write-off of deferred financing costs and debt discount/premiums | | | — | | | | 7 | | | | 22 | | | | — | | | | 29 | | Amortization of intangibles and out-of-market contracts | | | (270 | ) | | | — | | | | — | | | | — | | | | (270 | ) | Amortization of unearned equity compensation | | | — | | | | — | | | | 26 | | | | — | | | | 26 | | Loss on disposals and sales of assets | | | 25 | | | | — | | | | — | | | | — | | | | 25 | | Impairment charges and asset write downs | | | — | | | | — | | | | 23 | | | | — | | | | 23 | | Changes in derivatives | | | (482 | ) | | | (2 | ) | | | — | | | | — | | | | (484 | ) | Changes in deferred income taxes and liability for unrecognized tax benefits | | | 312 | | | | (16 | ) | | | 466 | | | | — | | | | 762 | | Gain on sale of discontinued operations | | | — | | | | (273 | ) | | | — | | | | — | | | | (273 | ) | Gain on sale of emission allowances | | | (51 | ) | | | — | | | | — | | | | — | | | | (51 | ) | Change in nuclear decommissioning trust liability | | | 34 | | | | — | | | | — | | | | — | | | | 34 | | Changes in collateral deposits supporting energy risk management activities | | | (417 | ) | | | — | | | | — | | | | — | | | | (417 | ) | Cash provided/(used) by changes in other working capital, net of disposition affects | | | 745 | | | | 88 | | | | (635 | ) | | | — | | | | 198 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Operating Activities | | | 1,894 | | | | 47 | | | | (507 | ) | | | — | | | | 1,434 | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | | | | | | | | Intercompany (loans to)/receipts from subsidiaries | | | (238 | ) | | | — | | | | 696 | | | | (458 | ) | | | — | | Capital expenditures | | | (597 | ) | | | (294 | ) | | | (8 | ) | | | — | | | | (899 | ) | Decrease in restricted cash | | | (6 | ) | | | 19 | | | | — | | | | — | | | | 13 | | Decrease in notes receivable | | | — | | | | 45 | | | | (35 | ) | | | — | | | | 10 | | Purchases of emission allowances | | | (8 | ) | | | — | | | | — | | | | — | | | | (8 | ) | Proceeds from sale of emission allowances | | | 75 | | | | — | | | | — | | | | — | | | | 75 | | Investments in nuclear decommissioning trust fund securities | | | (616 | ) | | | — | | | | — | | | | — | | | | (616 | ) | Proceeds from sales of nuclear decommissioning trust fund securities | | | 582 | | | | — | | | | — | | | | — | | | | 582 | | Proceeds from sale of assets | | | 14 | | | | — | | | | — | | | | — | | | | 14 | | Equity investment in unconsolidated affiliate | | | — | | | | (84 | ) | | | — | | | | — | | | | (84 | ) | Proceeds from sale of discontinued operations, net of cash divested | | | — | | | | (59 | ) | | | 300 | | | | — | | | | 241 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Investing Activities | | | (794 | ) | | | (373 | ) | | | 953 | | | | (458 | ) | | | (672 | ) | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | | | | | | | | (Payments)/proceeds from intercompany loans | | | (1,059 | ) | | | 315 | | | | 286 | | | | 458 | | | | — | | Payment of dividends to preferred stockholders | | | — | | | | — | | | | (55 | ) | | | — | | | | (55 | ) | Payment of financing element of acquired derivatives | | | (43 | ) | | | — | | | | — | | | | — | | | | (43 | ) | Payment for treasury stock | | | — | | | | — | | | | (185 | ) | | | — | | | | (185 | ) | Proceeds from sale of minority interest in subsidiary | | | — | | | | 50 | | | | — | | | | — | | | | 50 | | Proceeds from issuance of common stock, net of issuance costs | | | — | | | | — | | | | 9 | | | | — | | | | 9 | | Proceeds from issuance of long-term debt | | | — | | | | 20 | | | | | | | | — | | | | 20 | | Payment of deferred debt issuance costs | | | — | | | | (2 | ) | | | (2 | ) | | | — | | | | (4 | ) | Payments of short and long-term debt | | | — | | | | (60 | ) | | | (174 | ) | | | — | | | | (234 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Financing Activities | | | (1,102 | ) | | | 323 | | | | (121 | ) | | | 458 | | | | (442 | ) | | | | | | | | | | | | | | | | | | | | | | Change in cash from discontinued operations | | | — | | | | 43 | | | | — | | | | — | | | | 43 | | Effect of exchange rate changes on cash and cash equivalents | | | — | | | | (1 | ) | | | — | | | | — | | | | (1 | ) | | | | | | | | | | | | | | | | | | | | | | Net Increase/(Decrease) in Cash and Cash Equivalents | | | (2 | ) | | | 39 | �� | | | 325 | | | | — | | | | 362 | | Cash and Cash Equivalents at Beginning of Period | | | — | | | | 120 | | | | 1,012 | | | | — | | | | 1,132 | | | | | | | | | | | | | | | | | | | | | | | Cash and Cash Equivalents at End of Period | | $ | (2 | ) | | $ | 159 | | | $ | 1,337 | | | $ | — | | | $ | 1,494 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
223
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2007
| | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 5,614 | | | $ | 375 | | | $ | — | | | $ | — | | | $ | 5,989 | | | | | | | | | | | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | Cost of operations | | | 3,130 | | | | 248 | | | | — | | | | — | | | | 3,378 | | Depreciation and amortization | | | 630 | | | | 24 | | | | 4 | | | | — | | | | 658 | | General and administrative | | | 102 | | | | 18 | | | | 189 | | | | — | | | | 309 | | Development costs | | | 66 | | | | 2 | | | | 33 | | | | — | | | | 101 | | | | | | | | | | | | | | | | | | | | | | | Total operating costs and expenses | | | 3,928 | | | | 292 | | | | 226 | | | | — | | | | 4,446 | | | | | | | | | | | | | | | | | | | | | | | Gain/(loss) on sale of assets | | | 18 | | | | — | | | | (1 | ) | | | — | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | Operating Income/(Loss) | | | 1,704 | | | | 83 | | | | (227 | ) | | | — | | | | 1,560 | | | | | | | | | | | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | | | | | | | | | Equity in earnings of consolidated subsidiaries | | | 204 | | | | — | | | | 986 | | | | (1,190 | ) | | | — | | Equity in earnings of unconsolidated affiliates | | | (3 | ) | | | 57 | | | | — | | | | — | | | | 54 | | Gain on sale of equity method investments | | | — | | | | 1 | | | | — | | | | — | | | | 1 | | Other income, net | | | 9 | | | | 13 | | | | 33 | | | | — | | | | 55 | | Refinancing expenses | | | — | | | | — | | | | (35 | ) | | | — | | | | (35 | ) | Interest expense | | | (250 | ) | | | (64 | ) | | | (375 | ) | | | — | | | | (689 | ) | | | | | | | | | | | | | | | | | | | | | | Total other income/(expense) | | | (40 | ) | | | 7 | | | | 609 | | | | (1,190 | ) | | | (614 | ) | | | | | | | | | | | | | | | | | | | | | | Income From Continuing Operations Before Income Taxes | | | 1,664 | | | | 90 | | | | 382 | | | | (1,190 | ) | | | 946 | | Income tax expense/(benefit) | | | 576 | | | | 5 | | | | (204 | ) | | | — | | | | 377 | | | | | | | | | | | | | | | | | | | | | | | Income From Continuing Operations | | | 1,088 | | | | 85 | | | | 586 | | | | (1,190 | ) | | | 569 | | Income from discontinued operations, net of income taxes | | | — | | | | 17 | | | | — | | | | — | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | Net Income | | $ | 1,088 | | | $ | 102 | | | $ | 586 | | | $ | (1,190 | ) | | $ | 586 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
224
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEETS
December 31, 2007
| | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | | ASSETS | Current Assets | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | — | | | $ | 120 | | | $ | 1,012 | | | $ | — | | | $ | 1,132 | | Restricted cash | | | 1 | | | | 28 | | | | — | | | | — | | | | 29 | | Accounts receivable-trade, net | | | 445 | | | | 37 | | | | — | | | | — | | | | 482 | | Inventory | | | 439 | | | | 12 | | | | — | | | | — | | | | 451 | | Deferred income taxes | | | 139 | | | | (18 | ) | | | 3 | | | | — | | | | 124 | | Derivative instruments valuation | | | 1,034 | | | | — | | | | — | | | | — | | | | 1,034 | | Cash collateral paid in support of energy risk management activities | | | 85 | | | | — | | | | — | | | | — | | | | 85 | | Prepayments and other current assets | | | 97 | | | | 34 | | | | 195 | | | | (152 | ) | | | 174 | | Current assets — discontinued operations | | | — | | | | 51 | | | | — | | | | — | | | | 51 | | | | | | | | | | | | | | | | | | | | | | | Total current assets | | | 2,240 | | | | 264 | | | | 1,210 | | | | (152 | ) | | | 3,562 | | | | | | | | | | | | | | | | | | | | | | | Net Property, Plant and Equipment | | | 10,828 | | | | 470 | | | | 22 | | | | — | | | | 11,320 | | | | | | | | | | | | | | | | | | | | | | | Other Assets | | | | | | | | | | | | | | | | | | | | | Investment in subsidiaries | | | 610 | | | | — | | | | 9,787 | | | | (10,397 | ) | | | — | | Equity investments in affiliates | | | 28 | | | | 397 | | | | — | | | | — | | | | 425 | | Capital leases and notes receivable, less current portion | | | 360 | | | | 491 | | | | 3,779 | | | | (4,139 | ) | | | 491 | | Goodwill | | | 1,786 | | | | — | | | | — | | | | — | | | | 1,786 | | Intangible assets, net | | | 859 | | | | 14 | | | | — | | | | — | | | | 873 | | Nuclear decommissioning trust fund | | | 384 | | | | — | | | | — | | | | — | | | | 384 | | Derivative instruments valuation | | | 150 | | | | — | | | | — | | | | — | | | | 150 | | Other non-current assets | | | 25 | | | | 1 | | | | 164 | | | | — | | | | 190 | | Non-current assets — discontinued operations | | | — | | | | 93 | | | | — | | | | — | | | | 93 | | | | | | | | | | | | | | | | | | | | | | | Total other assets | | | 4,202 | | | | 996 | | | | 13,730 | | | | (14,536 | ) | | | 4,392 | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | $ | 17,270 | | | $ | 1,730 | | | $ | 14,962 | | | $ | (14,688 | ) | | $ | 19,274 | | | | | | | | | | | | | | | | | | | | | | | | LIABILITIES AND STOCKHOLDERS’ EQUITY | Current Liabilities | | | | | | | | | | | | | | | | | | | | | Current portion of long-term debt and capital leases | | $ | 83 | | | $ | 282 | | | $ | 184 | | | $ | (83 | ) | | $ | 466 | | Accounts payable — trade | | | (695 | ) | | | 348 | | | | 731 | | | | — | | | | 384 | | Derivative instruments valuation | | | 916 | | | | 1 | | | | — | | | | — | | | | 917 | | Cash collateral received in support of energy risk management activities | | | 14 | | | | — | | | | — | | | | — | | | | 14 | | Accrued expenses and other current liabilities | | | 321 | | | | 62 | | | | 145 | | | | (69 | ) | | | 459 | | Current liabilities — discontinued operations | | | — | | | | 37 | | | | — | | | | — | | | | 37 | | | | | | | | | | | | | | | | | | | | | | | Total current liabilities | | | 639 | | | | 730 | | | | 1,060 | | | | (152 | ) | | | 2,277 | | | | | | | | | | | | | | | | | | | | | | | Other Liabilities | | | | | | | | | | | | | | | | | | | | | Long-term debt and capital leases | | | 3,773 | | | | 571 | | | | 7,690 | | | | (4,139 | ) | | | 7,895 | | Nuclear decommissioning reserve | | | 307 | | | | — | | | | — | | | | — | | | | 307 | | Nuclear decommissioning trust liability | | | 326 | | | | — | | | | — | | | | — | | | | 326 | | Deferred income taxes | | | 598 | | | | (138 | ) | | | 383 | | | | — | | | | 843 | | Derivative instruments valuation | | | 690 | | | | 16 | | | | 53 | | | | — | | | | 759 | | Out-of-market contracts | | | 628 | | | | — | | | | — | | | | — | | | | 628 | | Other non-current liabilities | | | 377 | | | | 10 | | | | 25 | | | | — | | | | 412 | | Non-current liabilities — discontinued operations | | | — | | | | 76 | | | | — | | | | — | | | | 76 | | | | | | | | | | | | | | | | | | | | | | | Total non-current liabilities | | | 6,699 | | | | 535 | | | | 8,151 | | | | (4,139 | ) | | | 11,246 | | | | | | | | | | | | | | | | | | | | | | | Total liabilities | | | 7,338 | | | | 1,265 | | | | 9,211 | | | | (4,291 | ) | | | 13,523 | | | | | | | | | | | | | | | | | | | | | | | 3.625% Preferred Stock | | | — | | | | — | | | | 247 | | | | — | | | | 247 | | Stockholders’ Equity | | | 9,932 | | | | 465 | | | | 5,504 | | | | (10,397 | ) | | | 5,504 | | | | | | | | | | | | | | | | | | | | | | | Total Liabilities and Stockholders’ Equity | | $ | 17,270 | | | $ | 1,730 | | | $ | 14,962 | | | $ | (14,688 | ) | | $ | 19,274 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
225
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS BALANCE SHEETS Year Ended December 31, 20072009
| | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | | | | | | | | Net income | | $ | 1,088 | | | $ | 102 | | | $ | 586 | | | $ | (1,190 | ) | | $ | 586 | | Adjustments to reconcile net income to net cash provided/(used) by operating activities | | | | | | | | | | | | | | | | | | | | | Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | | | 101 | | | | (36 | ) | | | (684 | ) | | | 586 | | | | (33 | ) | Depreciation and amortization | | | 630 | | | | 27 | | | | 4 | | | | — | | | | 661 | | Amortization of nuclear fuel | | | 58 | | | | — | | | | — | | | | — | | | | 58 | | Amortization and write-off of deferred financing costs and debt discount/premiums | | | — | | | | 6 | | | | 60 | | | | — | | | | 66 | | Amortization of intangibles and out-of-market contracts | | | (160 | ) | | | 4 | | | | — | | | | — | | | | (156 | ) | Amortization of unearned equity compensation | | | — | | | | — | | | | 19 | | | | — | | | | 19 | | Gains on sale of equity method investments | | | — | | | | (1 | ) | | | — | | | | — | | | | (1 | ) | (Gain)/loss on sale assets | | | (18 | ) | | | — | | | | 1 | | | | — | | | | (17 | ) | Impairment charges and asset write downs | | | 9 | | | | — | | | | 11 | | | | — | | | | 20 | | Changes in derivatives | | | 77 | | | | — | | | | — | | | | — | | | | 77 | | Changes in deferred income taxes | | | 112 | | | | (31 | ) | | | 271 | | | | — | | | | 352 | | Gain on sale of emission allowances | | | (30 | ) | | | (1 | ) | | | — | | | | — | | | | (31 | ) | Change in nuclear decommissioning trust liability | | | 32 | | | | — | | | | — | | | | — | | | | 32 | | Changes in collateral deposits supporting energy risk management activities | | | (125 | ) | | | — | | | | — | | | | — | | | | (125 | ) | Cash provided/(used) by changes in other working capital, net of disposition affects | | | 218 | | | | 96 | | | | (305 | ) | | | — | | | | 9 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Operating Activities | | | 1,992 | | | | 166 | | | | (37 | ) | | | (604 | ) | | | 1,517 | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | | | | | | | | Intercompany loans to subsidiaries | | | 655 | | | | — | | | | 2,109 | | | | (2,764 | ) | | | — | | Capital expenditures | | | (389 | ) | | | (84 | ) | | | (8 | ) | | | — | | | | (481 | ) | Decrease in restricted cash, net | | | — | | | | 12 | | | | — | | | | — | | | | 12 | | Decrease in notes receivable | | | — | | | | 34 | | | | — | | | | — | | | | 34 | | Decrease in trust fund balances | | | 19 | | | | — | | | | — | | | | — | | | | 19 | | Purchases of emission allowances | | | (161 | ) | | | — | | | | — | | | | — | | | | (161 | ) | Proceeds from sale of emission allowances | | | 271 | | | | 1 | | | | — | | | | — | | | | 272 | | Investments in nuclear decommissioning trust fund securities | | | (265 | ) | | | — | | | | — | | | | — | | | | (265 | ) | Proceeds from sales of nuclear decommissioning trust fund securities | | | 233 | | | | — | | | | — | | | | — | | | | 233 | | Proceeds from sale of assets | | | — | | | | 2 | | | | — | | | | — | | | | 2 | | Purchase of securities | | | — | | | | — | | | | (49 | ) | | | — | | | | (49 | ) | Proceeds from sale of discontinued operations and assets, net of cash divested | | | 29 | | | | — | | | | 28 | | | | — | | | | 57 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Investing Activities | | | 392 | | | | (35 | ) | | | 2,080 | | | | (2,764 | ) | | | (327 | ) | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | | | | | | | | Payment of dividends to preferred stockholders | | | — | | | | — | | | | (55 | ) | | | — | | | | (55 | ) | Payment for treasury stock | | | — | | | | — | | | | (353 | ) | | | — | | | | (353 | ) | Payments from intercompany loans | | | (2,101 | ) | | | (38 | ) | | | (625 | ) | | | 2,764 | | | | — | | Payments from intercompany dividends | | | (302 | ) | | | (302 | ) | | | — | | | | 604 | | | | — | | Proceeds from issuance of common stock, net of issuance costs | | | — | | | | — | | | | 7 | | | | — | | | | 7 | | Proceeds from issuance of long-term debt | | | — | | | | — | | | | 1,411 | | | | — | | | | 1,411 | | Payment of deferred debt issuance costs | | | — | | | | — | | | | (5 | ) | | | — | | | | (5 | ) | Payments of short and long-term debt | | | (1 | ) | | | (64 | ) | | | (1,754 | ) | | | — | | | | (1,819 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Financing Activities | | | (2,404 | ) | | | (404 | ) | | | (1,374 | ) | | | 3,368 | | | | (814 | ) | | | | | | | | | | | | | | | | | | | | | | Change in cash from discontinued operations | | | — | | | | (25 | ) | | | — | | | | — | | | | (25 | ) | Effect of exchange rate changes on cash and cash equivalents | | | — | | | | 4 | | | | — | | | | — | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | Net Increase/(Decrease) in Cash and Cash Equivalents | | | (20 | ) | | | (294 | ) | | | 669 | | | | — | | | | 355 | | Cash and Cash Equivalents at Beginning of Period | | | 20 | | | | 414 | | | | 343 | | | | — | | | | 777 | | | | | | | | | | | | | | | | | | | | | | | Cash and Cash Equivalents at End of Period | | $ | — | | | $ | 120 | | | $ | 1,012 | | | $ | — | | | $ | 1,132 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | ASSETS | Current Assets | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 20 | | | $ | 120 | | | $ | 2,164 | | | $ | — | | | $ | 2,304 | | Funds deposited by counterparties | | | 177 | | | | — | | | | — | | | | — | | | | 177 | | Restricted cash | | | 1 | | | | 1 | | | | — | | | | — | | | | 2 | | Accounts receivable-trade, net | | | 837 | | | | 39 | | | | — | | | | — | | | | 876 | | Inventory | | | 529 | | | | 12 | | | | — | | | | — | | | | 541 | | Derivative instruments valuation | | | 1,636 | | | | — | | | | — | | | | — | | | | 1,636 | | Cash collateral paid in support of energy risk management activities | | | 359 | | | | 2 | | | | — | | | | — | | | | 361 | | Prepayments and other current assets | | | 194 | | | | 61 | | | | 157 | | | | (101 | ) | | | 311 | | | | | | | | | | | | | | | | | | | | | | | Total current assets | | | 3,753 | | | | 235 | | | | 2,321 | | | | (101 | ) | | | 6,208 | | | | | | | | | | | | | | | | | | | | | | | Net Property, Plant and Equipment | | | 10,494 | | | | 1,009 | | | | 61 | | | | — | | | | 11,564 | | | | | | | | | | | | | | | | | | | | | | | Other Assets | | | | | | | | | | | | | | | | | | | | | Investment in subsidiaries | | | 613 | | | | 222 | | | | 16,862 | | | | (17,697 | ) | | | — | | Equity investments in affiliates | | | 42 | | | | 367 | | | | — | | | | — | | | | 409 | | Capital leases and note receivable, less current portion | | | 4,982 | | | | 504 | | | | 3,027 | | | | (8,009 | ) | | | 504 | | Goodwill | | | 1,718 | | | | — | | | | — | | | | — | | | | 1,718 | | Intangible assets, net | | | 1,755 | | | | 20 | | | | 33 | | | | (31 | ) | | | 1,777 | | Nuclear decommissioning trust fund | | | 367 | | | | — | | | | — | | | | — | | | | 367 | | Derivative instruments valuation | | | 718 | | | | — | | | | 8 | | | | (43 | ) | | | 683 | | Other non-current assets | | | 29 | | | | 8 | | | | 111 | | | | — | | | | 148 | | | | | | | | | | | | | | | | | | | | | | | Total other assets | | | 10,224 | | | | 1,121 | | | | 20,041 | | | | (25,780 | ) | | | 5,606 | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | $ | 24,471 | | | $ | 2,365 | | | $ | 22,423 | | | $ | (25,881 | ) | | $ | 23,378 | | | | | | | | | | | | | | | | | | | | | | | | LIABILITIES AND STOCKHOLDERS’ EQUITY | Current Liabilities | | | | | | | | | | | | | | | | | | | | | Current portion of long-term debt and capital leases | | $ | 58 | | | $ | 310 | | | $ | 261 | | | $ | (58 | ) | | $ | 571 | | Accounts payable | | | (852 | ) | | | 393 | | | | 1,156 | | | | — | | | | 697 | | Derivative instruments valuation | | | 1,469 | | | | 2 | | | | 2 | | | | — | | | | 1,473 | | Deferred income taxes | | | 456 | | | | 11 | | | | (270 | ) | | | — | | | | 197 | | Cash collateral received in support of energy risk management activities | | | 177 | | | | — | | | | — | | | | — | | | | 177 | | Accrued expenses and other current liabilities | | | 261 | | | | 82 | | | | 347 | | | | (43 | ) | | | 647 | | | | | | | | | | | | | | | | | | | | | | | Total current liabilities | | | 1,569 | | | | 798 | | | | 1,496 | | | | (101 | ) | | | 3,762 | | | | | | | | | | | | | | | | | | | | | | | Other Liabilities | | | | | | | | | | | | | | | | | | | | | Long-term debt and capital leases | | | 2,533 | | | | 1,003 | | | | 12,320 | | | | (8,009 | ) | | | 7,847 | | Nuclear decommissioning reserve | | | 300 | | | | — | | | | — | | | | — | | | | 300 | | Nuclear decommissioning trust liability | | | 255 | | | | — | | | | — | | | | — | | | | 255 | | Deferred income taxes | | | 1,711 | | | | (165 | ) | | | 237 | | | | — | | | | 1,783 | | Derivative instruments valuation | | | 323 | | | | 28 | | | | 79 | | | | (43 | ) | | | 387 | | Out-of-market contracts | | | 318 | | | | 7 | | | | — | | | | (31 | ) | | | 294 | | Other non-current liabilities | | | 431 | | | | 16 | | | | 359 | | | | — | | | | 806 | | | | | | | | | | | | | | | | | | | | | | | Total non-current liabilities | | | 5,871 | | | | 889 | | | | 12,995 | | | | (8,083 | ) | | | 11,672 | | | | | | | | | | | | | | | | | | | | | | | Total liabilities | | | 7,440 | | | | 1,687 | | | | 14,491 | | | | (8,184 | ) | | | 15,434 | | | | | | | | | | | | | | | | | | | | | | | 3.625% Preferred Stock | | | — | | | | — | | | | 247 | | | | — | | | | 247 | | Stockholders’ Equity | | | 17,031 | | | | 678 | | | | 7,685 | | | | (17,697 | ) | | | 7,697 | | | | | | | | | | | | | | | | | | | | | | | Total Liabilities and Stockholders’ Equity | | $ | 24,471 | | | $ | 2,365 | | | $ | 22,423 | | | $ | (25,881 | ) | | $ | 23,378 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
226
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS CASH FLOWS For the Year Ended December 31, 20062009
| | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | NRG
| | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 5,282 | | | $ | 303 | | | $ | — | | | $ | — | | | $ | 5,585 | | | | | | | | | | | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | Cost of operations | | | 3,038 | | | | 225 | | | | 2 | | | | — | | | | 3,265 | | Depreciation and amortization | | | 562 | | | | 23 | | | | 5 | | | | — | | | | 590 | | General and administrative | | | 82 | | | | 14 | | | | 180 | | | | — | | | | 276 | | Development costs | | | 32 | | | | — | | | | 4 | | | | — | | | | 36 | | | | | | | | | | | | | | | | | | | | | | | Total operating costs and expenses | | | 3,714 | | | | 262 | | | | 191 | | | | — | | | | 4,167 | | | | | | | | | | | | | | | | | | | | | | | Operating Income/(Loss) | | | 1,568 | | | | 41 | | | | (191 | ) | | | — | | | | 1,418 | | | | | | | | | | | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | | | | | | | | | Equity in earnings of consolidated subsidiaries | | | 134 | | | | — | | | | 996 | | | | (1,130 | ) | | | — | | Equity in earnings of unconsolidated affiliates | | | 2 | | | | 58 | | | | — | | | | — | | | | 60 | | Gains/(losses) on sales of equity method investments | | | (5 | ) | | | 13 | | | | — | | | | — | | | | 8 | | Other income, net | | | 20 | | | | 115 | | | | 41 | | | | (20 | ) | | | 156 | | Refinancing expenses | | | — | | | | — | | | | (187 | ) | | | — | | | | (187 | ) | Interest expense | | | (232 | ) | | | (56 | ) | | | (322 | ) | | | 20 | | | | (590 | ) | | | | | | | | | | | | | | | | | | | | | | Total other income/(expense) | | | (81 | ) | | | 130 | | | | 528 | | | | (1,130 | ) | | | (553 | ) | | | | | | | | | | | | | | | | | | | | | | Income From Continuing Operations Before Income Taxes | | | 1,487 | | | | 171 | | | | 337 | | | | (1,130 | ) | | | 865 | | Income tax expense | | | 549 | | | | 42 | | | | (269 | ) | | | — | | | | 322 | | | | | | | | | | | | | | | | | | | | | | | Income From Continuing Operations | | | 938 | | | | 129 | | | | 606 | | | | (1,130 | ) | | | 543 | | Income from discontinued operations, net of income taxes | | | — | | | | 63 | | | | 15 | | | | — | | | | 78 | | | | | | | | | | | | | | | | | | | | | | | Net Income | | $ | 938 | | | $ | 192 | | | $ | 621 | | | $ | (1,130 | ) | | $ | 621 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | NRG
| | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | Energy,
| | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | Inc. | | | Eliminations(a) | | | Balance | | | | | | | | | | (In millions) | | | | | | | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | | | | | | | | Net income | | $ | 1,544 | | | $ | 124 | | | $ | 942 | | | $ | (1,669 | ) | | $ | 941 | | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | | Distributions and equity (earnings)/losses of unconsolidated affiliates | | | 154 | | | | (31 | ) | | | (1,173 | ) | | | 1,009 | | | | (41 | ) | Depreciation and amortization | | | 772 | | | | 40 | | | | 6 | | | | — | | | | 818 | | Provision for bad debts | | | 61 | | | | — | | | | — | | | | — | | | | 61 | | Amortization of nuclear fuel | | | 36 | | | | — | | | | — | | | | — | | | | 36 | | Amortization of financing costs and debt discounts/premiums | | | — | | | | 13 | | | | 31 | | | | — | | | | 44 | | Amortization of intangibles andout-of-market contracts | | | 153 | | | | — | | | | — | | | | — | | | | 153 | | Changes in deferred income taxes and liability for unrecognized tax benefits | | | 934 | | | | (16 | ) | | | (229 | ) | | | — | | | | 689 | | Changes in nuclear decommissioning liability | | | 26 | | | | — | | | | — | | | | — | | | | 26 | | Changes in derivatives | | | (228 | ) | | | 3 | | | | — | | | | — | | | | (225 | ) | Changes in collateral deposits supporting energy risk management activities | | | 129 | | | | (2 | ) | | | — | | | | — | | | | 127 | | Loss on disposals and sales of assets | | | 17 | | | | — | | | | — | | | | — | | | | 17 | | Gain on sales of equity method investments | | | — | | | | (128 | ) | | | — | | | | — | | | | (128 | ) | Gain on sale of emission allowances | | | (4 | ) | | | — | | | | — | | | | — | | | | (4 | ) | Gain recognized on settlement of pre-existing relationship | | | — | | | | — | | | | (31 | ) | | | — | | | | (31 | ) | Amortization of unearned equity compensation | | | — | | | | — | | | | 26 | | | | — | | | | 26 | | Changes in option premiums collected | | | (282 | ) | | | — | | | | — | | | | — | | | | (282 | ) | Cash provided/(used) by changes in other working capital, net of acquisition/disposition affects | | | (487 | ) | | | 31 | | | | 335 | | | | | | | | (121 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Operating Activities | | | 2,825 | | | | 34 | | | | (93 | ) | | | (660 | ) | | | 2,106 | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | | | | | | | | Intercompany (loans to)/receipts from subsidiaries | | | (1,755 | ) | | | — | | | | 159 | | | | 1,596 | | | | — | | Investment in subsidiaries | | | 200 | | | | 60 | | | | (260 | ) | | | — | | | | — | | Capital expenditures | | | (507 | ) | | | (197 | ) | | | (30 | ) | | | — | | | | (734 | ) | Acquisition of businesses, net of cash acquired | | | (72 | ) | | | (67 | ) | | | (288 | ) | | | — | | | | (427 | ) | Increase in restricted cash, net | | | 6 | | | | 8 | | | | — | | | | — | | | | 14 | | (Increase)/decrease in notes receivable | | | — | | | | (58 | ) | | | 36 | | | | — | | | | (22 | ) | Purchases of emission allowances | | | (78 | ) | | | — | | | | — | | | | — | | | | (78 | ) | Proceeds from sale of emission allowances | | | 40 | | | | — | | | | — | | | | — | | | | 40 | | Investments in nuclear decommissioning trust fund securities | | | (305 | ) | | | — | | | | — | | | | — | | | | (305 | ) | Proceeds from sales of nuclear decommissioning trust fund securities | | | 279 | | | | — | | | | — | | | | — | | | | 279 | | Proceeds from sale of assets, net | | | 6 | | | | — | | | | — | | | | — | | | | 6 | | Proceeds from sale of equity method investment | | | — | | | | 284 | | | | — | | | | — | | | | 284 | | Equity investment in unconsolidated affiliate | | | — | | | | — | | | | (6 | ) | | | — | | | | (6 | ) | Other | | | — | | | | — | | | | (5 | ) | | | — | | | | (5 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Investing Activities | | | (2,186 | ) | | | 30 | | | | (394 | ) | | | 1,596 | | | | (954 | ) | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | | | | | | | | (Payments)/proceeds from intercompany loans | | | (258 | ) | | | 99 | | | | 1,755 | | | | (1,596 | ) | | | — | | Payment of intercompany dividends | | | (330 | ) | | | (330 | ) | | | — | | | | 660 | | | | — | | Payment of dividends to preferred stockholders | | | — | | | | — | | | | (33 | ) | | | — | | | | (33 | ) | Net payments to settle acquired derivatives that include financing elements | | | (79 | ) | | | — | | | | — | | | | — | | | | (79 | ) | Payment for treasury stock | | | — | | | | — | | | | (500 | ) | | | — | | | | (500 | ) | Installment proceeds from sale of noncontrolling interest in subsidiary | | | — | | | | 50 | | | | — | | | | — | | | | 50 | | Proceeds from issuance of common stock, net of issuance costs | | | — | | | | — | | | | 2 | | | | — | | | | 2 | | Proceeds from issuance of long-term debt | | | 77 | | | | 127 | | | | 688 | | | | — | | | | 892 | | Payment of deferred debt issuance costs | | | (2 | ) | | | (3 | ) | | | (26 | ) | | | — | | | | (31 | ) | Payments of short and long-term debt | | | (25 | ) | | | (47 | ) | | | (572 | ) | | | — | | | | (644 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Financing Activities | | | (617 | ) | | | (104 | ) | | | 1,314 | | | | (936 | ) | | | (343 | ) | | | | | | | | | | | | | | | | | | | | | | Effect of exchange rate changes on cash and cash equivalents | | | — | | | | 1 | | | | — | | | | — | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | Net Increase/(Decrease) in Cash and Cash Equivalents | | | 22 | | | | (39 | ) | | | 827 | | | | — | | | | 810 | | Cash and Cash Equivalents at Beginning of Period | | | (2 | ) | | | 159 | | | | 1,337 | | | | — | | | | 1,494 | | | | | | | | | | | | | | | | | | | | | | | Cash and Cash Equivalents at End of Period | | $ | 20 | | | $ | 120 | | | $ | 2,164 | | | $ | — | | | $ | 2,304 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
227
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS OPERATIONS For the Year Ended December 31, 20062008 | | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | | | | | | | | Net income | | $ | 938 | | | $ | 192 | | | $ | 621 | | | $ | (1,130 | ) | | $ | 621 | | Adjustments to reconcile net income to net cash provided/(used) by operating activities | | | | | | | | | | | | | | | | | | | | | Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | | | (136 | ) | | | (31 | ) | | | (996 | ) | | | 1,130 | | | | (33 | ) | Depreciation and amortization of nuclear fuel | | | 609 | | | | 35 | | | | 10 | | | | — | | | | 654 | | Amortization and write-of of deferred financing costs and debt discount/premiums | | | — | | | | 6 | | | | 73 | | | | — | | | | 79 | | Amortization of intangibles and out-of-market contracts | | | (487 | ) | | | (3 | ) | | | — | | | | — | | | | (490 | ) | Amortization of unearned equity compensation | | | — | | | | — | | | | 14 | | | | — | | | | 14 | | Write down and gains on sale of equity method investments | | | 5 | | | | (13 | ) | | | — | | | | — | | | | (8 | ) | Loss on sale of equipment | | | 10 | | | | — | | | | — | | | | — | | | | 10 | | Changes in derivatives | | | (151 | ) | | | 2 | | | | — | | | | — | | | | (149 | ) | Changes in deferred income taxes | | | 474 | | | | 19 | | | | (166 | ) | | | — | | | | 327 | | Gain on legal settlement | | | — | | | | (67 | ) | | | — | | | | — | | | | (67 | ) | Gain on sale of discontinued operations | | | — | | | | (71 | ) | | | (5 | ) | | | — | | | | (76 | ) | Gain on sale of emission allowances | | | (64 | ) | | | — | | | | — | | | | — | | | | (64 | ) | Change in nuclear decommissioning trust liability | | | 12 | | | | — | | | | — | | | | — | | | | 12 | | Changes in collateral deposits supporting energy risk management activities | | | 454 | | | | — | | | | — | | | | — | | | | 454 | | Settlement of out-of-market power contracts | | | (1,073 | ) | | | — | | | | — | | | | — | | | | (1,073 | ) | Cash provided/(used) by changes in other working capital, net of acquisition and disposition affects | | | (557 | ) | | | 216 | | | | 538 | | | | — | | | | 197 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided by Operating Activities | | | 34 | | | | 285 | | | | 89 | | | | — | | | | 408 | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | | | | | | | | I/C loans to subsidiaries | | | (939 | ) | | | — | | | | (4,106 | ) | | | 5,045 | | | | — | | Acquisition of Texas Genco, WCP and Padoma, net of cash acquired | | | — | | | | — | | | | (4,333 | ) | | | — | | | | (4,333 | ) | Capital expenditures | | | (195 | ) | | | (21 | ) | | | (5 | ) | | | — | | | | (221 | ) | Decrease in restricted cash, net | | | 2 | | | | 4 | | | | — | | | | — | | | | 6 | | Decrease in notes receivable | | | — | | | | 27 | | | | — | | | | — | | | | 27 | | Purchases of emission allowances | | | (135 | ) | | | — | | | | — | | | | — | | | | (135 | ) | Proceeds from sale of emission allowances | | | 146 | | | | — | | | | — | | | | — | | | | 146 | | Investments in nuclear decommissioning trust fund securities | | | (227 | ) | | | — | | | | — | | | | — | | | | (227 | ) | Proceeds from sales of nuclear decommissioning trust fund securities | | | 214 | | | | — | | | | — | | | | — | | | | 214 | | Proceeds from sale of investments | | | 53 | | | | 33 | | | | — | | | | — | | | | 86 | | Proceeds from sale of discontinued operations | | | — | | | | 239 | | | | 22 | | | | — | | | | 261 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Investing Activities | | | (1,081 | ) | | | 282 | | | | (8,422 | ) | | | 5,045 | | | | (4,176 | ) | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | | | | | | | | Payment of dividends to preferred stockholders | | | — | | | | — | | | | (50 | ) | | | — | | | | (50 | ) | Payment of financing element of acquired derivatives | | | (296 | ) | | | — | | | | — | | | | — | | | | (296 | ) | Payment for treasury stock | | | — | | | | (500 | ) | | | (232 | ) | | | — | | | | (732 | ) | Funded letter of credit | | | — | | | | — | | | | 350 | | | | — | | | | 350 | | Proceeds from Intercompany loans | | | 4,106 | | | | — | | | | 939 | | | | (5,045 | ) | | | — | | Proceeds from issuance of common stock, net | | | — | | | | — | | | | 986 | | | | — | | | | 986 | | Proceeds from issuance of preferred shares, net | | | — | | | | — | | | | 486 | | | | — | | | | 486 | | Proceeds from issuance of long-term debt | | | — | | | | 333 | | | | 8,286 | | | | — | | | | 8,619 | | Payment of deferred debt issuance costs | | | — | | | | — | | | | (199 | ) | | | — | | | | (199 | ) | Payments of short and long-term debt | | | (2,736 | ) | | | (62 | ) | | | (2,313 | ) | | | — | | | | (5,111 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Financing Activities | | | 1,074 | | | | (229 | ) | | | 8,253 | | | | (5,045 | ) | | | 4,053 | | Change in cash from discontinued operations | | | — | | | | 1 | | | | 1 | | | | — | | | | 2 | | Effect of exchange rate changes on cash and cash equivalents | | | — | | | | 4 | | | | — | | | | — | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | Net Increase/(decrease) in Cash and Cash Equivalents | | | 27 | | | | 343 | | | | (79 | ) | | | — | | | | 291 | | Cash and Cash Equivalents at Beginning of Period | | | (7 | ) | | | 71 | | | | 422 | | | | — | | | | 486 | | | | | | | | | | | | | | | | | | | | | | | Cash and Cash Equivalents at End of Period | | $ | 20 | | | $ | 414 | | | $ | 343 | | | $ | — | | | $ | 777 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 6,504 | | | $ | 405 | | | $ | — | | | $ | (24 | ) | | $ | 6,885 | | | | | | | | | | | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | Cost of operations | | | 3,321 | | | | 303 | | | | — | | | | (26 | ) | | | 3,598 | | Depreciation and amortization | | | 618 | | | | 27 | | | | 4 | | | | — | | | | 649 | | General and administrative | | | 64 | | | | 14 | | | | 241 | | | | — | | | | 319 | | Development costs | | | (1 | ) | | | 7 | | | | 40 | | | | — | | | | 46 | | | | | | | | | | | | | | | | | | | | | | | Total operating costs and expenses | | | 4,002 | | | | 351 | | | | 285 | | | | (26 | ) | | | 4,612 | | | | | | | | | | | | | | | | | | | | | | | Operating Income/(Loss) | | | 2,502 | | | | 54 | | | | (285 | ) | | | 2 | | | | 2,273 | | | | | | | | | | | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | | | | | | | | | Equity in earnings of consolidated subsidiaries | | | 276 | | | | — | | | | 1,638 | | | | (1,914 | ) | | | — | | Equity in earnings of unconsolidated affiliates | | | (2 | ) | | | 61 | | | | — | | | | — | | | | 59 | | Other income/(expense), net | | | 23 | | | | 11 | | | | (15 | ) | | | (2 | ) | | | 17 | | Interest expense | | | (183 | ) | | | (77 | ) | | | (323 | ) | | | — | | | | (583 | ) | | | | | | | | | | | | | | | | | | | | | | Total other income/(expense) | | | 114 | | | | (5 | ) | | | 1,300 | | | | (1,916 | ) | | | (507 | ) | | | | | | | | | | | | | | | | | | | | | | Income From Continuing Operations Before Income Taxes | | | 2,616 | | | | 49 | | | | 1,015 | | | | (1,914 | ) | | | 1,766 | | Income tax expense/(benefit) | | | 1,001 | | | | 19 | | | | (307 | ) | | | — | | | | 713 | | | | | | | | | | | | | | | | | | | | | | | Income From Continuing Operations | | | 1,615 | | | | 30 | | | | 1,322 | | | | (1,914 | ) | | | 1,053 | | Income from discontinued operations, net of income taxes | | | — | | | | 269 | | | | (97 | ) | | | — | | | | 172 | | | | | | | | | | | | | | | | | | | | | | | Net Income/(Loss) attributable to NRG Energy, Inc. | | $ | 1,615 | | | $ | 299 | | | $ | 1,225 | | | $ | (1,914 | ) | | $ | 1,225 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
228
NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2008 | | | | | | | | | | | | | | | | | | | | | | | | | | Non-
| | | | | | | | | | | | | Guarantor
| | | Guarantor
| | | NRG Energy,
| | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | ASSETS | Current Assets | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | (2 | ) | | $ | 159 | | | $ | 1,337 | | | $ | — | | | $ | 1,494 | | Funds deposited by counterparties | | | — | | | | — | | | | 754 | | | | — | | | | 754 | | Restricted cash | | | 7 | | | | 9 | | | | — | | | | — | | | | 16 | | Accounts receivable-trade, net | | | 422 | | | | 42 | | | | — | | | | — | | | | 464 | | Inventory | | | 443 | | | | 12 | | | | — | | | | — | | | | 455 | | Derivative instruments valuation | | | 4,600 | | | | — | | | | — | | | | — | | | | 4,600 | | Cash collateral paid in support of energy risk management activities | | | 494 | | | | — | | | | — | | | | — | | | | 494 | | Prepayments and other current assets | | | 130 | | | | 37 | | | | 278 | | | | (230 | ) | | | 215 | | | | | | | | | | | | | | | | | | | | | | | Total current assets | | | 6,094 | | | | 259 | | | | 2,369 | | | | (230 | ) | | | 8,492 | | | | | | | | | | | | | | | | | | | | | | | Net Property, Plant and Equipment | | | 10,725 | | | | 791 | | | | 29 | | | | — | | | | 11,545 | | | | | | | | | | | | | | | | | | | | | | | Other Assets | | | | | | | | | | | | | | | | | | | | | Investment in subsidiaries | | | 651 | | | | — | | | | 11,949 | | | | (12,600 | ) | | | — | | Equity investments in affiliates | | | 26 | | | | 464 | | | | — | | | | — | | | | 490 | | Capital leases and note receivable, less current portion | | | 598 | | | | 435 | | | | 3,177 | | | | (3,775 | ) | | | 435 | | Goodwill | | | 1,718 | | | | — | | | | — | | | | — | | | | 1,718 | | Intangible assets, net | | | 797 | | | | 16 | | | | 2 | | | | — | | | | 815 | | Nuclear decommissioning trust fund | | | 303 | | | | — | | | | — | | | | — | | | | 303 | | Derivative instruments valuation | | | 870 | | | | — | | | | 15 | | | | — | | | | 885 | | Other non-current assets | | | 9 | | | | 4 | | | | 112 | | | | — | | | | 125 | | | | | | | | | | | | | | | | | | | | | | | Total other assets | | | 4,972 | | | | 919 | | | | 15,255 | | | | (16,375 | ) | | | 4,771 | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | $ | 21,791 | | | $ | 1,969 | | | $ | 17,653 | | | $ | (16,605 | ) | | $ | 24,808 | | | | | | | | | | | | | | | | | | | | | | | LIABILITIES AND STOCKHOLDERS’ EQUITY | Current Liabilities | | | | | | | | | | | | | | | | | | | | | Current portion of long-term debt and capital leases | | $ | 67 | | | $ | 235 | | | $ | 229 | | | $ | (67 | ) | | $ | 464 | | Accounts payable | | | (1,302 | ) | | | 429 | | | | 1,324 | | | | — | | | | 451 | | Derivative instruments valuation | | | 3,976 | | | | 3 | | | | 2 | | | | — | | | | 3,981 | | Deferred income taxes | | | 503 | | | | 31 | | | | (333 | ) | | | — | | | | 201 | | Cash collateral received in support of energy risk management activities | | | 760 | | | | — | | | | — | | | | — | | | | 760 | | Accrued expenses and other current liabilities | | | 507 | | | | 48 | | | | 333 | | | | (164 | ) | | | 724 | | | | | | | | | | | | | | | | | | | | | | | Total current liabilities | | | 4,511 | | | | 746 | | | | 1,555 | | | | (231 | ) | | | 6,581 | | | | | | | | | | | | | | | | | | | | | | | Other Liabilities | | | | | | | | | | | | | | | | | | | | | Long-term debt and capital leases | | | 2,730 | | | | 1,014 | | | | 7,729 | | | | (3,776 | ) | | | 7,697 | | Nuclear decommissioning reserve | | | 284 | | | | — | | | | — | | | | — | | | | 284 | | Nuclear decommissioning trust liability | | | 218 | | | | — | | | | — | | | | — | | | | 218 | | Deferred income taxes | | | 705 | | | | (187 | ) | | | 672 | | | | — | | | | 1,190 | | Derivative instruments valuation | | | 348 | | | | 46 | | | | 114 | | | | — | | | | 508 | | Out-of-market contracts | | | 291 | | | | — | | | | — | | | | — | | | | 291 | | Other non-current liabilities | | | 405 | | | | 44 | | | | 220 | | | | — | | | | 669 | | | | | | | | | | | | | | | | | | | | | | | Total non-current liabilities | | | 4,981 | | | | 917 | | | | 8,735 | | | | (3,776 | ) | | | 10,857 | | | | | | | | | | | | | | | | | | | | | | | Total liabilities | | | 9,492 | | | | 1,663 | | | | 10,290 | | | | (4,007 | ) | | | 17,438 | | | | | | | | | | | | | | | | | | | | | | | 3.625% Preferred Stock | | | — | | | | — | | | | 247 | | | | — | | | | 247 | | Stockholders’ Equity | | | 12,299 | | | | 306 | | | | 7,116 | | | | (12,598 | ) | | | 7,123 | | | | | | | | | | | | | | | | | | | | | | | Total Liabilities and Stockholders’ Equity | | $ | 21,791 | | | $ | 1,969 | | | $ | 17,653 | | | $ | (16,605 | ) | | $ | 24,808 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
229
NRG ENERGY, INC. AND NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2008 | | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | | | | | | | | Net income | | $ | 1,615 | | | $ | 299 | | | $ | 1,225 | | | $ | (1,914 | ) | | $ | 1,225 | | Adjustments to reconcile net income to net cash provided/(used) by operating activities: | | | | | | | | | | | | | | | | | | | | | Distributions and equity (earnings)/losses of unconsolidated affiliates | | | (274 | ) | | | (46 | ) | | | (1,638 | ) | | | 1,914 | | | | (44 | ) | Depreciation and amortization | | | 618 | | | | 27 | | | | 4 | | | | — | | | | 649 | | Amortization of nuclear fuel | | | 39 | | | | — | | | | — | | | | — | | | | 39 | | Amortization of financing costs and debt discount/premiums | | | — | | | | 15 | | | | 22 | | | | — | | | | 37 | | Amortization of intangibles andout-of-market contracts | | | (270 | ) | | | — | | | | — | | | | — | | | | (270 | ) | Amortization of unearned equity compensation | | | — | | | | — | | | | 26 | | | | — | | | | 26 | | Loss on disposals and sales of assets | | | 25 | | | | — | | | | — | | | | — | | | | 25 | | Impairment charges and asset write downs | | | — | | | | — | | | | 23 | | | | — | | | | 23 | | Changes in derivatives | | | (482 | ) | | | (2 | ) | | | — | | | | — | | | | (484 | ) | Changes in deferred income taxes and liability for unrecognized tax benefits | | | 312 | | | | (16 | ) | | | 466 | | | | — | | | | 762 | | Gain on sale of discontinued operations | | | — | | | | (273 | ) | | | — | | | | — | | | | (273 | ) | Gain on sale of emission allowances | | | (51 | ) | | | — | | | | — | | | | — | | | | (51 | ) | Change in nuclear decommissioning trust liability | | | 34 | | | | — | | | | — | | | | — | | | | 34 | | Changes in collateral deposits supporting energy risk management activities | | | (417 | ) | | | — | | | | — | | | | — | | | | (417 | ) | Cash provided/(used) by changes in other working capital, net of disposition affects | | | 745 | | | | 88 | | | | (635 | ) | | | — | | | | 198 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Operating Activities | | | 1,894 | | | | 92 | | | | (507 | ) | | | — | | | | 1,479 | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | | | | | | | | Intercompany (loans to)/receipts from subsidiaries | | | (238 | ) | | | — | | | | 696 | | | | (458 | ) | | | — | | Capital expenditures | | | (597 | ) | | | (294 | ) | | | (8 | ) | | | — | | | | (899 | ) | (Increase)/decrease in restricted cash | | | (6 | ) | | | 19 | | | | — | | | | — | | | | 13 | | Decrease/(increase) in notes receivable | | | — | | | | 45 | | | | (35 | ) | | | — | | | | 10 | | Purchases of emission allowances | | | (8 | ) | | | — | | | | — | | | | — | | | | (8 | ) | Proceeds from sale of emission allowances | | | 75 | | | | — | | | | — | | | | — | | | | 75 | | Investments in nuclear decommissioning trust fund securities | | | (616 | ) | | | — | | | | — | | | | — | | | | (616 | ) | Proceeds from sales of nuclear decommissioning trust fund securities | | | 582 | | | | — | | | | — | | | | — | | | | 582 | | Proceeds from sale of assets, net | | | 14 | | | | — | | | | — | | | | — | | | | 14 | | Equity investment in unconsolidated affiliate | | | — | | | | (84 | ) | | | — | | | | — | | | | (84 | ) | Proceeds from sale of discontinued operations, net of cash divested | | | — | | | | (59 | ) | | | 300 | | | | — | | | | 241 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Investing Activities | | | (794 | ) | | | (373 | ) | | | 953 | | | | (458 | ) | | | (672 | ) | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | | | | | | | | (Payments)/proceeds from intercompany loans | | | (1,059 | ) | | | 315 | | | | 286 | | | | 458 | | | | — | | Payment for dividends to preferred stockholders | | | — | | | | — | | | | (55 | ) | | | — | | | | (55 | ) | Net payments to settle acquired derivatives that include financing elements | | | (43 | ) | | | — | | | | — | | | | — | | | | (43 | ) | Payment for treasury stock | | | — | | | | — | | | | (185 | ) | | | — | | | | (185 | ) | Installment proceeds from sale of noncontrolling interest of subsidiary | | | — | | | | 50 | | | | — | | | | — | | | | 50 | | Payment to settle CSF I CAGR | | | — | | | | (45 | ) | | | — | | | | — | | | | (45 | ) | Proceeds from issuance of common stock, net of issuance costs | | | — | | | | — | | | | 9 | | | | — | | | | 9 | | Proceeds from issuance of long-term debt | | | — | | | | 20 | | | | — | | | | — | | | | 20 | | Payment of deferred debt issuance costs | | | — | | | | (2 | ) | | | (2 | ) | | | — | | | | (4 | ) | Payments of short and long-term debt | | | — | | | | (60 | ) | | | (174 | ) | | | — | | | | (234 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Financing Activities | | | (1,102 | ) | | | 278 | | | | (121 | ) | | | 458 | | | | (487 | ) | | | | | | | | | | | | | | | | | | | | | | Change in cash from discontinued operations | | | — | | | | 43 | | | | — | | | | — | | | | 43 | | Effect of exchange rate changes on cash and cash equivalents | | | — | | | | (1 | ) | | | — | | | | — | | | | (1 | ) | | | | | | | | | | | | | | | | | | | | | | Net Increase/(Decrease) in Cash and Cash Equivalents | | | (2 | ) | | | 39 | | | | 325 | | | | — | | | | 362 | | Cash and Cash Equivalents at Beginning of Period | | | — | | | | 120 | | | | 1,012 | | | | — | | | | 1,132 | | | | | | | | | | | | | | | | | | | | | | | Cash and Cash Equivalents at End of Period | | $ | (2 | ) | | $ | 159 | | | $ | 1,337 | | | $ | — | | | $ | 1,494 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
230
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2007 | | | | | | | | | | | | | | | | | | | | | | | Guarantor
| | | Non-Guarantor
| | | NRG
| | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Operating Revenues | | | | | | | | | | | | | | | | | | | | | Total operating revenues | | $ | 5,614 | | | $ | 375 | | | $ | — | | | $ | — | | | $ | 5,989 | | | | | | | | | | | | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | | | | | | | | | | | Cost of operations | | | 3,130 | | | | 248 | | | | — | | | | — | | | | 3,378 | | Depreciation and amortization | | | 630 | | | | 24 | | | | 4 | | | | — | | | | 658 | | General and administrative | | | 102 | | | | 18 | | | | 189 | | | | — | | | | 309 | | Development costs | | | 66 | | | | 2 | | | | 33 | | | | — | | | | 101 | | | | | | | | | | | | | | | | | | | | | | | Total operating costs and expenses | | | 3,928 | | | | 292 | | | | 226 | | | | — | | | | 4,446 | | | | | | | | | | | | | | | | | | | | | | | Gain/(loss) on sale of assets | | | 18 | | | | — | | | | (1 | ) | | | — | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | Operating Income/(Loss) | | | 1,704 | | | | 83 | | | | (227 | ) | | | — | | | | 1,560 | | | | | | | | | | | | | | | | | | | | | | | Other Income/(Expense) | | | | | | | | | | | | | | | | | | | | | Equity in earnings of consolidated subsidiaries | | | 204 | | | | — | | | | 973 | | | | (1,177 | ) | | | — | | Equity in earnings of unconsolidated affiliates | | | (3 | ) | | | 57 | | | | — | | | | — | | | | 54 | | Gains on sales of equity method investments | | | — | | | | 1 | | | | — | | | | — | | | | 1 | | Other income, net | | | 9 | | | | 13 | | | | 33 | | | | — | | | | 55 | | Refinancing expenses | | | — | | | | — | | | | (35 | ) | | | — | | | | (35 | ) | Interest expense | | | (250 | ) | | | (77 | ) | | | (375 | ) | | | — | | | | (702 | ) | | | | | | | | | | | | | | | | | | | | | | Total other income/(expense) | | | (40 | ) | | | (6 | ) | | | 596 | | | | (1,177 | ) | | | (627 | ) | | | | | | | | | | | | | | | | | | | | | | Income/(Loss) From Continuing Operations Before Income Taxes | | | 1,664 | | | | 77 | | | | 369 | | | | (1,177 | ) | | | 933 | | Income tax expense/(benefit) | | | 576 | | | | 5 | | | | (204 | ) | | | — | | | | 377 | | | | | | | | | | | | | | | | | | | | | | | Income/(Loss) From Continuing Operations | | | 1,088 | | | | 72 | | | | 573 | | | | (1,177 | ) | | | 556 | | Income from discontinued operations, net of income taxes | | | — | | | | 17 | | | | — | | | | — | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | Net Income/(Loss) | | $ | 1,088 | | | $ | 89 | | | $ | 573 | | | $ | (1,177 | ) | | $ | 573 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
231
NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2007 | | | | | | | | | | | | | | | | | | | | | | | | | | Non-
| | | | | | | | | | | | | Guarantor
| | | Guarantor
| | | | | | | | | Consolidated
| | | | Subsidiaries | | | Subsidiaries | | | NRG Energy, Inc. | | | Eliminations(a) | | | Balance | | | | (In millions) | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | | | | | | | | Net income | | $ | 1,088 | | | $ | 89 | | | $ | 573 | | | $ | (1,177 | ) | | $ | 573 | | Adjustments to reconcile net income to net cash provided/(used) by operating activities: | | | | | | | | | | | | | | | | | | | | | Distributions and equity (earnings)/losses of unconsolidated affiliates | | | 101 | | | | (36 | ) | | | (684 | ) | | | 586 | | | | (33 | ) | Depreciation and amortization | | | 630 | | | | 27 | | | | 4 | | | | — | | | | 661 | | Amortization of nuclear fuel | | | 58 | | | | — | | | | — | | | | — | | | | 58 | | Amortization of financing costs and debt discount/premiums | | | — | | | | 19 | | | | 60 | | | | — | | | | 79 | | Amortization of intangibles andout-of-market contracts | | | (160 | ) | | | 4 | | | | — | | | | — | | | | (156 | ) | Amortization of unearned equity compensation | | | — | | | | — | | | | 19 | | | | — | | | | 19 | | (Gain)/loss on sale of assets | | | (18 | ) | | | — | | | | 1 | | | | — | | | | (17 | ) | Impairment charges and asset write downs | | | 9 | | | | — | | | | 11 | | | | — | | | | 20 | | Changes in derivatives | | | 77 | | | | — | | | | — | | | | — | | | | 77 | | Changes in deferred income taxes and liability for unearned tax benefits | | | 112 | | | | (31 | ) | | | 278 | | | | — | | | | 359 | | Gains on sale of equity method investments | | | — | | | | (1 | ) | | | — | | | | — | | | | (1 | ) | Gain on sale of emission allowances | | | (30 | ) | | | (1 | ) | | | — | | | | — | | | | (31 | ) | Change in nuclear decommissioning trust liability | | | 32 | | | | — | | | | — | | | | — | | | | 32 | | Changes in collateral deposits supporting energy risk management activities | | | (125 | ) | | | — | | | | — | | | | — | | | | (125 | ) | Cash provided/(used) by changes in other working capital, net of disposition affects | | | 218 | | | | 96 | | | | (299 | ) | | | (13 | ) | | | 2 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Operating Activities | | | 1,992 | | | | 166 | | | | (37 | ) | | | (604 | ) | | | 1,517 | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | | | | | | | | Intercompany (loans to)/receipts from subsidiaries | | | 655 | | | | — | | | | 2,109 | | | | (2,764 | ) | | | — | | Capital expenditures | | | (389 | ) | | | (84 | ) | | | (8 | ) | | | — | | | | (481 | ) | Decrease in restricted cash, net | | | — | | | | 12 | | | | — | | | | — | | | | 12 | | Decrease in notes receivable | | | — | | | | 34 | | | | — | | | | — | | | | 34 | | Decrease in trust fund balances | | | 19 | | | | — | | | | — | | | | — | | | | 19 | | Purchases of emission allowances | | | (161 | ) | | | — | | | | — | | | | — | | | | (161 | ) | Proceeds from sale of emission allowances | | | 271 | | | | 1 | | | | — | | | | — | | | | 272 | | Investments in nuclear decommissioning trust fund securities | | | (265 | ) | | | — | | | | — | | | | — | | | | (265 | ) | Proceeds from sales of nuclear decommissioning trust fund securities | | | 233 | | | | — | | | | — | | | | — | | | | 233 | | Proceeds from sale of assets | | | — | | | | 2 | | | | — | | | | — | | | | 2 | | Purchase of securities | | | — | | | | — | | | | (49 | ) | | | — | | | | (49 | ) | Proceeds from sale of discontinued operations and assets, net of cash divested | | | 29 | | | | — | | | | 28 | | | | — | | | | 57 | | | | | | | | | | | | | | | | | | | | | | | Net Cash Provided/(Used) by Investing Activities | | | 392 | | | | (35 | ) | | | 2,080 | | | | (2,764 | ) | | | (327 | ) | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | | | | | | | | (Payments)/proceeds from intercompany loans | | | (2,101 | ) | | | (38 | ) | | | (625 | ) | | | 2,764 | | | | — | | Payment from intercompany dividends | | | (302 | ) | | | (302 | ) | | | — | | | | 604 | | | | — | | Payment for dividends to preferred stockholders | | | — | | | | — | | | | (55 | ) | | | — | | | | (55 | ) | Payment for treasury stock | | | — | | | | — | | | | (353 | ) | | | — | | | | (353 | ) | Proceeds from issuance of common stock, net of issuance costs | | | — | | | | — | | | | 7 | | | | — | | | | 7 | | Proceeds from issuance of long-term debt | | | — | | | | — | | | | 1,411 | | | | — | | | | 1,411 | | Payment of deferred debt issuance costs | | | — | | | | — | | | | (5 | ) | | | — | | | | (5 | ) | Payments of short and long-term debt | | | (1 | ) | | | (64 | ) | | | (1,754 | ) | | | — | | | | (1,819 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash (Used)/Provided by Financing Activities | | | (2,404 | ) | | | (404 | ) | | | (1,374 | ) | | | 3,368 | | | | (814 | ) | Change in cash from discontinued operations | | | — | | | | (25 | ) | | | — | | | | — | | | | (25 | ) | Effect of exchange rate changes on cash and cash equivalents | | | — | | | | 4 | | | | — | | | | — | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | Net Increase/(Decrease) in Cash and Cash Equivalents | | | (20 | ) | | | (294 | ) | | | 669 | | | | — | | | | 355 | | Cash and Cash Equivalents at Beginning of Period | | | 20 | | | | 414 | | | | 343 | | | | — | | | | 777 | | | | | | | | | | | | | | | | | | | | | | | Cash and Cash Equivalents at End of Period | | $ | — | | | $ | 120 | | | $ | 1,012 | | | $ | — | | | $ | 1,132 | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | All significant intercompany transactions have been eliminated in consolidation. |
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Schedule of valuation and qualifying accounts disclosure NRG ENERGY, INC.
SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2009, 2008, 2007, and 20062007 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at
| | Charged to
| | Charged to
| | | | | | | Balance at
| | Charged to
| | Charged to
| | | | | | | Beginning of
| | Costs and
| | Other
| | Additions/
| | Balance at
| | | Beginning of
| | Costs and
| | Other
| | | | Balance at
| | | Period | | Expenses | | Accounts | | (Deductions) | | End of Period | | | Period | | Expenses | | Accounts | | Deductions | | End of Period | | | (In millions) | | | (In millions) | | Allowance for doubtful accounts, deducted from accounts receivable | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year ended December 31, 2009 | | | $ | 3 | | | $ | 61 | (a) | | $ | — | | | $ | (35 | )(b) | | $ | 29 | | Year ended December 31, 2008 | | $ | 1 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | 3 | | | $ | 1 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | 3 | | Year ended December 31, 2007 | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | 1 | | Year ended December 31, 2006 | | $ | 2 | | | $ | — | | | $ | — | | | $ | (1 | ) | | $ | 1 | | | Income tax valuation allowance, deducted from deferred tax assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year ended December 31, 2009 | | | $ | 359 | | | $ | (130 | ) | | $ | 4 | | | $ | — | | | $ | 233 | | Year ended December 31, 2008 | | $ | 539 | | | $ | (12 | ) | | $ | (6 | ) | | $ | (162 | ) | | $ | 359 | | | $ | 539 | | | $ | (12 | ) | | $ | (6 | ) | | $ | (162 | ) | | $ | 359 | | Year ended December 31, 2007 | | $ | 581 | | | $ | 6 | | | $ | 8 | | | $ | (56 | ) | | $ | 539 | | | $ | 581 | | | $ | 6 | | | $ | 8 | | | $ | (56 | ) | | $ | 539 | | Year ended December 31, 2006 | | $ | 836 | | | $ | (10 | ) | | $ | (81 | ) | | $ | (164 | ) | | $ | 581 | | |
| | | (a) | | Significant increase reflects acquisition of Reliant Energy in May 2009. | (b) | | Represents principally net amounts charged as uncollectable. |
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SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. NRG Energy, Inc. (Registrant)
David W. Crane Chief Executive Officer
(Principal Executive Officer)
Clint C. Freeland
Chief Financial Officer
(Principal Financial Officer)
James J. Ingoldsby
Chief Accounting Officer
(Principal Accounting Officer)
Date: February 12, 200923, 2010
230234
POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints David W. Crane, J. Andrew Murphy,Michael R. Bramnick, Tanuja M. Dehne and Brian Curci, each or any of them, such person’s true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person’s name, place and stead, in any and all capacities, to sign any and all amendments to this report onForm 10-K, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 12, 2009.23, 2010. | | | | | | | Signature | | Title | | Date | | | | | | /s/ David W. Crane David W. Crane | | President, Chief Executive Officer and Director (Principle Executive Officer) | | February 23, 2010 | | | | | | /s/ David W. Crane Gerald Luterman
David W. CraneGerald Luterman | | President, Chief ExecutiveFinancial Officer and Director (Principle Financial Officer) | | February 12, 200923, 2010 | | | | | | /s/ James J. Ingoldsby James J. Ingoldsby | | Chief Accounting Officer (Principle Accounting Officer) | | February 23, 2010 | | | | | | /s/ Howard E. Cosgrove Howard E. Cosgrove | | Chairman of the Board | | February 23, 2010 | | | | | | /s/ Howard E. Cosgrove
Howard E. CosgroveKirbyjon H. Caldwell | | Chairman of the BoardDirector | | February 12, 200923, 2010 | | | | | | /s/ John F. Chlebowski John F. Chlebowski | | Director | | February 23, 2010 | | | | | | /s/ Lawrence S. Coben Lawrence S. Coben | | Director | | February 23, 2010 | | | | | | /s/ Stephen L. Cropper Stephen L. Cropper | | Director | | February 23, 2010 | | | | | | /s/ William E. Hantke William E. Hantke | | Director | | February 23, 2010 | | | | | | /s/ Paul W. Hobby Paul W. Hobby | | Director | | February 23, 2010 | | | | | | /s/ Kathleen A. McGinty Kathleen A. McGinty | | Director | | February 23, 2010 | | | | | | /s/ Anne C. Schaumburg Anne C. Schaumburg | | Director | | February 23, 2010 |
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| | | | | | | Signature | | Title | | Date | | | | | | /s/ Herbert H. Tate Herbert H. Tate | | Director | | February 23, 2010 | | | | | | /s/ Thomas H. Weidemeyer Thomas H. Weidemeyer | | Director | | February 23, 2010 | | | | | | /s/ John F. Chlebowski
John F. ChlebowskiWalter R. Young | | Director | | February 12, 2009 | | | | | | /s/ Lawrence S. Coben
Lawrence S. Coben | | Director | | February 12, 2009 | | | | | | /s/ Stephen L. Cropper
Stephen L. Cropper | | Director | | February 12, 2009 | | | | | | /s/ William E. Hantke
William E. Hantke | | Director | | February 12, 2009 | | | | | | /s/ Paul W. Hobby
Paul W. Hobby | | Director | | February 12, 2009 | | | | | | /s/ Kathleen A. McGinty
Kathleen A. McGinty | | Director | | February 12, 2009 | | | | | | /s/ Anne C. Schaumburg
Anne C. Schaumburg | | Director | | February 12, 2009 | | | | | | /s/ Herbert H. Tate
Herbert H. Tate | | Director | | February 12, 2009 | | | | | | /s/ Thomas H. Weidemeyer
Thomas H. Weidemeyer | | Director | | February 12, 2009 | | | | | | /s/ Walter R. Young
Walter R. Young | | Director | | February 12, 200923, 2010 |
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EXHIBIT INDEX | | | | | | 2 | .1 | | Third Amended Joint Plan of Reorganization of NRG Energy, Inc., NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company I LLC, and NRGenerating Holdings (No. 23) B.V.(5) | | 2 | .2 | | First Amended Joint Plan of Reorganization of NRG Northeast Generating LLC (and certain of its subsidiaries), NRG South Central Generating (and certain of its subsidiaries) and Berrians I Gas Turbine Power LLC.(5) | | 2 | .3 | | Acquisition Agreement, dated as of September 30, 2005, by and among NRG Energy, Inc., Texas Genco LLC and the Direct and Indirect Owners of Texas Genco LLC.(11) | | 3 | .1 | | Amended and Restated Certificate of Incorporation.(16) | | 3 | .2 | | Amended and Restated By-Laws.(35) | | 3 | .3 | | Certificate of Designation of 4.0% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on December 20, 2004.(7) | | 3 | .4 | | Certificate of Designations of 3.625% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on August 11, 2005.(17) | | 3 | .5 | | Certificate of Designations of 5.75% Mandatory Convertible Preferred Stock, as filed with the Secretary of State of the State of Delaware on January 27, 2006.(19) | | 3 | .6 | | Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 14, 2006.(27) | | 3 | .7 | | Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on February 27, 2008.(36) | | 3 | .8 | | Second Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 8, 2008.(37) | | 3 | .9 | | Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance II LLC, as filed with the Secretary of State of Delaware on August 14, 2006.(27) | | 4 | .1 | | Supplemental Indenture dated as of December 30, 2005, among NRG Energy, Inc., the subsidiary guarantors named on Schedule A thereto and Law Debenture Trust Company of New York, as trustee.(13) | | 4 | .2 | | Amended and Restated Common Agreement among XL Capital Assurance Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law Debenture Trust Company of New York, as Trustee, The Bank of New York, as Collateral Agent, NRG Peaker Finance Company LLC and each Project Company Party thereto dated as of January 6, 2004, together with Annex A to the Common Agreement.(2) | | 4 | .3 | | Amended and Restated Security Deposit Agreement among NRG Peaker Finance Company, LLC and each Project Company party thereto, and the Bank of New York, as Collateral Agent and Depositary Agent, dated as of January 6, 2004.(2) | | 4 | .4 | | NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of New York, as Collateral Agent, dated as of January 6, 2004.(2) | | 4 | .5 | | Indenture dated June 18, 2002, between NRG Peaker Finance Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc., as Insurer, and Law Debenture Trust Company, as Successor Trustee to the Bank of New York.(3) | | 4 | .6 | | Registration Rights Agreement, dated December 21, 2004, by and among NRG Energy, Inc., Citigroup Global Markets Inc. and Deutsche Bank Securities Inc.(6) | | 4 | .7 | | Specimen of Certificate representing common stock of NRG Energy, Inc.(26) | | 4 | .8 | | Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law Debenture Trust Company of New York.(19) | | 4 | .9 | | First Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(20) |
| | | | | | | | | | | 2 | .1 | | Third Amended Joint Plan of Reorganization of NRG Energy, Inc., NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company I LLC, and NRGenerating Holdings (No. 23) B.V.(5) | | | | | | | 2 | .2 | | First Amended Joint Plan of Reorganization of NRG Northeast Generating LLC (and certain of its subsidiaries), NRG South Central Generating (and certain of its subsidiaries) and Berrians I Gas Turbine Power LLC.(5) | | | | | | | 2 | .3 | | Acquisition Agreement, dated as of September 30, 2005, by and among NRG Energy, Inc., Texas Genco LLC and the Direct and Indirect Owners of Texas Genco LLC.(11) | | | | | | | 3 | .1 | | Amended and Restated Certificate of Incorporation.(45) | | | | | | | 3 | .2 | | Amended and Restated By-Laws.(47) | | | | | | | 3 | .3 | | Certificate of Designations of 3.625% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on August 11, 2005.(17) | | | | | | | 3 | .4 | | Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 14, 2006.(27) | | | | | | | 3 | .5 | | Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on February 27, 2008.(36) | | | | | | | 3 | .6 | | Second Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 8, 2008.(37) | | | | | | | 4 | .1 | | Supplemental Indenture dated as of December 30, 2005, among NRG Energy, Inc., the subsidiary guarantors named on Schedule A thereto and Law Debenture Trust Company of New York, as trustee.(13) | | | | | | | 4 | .2 | | Amended and Restated Common Agreement among XL Capital Assurance Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law Debenture Trust Company of New York, as Trustee, The Bank of New York, as Collateral Agent, NRG Peaker Finance Company LLC and each Project Company Party thereto dated as of January 6, 2004, together with Annex A to the Common Agreement.(2) | | | | | | | 4 | .3 | | Amended and Restated Security Deposit Agreement among NRG Peaker Finance Company, LLC and each Project Company party thereto, and the Bank of New York, as Collateral Agent and Depositary Agent, dated as of January 6, 2004.(2) | | | | | | | 4 | .4 | | NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of New York, as Collateral Agent, dated as of January 6, 2004.(2) | | | | | | | 4 | .5 | | Indenture dated June 18, 2002, between NRG Peaker Finance Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc., as Insurer, and Law Debenture Trust Company, as Successor Trustee to the Bank of New York.(3) | | | | | | | 4 | .6 | | Specimen of Certificate representing common stock of NRG Energy, Inc.(26) | | | | | | | 4 | .7 | | Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law Debenture Trust Company of New York.(19) | | | | | | | 4 | .8 | | First Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(20) | | | | | | | 4 | .9 | | Second Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(20) |
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| | | | | | 4 | .10 | | Second Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(20) | | 4 | .11 | | Form of 7.250% Senior Note due 2014.(20) | | 4 | .12 | | Form of 7.375% Senior Note due 2016.(20) | | 4 | .13 | | Third Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(22) | | 4 | .14 | | Fourth Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(22) | | 4 | .15 | | Fifth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(23) | | 4 | .16 | | Sixth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(23) | | 4 | .17 | | Seventh Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(28) | | 4 | .18 | | Eighth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(28) | | 4 | .19 | | Ninth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(29) | | 4 | .20 | | Tenth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(33) | | 4 | .21 | | Eleventh Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(33) | | 4 | .22 | | Twelfth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(33) | | 4 | .23 | | Thirteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(34) | | 4 | .24 | | Fourteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(34) | | 4 | .25 | | Fifteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(34) | | 4 | .26 | | Form of 7.375% Senior Note due 2017.(29) | | 10 | .1 | | Note Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc. and each of the purchasers named therein.(4) | | 10 | .2 | | Master Shelf and Revolving Credit Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate, which becomes party thereto.(4) | | 10 | .3* | | Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.(15) |
| | | | | | | | | | | 4 | .10 | | Form of 7.250% Senior Note due 2014.(20) | | | | | | | 4 | .11 | | Form of 7.375% Senior Note due 2016.(20) | | | | | | | 4 | .12 | | Form of 7.375% Senior Note due 2017.(29) | | | | | | | 4 | .13 | | Form of 8.5% Senior Note due 2019.(42) | | | | | | | 4 | .14 | | Third Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(22) | | | | | | | 4 | .15 | | Fourth Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(22) | | | | | | | 4 | .16 | | Fifth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(23) | | | | | | | 4 | .17 | | Sixth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(23) | | | | | | | 4 | .18 | | Seventh Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(28) | | | | | | | 4 | .19 | | Eighth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(28) | | | | | | | 4 | .20 | | Ninth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(29) | | | | | | | 4 | .21 | | Tenth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(33) | | | | | | | 4 | .22 | | Eleventh Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(33) | | | | | | | 4 | .23 | | Twelfth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(33) | | | | | | | 4 | .24 | | Thirteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(34) | | | | | | | 4 | .25 | | Fourteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(34) | | | | | | | 4 | .26 | | Fifteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(34) | | | | | | | 4 | .27 | | Sixteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(40) |
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| | | | | | 10 | .4* | | Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Directors.(15) | | 10 | .5* | | Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.(8) | | 10 | .6* | | Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.(8) | | 10 | .7* | | Form of NRG Energy, Inc. Long Term Incentive Plan Performance Unit Agreement.(15) | | 10 | .8* | | Annual Incentive Plan for Designated Corporate Officers.(9) | | 10 | .9 | | Railroad Car Full Service Master Leasing Agreement, dated as of February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(15) | | 10 | .10 | | Purchase Agreement (West Coast Power) dated as of December 27, 2005, by and among NRG Energy, Inc., NRG West Coast LLC (Buyer), DPC II Inc. (Seller) and Dynegy, Inc.(14) | | 10 | .11 | | Purchase Agreement (Rocky Road Power), dated as of December 27, 2005, by and among Termo Santander Holding, L.L.C.(Buyer), Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG Energy, Inc.(14) | | 10 | .12 | | Stock Purchase Agreement, dated as of August 10, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(17) | | 10 | .13 | | Agreement with respect to the Stock Purchase Agreement, dated December 19, 2008, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(1) | | 10 | .14 | | Investor Rights Agreement, dated as of February 2, 2006, by and among NRG Energy, Inc. and Certain Stockholders of NRG Energy, Inc. set forth therein.(21) | | 10 | .15† | | Terms and Conditions of Sale, dated as of October 5, 2005, between Texas Genco II LP and Freight Car America, Inc., (including the Proposal Letter and Amendment thereto).(25) | | 10 | .16* | | Amended and Restated Employment Agreement, dated December 4, 2008, between NRG Energy, Inc. and David Crane.(1) | | 10 | .17* | | CFO Compensation Table.(38) | | 10 | .18 | | Limited Liability Company Agreement of NRG Common Stock Finance I LLC.(27) | | 10 | .19 | | Limited Liability Company Agreement of NRG Common Stock Finance II LLC.(27) | | 10 | .20 | | Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC.(27) | | 10 | .21 | | Amendment Agreement, dated February 27, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(36) | | 10 | .22 | | Amendment Agreement, dated August 8, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | | 10 | .23 | | Amendment Agreement, dated December 19, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | | 10 | .24 | | Agreement with respect to Note Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | | 10 | .25 | | Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC, as agent.(27) | | 10 | .26 | | Amendment Agreement, dated December 19, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance II LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | | 10 | .27 | | Agreement with respect to Note Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance II LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | | 10 | .28 | | Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27) | | 10 | .29 | | Preferred Interest Amendment Agreement, dated February 27, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(36) | | 10 | .30 | | Preferred Interest Amendment Agreement, dated August 8, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | | 10 | .31 | | Preferred Interest Amendment Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) |
| | | | | | | | | | | 4 | .28 | | Seventeenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(40) | | | | | | | 4 | .29 | | Eighteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(40) | | | | | | | 4 | .30 | | Nineteenth Supplemental Indenture, dated May 8, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(41) | | | | | | | 4 | .31 | | Twentieth Supplemental Indenture, dated May 8, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(41) | | | | | | | 4 | .32 | | Twenty-First Supplemental Indenture, dated May 8, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(41) | | | | | | | 4 | .33 | | Twenty-Second Supplemental Indenture, dated June 5, 2009, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 8.5% Senior Notes due 2019.(42) | | | | | | | 4 | .34 | | Twenty-Third Supplemental Indenture, dated July 14, 2009, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 8.5% Senior Notes due 2019. (44). | | | | | | | 4 | .35 | | Twenty-Fourth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(46) | | | | | | | 4 | .36 | | Twenty-Fifth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(46). | | | | | | | 4 | .37 | | Twenty-Sixth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(46). | | | | | | | 4 | .38 | | Twenty-Seventh Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 8.5% Senior Notes due 2019. (46). | | | | | | | 10 | .1 | | Note Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc. and each of the purchasers named therein.(4) | | | | | | | 10 | .2 | | Master Shelf and Revolving Credit Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate, which becomes party thereto.(4) | | | | | | | 10 | .3* | | Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.(15) | | | | | | | 10 | .4* | | Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Directors.(15) | | | | | | | 10 | .5* | | Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.(8) | | | | | | | 10 | .6* | | Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.(8) | | | | | | | 10 | .7* | | Form of NRG Energy, Inc. Long Term Incentive Plan Performance Unit Agreement.(1) | | | | | | | 10 | .8* | | Annual Incentive Plan for Designated Corporate Officers.(43) |
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| | | | | | 10 | .32 | | Agreement with respect to Preferred Interest Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | | 10 | .33 | | Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27) | | 10 | .34 | | Preferred Interest Amendment Agreement, dated December 19, 2008, by and among NRG Common Stock Finance II LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | | 10 | .35 | | Agreement with respect to Preferred Interest Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance II LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | | 10 | .36 | | Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance I LLC.(27) | | 10 | .37 | | Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance II LLC.(27) | | 10 | .38 | | Second Amended and Restated Credit Agreement, dated June 8, 2007, by and among NRG Energy, Inc., the lenders party thereto, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Citicorp North America Inc. and Credit Suisse.(32) | | 10 | .39* | | Amended and Restated Long-Term Incentive Plan, dated December 8, 2006.(31) | | 10 | .40* | | NRG Energy, Inc. ExecutiveChange-in-Control and General Severance Agreement, dated December 9, 2008.(1) | | 10 | .41† | | Amended and Restated Contribution Agreement (NRG), dated March 25, 2008, by and among Texas Genco Holdings, Inc., NRG South Texas LP and NRG Nuclear Development Company LLC and Certain Subsidiaries Thereof.(36) | | 10 | .42† | | Contribution Agreement (Toshiba), dated February 29, 2008, by and between Toshiba Corporation and NRG Nuclear Development Company LLC.(36) | | 10 | .43† | | Multi-Unit Agreement, dated February 29, 2008, by and among Toshiba Corporation, NRG Nuclear Development Company LLC and NRG Energy, Inc.(36) | | 10 | .44† | | Amended and Restated Operating Agreement of Nuclear Innovation North America LLC, dated May 1, 2008(36) | | 12 | .1 | | NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges.(1) | | 12 | .2 | | NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements.(1) | | 21 | | | Subsidiaries of NRG Energy. Inc.(1) | | 23 | .1 | | Consent of KPMG LLP.(1) | | 31 | .1 | | Rule 13a-14(a)/15d-14(a) certification of David W. Crane.(1) | | 31 | .2 | | Rule 13a-14(a)/15d-14(a) certification of Clint C. Freeland.(1) | | 31 | .3 | | Rule 13a-14(a)/15d-14(a) certification of James J. Ingoldsby.(1) | | 32 | | | Section 1350 Certification.(1) |
| | | | | | | | | | | 10 | .9 | | Railroad Car Full Service Master Leasing Agreement, dated as of February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(15) | | | | | | | 10 | .10 | | Purchase Agreement (West Coast Power) dated as of December 27, 2005, by and among NRG Energy, Inc., NRG West Coast LLC (Buyer), DPC II Inc. (Seller) and Dynegy, Inc.(14) | | | | | | | 10 | .11 | | Purchase Agreement (Rocky Road Power), dated as of December 27, 2005, by and among Termo Santander Holding, L.L.C.(Buyer), Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG Energy, Inc.(14) | | | | | | | 10 | .12 | | Stock Purchase Agreement, dated as of August 10, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(17) | | | | | | | 10 | .13 | | Agreement with respect to the Stock Purchase Agreement, dated December 19, 2008, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(37) | | | | | | | 10 | .14 | | Investor Rights Agreement, dated as of February 2, 2006, by and among NRG Energy, Inc. and Certain Stockholders of NRG Energy, Inc. set forth therein.(21) | | | | | | | 10 | .15† | | Terms and Conditions of Sale, dated as of October 5, 2005, between Texas Genco II LP and Freight Car America, Inc., (including the Proposal Letter and Amendment thereto).(25) | | | | | | | 10 | .16* | | Amended and Restated Employment Agreement, dated December 4, 2008, between NRG Energy, Inc. and David Crane.(37) | | | | | | | 10 | .17* | | CEO Compensation Table.(48) | | | | | | | 10 | .18 | | Limited Liability Company Agreement of NRG Common Stock Finance I LLC.(27) | | | | | | | 10 | .19 | | Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC.(27) | | | | | | | 10 | .20 | | Amendment Agreement, dated February 27, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(36) | | | | | | | 10 | .21 | | Amendment Agreement, dated August 8, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | | | | | | | 10 | .22 | | Amendment Agreement, dated December 19, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | | | | | | | 10 | .23 | | Agreement with respect to Note Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | | | | | | | 10 | .24 | | Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27) | | | | | | | 10 | .25 | | Preferred Interest Amendment Agreement, dated February 27, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(36) | | | | | | | 10 | .26 | | Preferred Interest Amendment Agreement, dated August 8, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | | | | | | | 10 | .27 | | Preferred Interest Amendment Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | | | | | | | 10 | .28 | | Agreement with respect to Preferred Interest Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) |
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| | | | | | | | | | | 10 | .29 | | Second Amended and Restated Credit Agreement, dated June 8, 2007, by and among NRG Energy, Inc., the lenders party thereto, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Citicorp North America Inc. and Credit Suisse.(32) | | | | | | | 10 | .30* | | Amended and Restated Long-Term Incentive Plan(43) | | | | | | | 10 | .31* | | NRG Energy, Inc. ExecutiveChange-in-Control and General Severance Agreement, dated December 9, 2008.(37) | | | | | | | 10 | .32† | | Amended and Restated Contribution Agreement (NRG), dated March 25, 2008, by and among Texas Genco Holdings, Inc., NRG South Texas LP and NRG Nuclear Development Company LLC and Certain Subsidiaries Thereof.(36) | | | | | | | 10 | .33† | | Contribution Agreement (Toshiba), dated February 29, 2008, by and between Toshiba Corporation and NRG Nuclear Development Company LLC.(36) | | | | | | | 10 | .34† | | Multi-Unit Agreement, dated February 29, 2008, by and among Toshiba Corporation, NRG Nuclear Development Company LLC and NRG Energy, Inc.(36) | | | | | | | 10 | .35† | | Amended and Restated Operating Agreement of Nuclear Innovation North America LLC, dated May 1, 2008(36) | | | | | | | 10 | .36 | | Credit Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America Investments LLC, NINA Texas 3 LLC and NINA Texas 4 LLC, as Borrowers and Toshiba America Nuclear Energy Corporation, as Administrative Agent and as Collateral Agent.(38) | | | | | | | 10 | .37† | | LLC Membership Purchase Agreement between Reliant Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.(39) | | | | | | | 12 | .1 | | NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges.(1) | | | | | | | 12 | .2 | | NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements.(1) | | | | | | | 21 | .1 | | Subsidiaries of NRG Energy. Inc.(1) | | | | | | | 23 | .1 | | Consent of KPMG LLP.(1) | | | | | | | 31 | .1 | | Rule 13a-14(a)/15d-14(a) certification of David W. Crane.(1) | | | | | | | 31 | .2 | | Rule 13a-14(a)/15d-14(a) certification of Gerald Luterman.(1) | | | | | | | 31 | .3 | | Rule 13a-14(a)/15d-14(a) certification of James J. Ingoldsby.(1) | | | | | | | 32 | | | Section 1350 Certification.(1) | | | | | | | 101 | .INS | | XBRL Instance Document(1) | | | | | | | 101 | .SCH | | XBRL Taxonomy Extension Schema(1) | | | | | | | 101 | .CAL | | XBRL Taxonomy Extension Calculation Linkbase(1) | | | | | | | 101 | .DEF | | XBRL Taxonomy Extension Definition Linkbase(1) | | | | | | | 101 | .LAB | | XBRL Taxonomy Extension Label Linkbase(1) | | | | | | | 101 | .PRE | | XBRL Taxonomy Extension Presentation Linkbase(1) |
| | | * | | Exhibit relates to compensation arrangements. | | † | | Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of the Securities and Exchange Commission pursuant toRule 24b-2 under the Securities Exchange Act of 1934, as amended. | | (1) | | Filed herewith. | | (2) | | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 16, 2004. | | (3) | | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 31, 2003. |
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| | | (4) | | Incorporated herein by reference to NRG Energy Inc.’s Registration Statement onForm S-1, as amended, RegistrationNo.333-33397. | | (5) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 19, 2003. |
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| | | (6) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 27, 2004. | | (7) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 27, 2004. | | (8) | | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended September 30, 2004. | | (9)(7) | | Incorporated herein by reference to NRG Energy, Inc.’s 2004 proxy statement on Schedule 14AScheduleb14A filed on July 12, 2004. | | (10)(8) | | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended March 31, 2004. | | (11)(9) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on October 3, 2005. | | (12)(10) | | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended June 30, 2005. | | (13)(11) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on January 4, 2006. | | (14)(12) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 28, 2005. | | (15)(13) | | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 30, 2005. | | (16)(14) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 24, 2005. | | (17)(15) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 11, 2005. | | (18)(16) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 3, 2005. | | (19)(17) | | Incorporated herein by reference to NRG Energy, Inc.’sForm 8-A filed on January 27, 2006. | | (20)(18) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on February 6, 2006. | | (21)(19) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on February 8, 2006. | | (22)(20) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on March 16, 2006. | | (23)(21) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 3, 2006. | | (24)(22) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 4, 2006. | | (25)(23) | | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 7, 2006. | | (26)(24) | | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on August 4, 2006. | | (27)(25) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 10, 2006. | | (28)(26) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 14, 2006. | | (29)(27) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 27, 2006. | | (30)(28) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 26, 2007. | | (31)(29) | | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on May 2, 2007. | | (32)(30) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on June 13, 2007. |
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| | | (33)(31) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on July 20, 2007. | | (34)(32) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on September 4, 2007. | | (35)(33) | | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on February 28, 2008. | | (36)(34) | | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on May 1, 2008. | | (37)(35) | | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on October 30, 2008. | | (38)(36) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 9, 2008. | (37) | | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on February 12, 2009. | (38) | | Incorporated herein by reference to NRG Energy Inc’s current report onForm 8-K filed on February 27, 2009. | (39) | | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on April 30, 2009. | (40) | | Incorporated herein by reference to NRG Energy, Inc’s current report onForm 8-K filed on May 4, 2009. | (41) | | Incorporated herein by reference to NRG Energy, Inc’s current report onForm 8-K filed on May 14, 2009. | (42) | | Incorporated herein by reference to NRG Energy, Inc’s current report onForm 8-K filed on June 5, 2009. | (43) | | Incorporated herein by reference to NRG Energy, Inc.’s 2009 proxy statement on Schedule 14A filed on June 16, 2009. | (44) | | Incorporated herein by reference to NRG Energy, Inc’s current report onForm 8-K filed on July 15, 2009. | (45) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 4, 2009. | (46) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on October 6, 2009. | (47) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on October 21, 2009. | (48) | | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 9, 2009. |
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