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NRG Energy NRG W
June 01, 2008 - 3:58pm EST by
vincent975
2008 2009
Price: 41.59 EPS
Shares Out. (in M): 0 P/E
Market Cap (in $M): 9,812 P/FCF
Net Debt (in $M): 0 EBIT 0 0
TEV (in $M): 0 TEV/EBIT

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Description

This note will discuss my views on standalone NRG. In mid-May, NRG offered 0.534 shares of NRG stock for each share of Calpine. It is my opinion that NRG is overpaying for Calpine, especially considering the use of its undervalued stock as currency. However, in the event a “reasonable” transaction is consummated, NRG’s shares still offer compelling value.
 
NRG’s management has a history of being investor-friendly. Stock buybacks and investments in high ROIC projects, along with improved power markets led to significant share appreciation. As such, this offer is unusual based on management’s past behavior. It is my view that NRG should remain a standalone company. On Friday, Calpine rejected NRG’s proposed takeover offer. In response, NRG’s CEO indicated that he does not plan to raise his bid. This gives me confidence that he will act with discipline. 
 
Avenues of value creation for independent NRG:
  1. Increased share buybacks per amending the restricted payment test in the bond indenture or other means.
  2. Resetting below-market hedges in Texas and the Northeast leading to a material earnings improvement.
  3. Sales of non-earning assets. Several of NRG’s assets generate limited cash flow, yet have asset value.
  4. Project development.
Pro forma for the $23/share offer for Calpine, the combined entity is still undervalued (see appendix). On an EBITDA basis, the transaction values Calpine at 12.0x, 11.0x and 9.6x 2008, 2009 and “open” (unhedged – current power prices). Using per kW multiples, Calpine is valued at $830/kW, $700/kW (ex. geysers) and $810/kW (ex. geysers and SERC/SPP asset valuations). On an “open” basis if all hedges (ex. NRG South Central) are reset to market values, NRG will generate nearly double the EBITDA as Calpine, yet the purchase price implies that Calpine is the more valuable entity.
 
*Potential CO2 legislation should reduce the aforementioned Calpine EBITDA multiples by slightly over 0.5x. 
 
NRG Quick Summary:
NRG is a blue chip merchant power producer trading at 12.0x “hedged” free cash flow and <8x “open” free cash flow (fully taxed and including $15/ton for carbon – no allocations). The company also trades at a significant discount to replacement cost, which continues to increase as commodities and engineering and procurement costs rise. Investors mistakenly value the business on current “hedged” cash flows after factoring in stringent CO2 legislation, and without taking into account the rapid rise in natural gas prices, increased replacement costs and continued tightening of supply and demand.
 
*My “open” cash flow calculation does not assume the South Central contracts are reset.
**The natural gas price used is an average of 2009 and 2010 strip.
 
I expect the company to continue to grow EBITDA and free cash flow, especially as below-market hedges roll-off. The company’s non-nuclear development portfolio should provide additional value accretion with low risk. As a US infrastructure asset with good growth prospects, a 13x “open” free cash flow (after factoring in the cost of exiting below-market hedges) does not seem unreasonable. This implies a share price of over $70. Hedges, while below-market provide a margin of safety and virtually guarantee a 9% FCF yield (pre-growth capital spending).
 
Company Overview:
NRG’s global portfolio is comprised of 191 generation units at 49 power plants for total capacity of 24,115 MW (23,960 MW pro forma for ITISA sale in 1Q 2008). MW by region: Texas (45%), Northeast (29%), South Central (12%), West (9%) and International (5%). MW by fuel type: Natural Gas (44%), Coal (36%), Oil (15%) and Nuclear (5%). See 10K for a complete list of plants by region and fuel type. The bulk of NRG’s earnings are generated by its coal and nuclear plants.
 
The Texas operations consist of 10,805 MW of coal, nuclear and natural gas generation primarily serving the Houston load zone. This region represented almost 62% of NRG’s 2007 EBITDA of $2.2 BN. Baseload coal/lignite (4,150 MW – 38%) and nuclear power (1,175 – 11%) generate the bulk of the earnings. The coal/lignite plants are relatively new with in-service dates ranging from 1977-1986. Existing pollution control equipment and the use of low sulfur Powder River Basin coal at its WA Parish plant reduces SO2 and NOx emissions. These plants along with the South Texas nuclear plant are the crown jewels of the portfolio. The natural gas plants (5,480 MW – 51%) are fairly old and inefficient, but they remain a good call option on tightening reserve margins. Repowerings could also reduce the heat rates at several of these facilities. 
 
The Northeast region is NRG’s second largest asset base (6,890 MW) with oil (3,690 MW – 53%), natural gas (1,420 MW – 20%) and coal-fired plants (1,870 – 27%) comprising 26% of company EBITDA. These units are older like many Northeast plants and require environmental spending, but many operate near load centers in capacity constrained regions, such as New York City (NYISO), Southwest Connecticut (ISO-NE) and the Delmarva Peninsula (PJM).
 
The South Central plants consist of 2,850 MW of coal and natural gas units. The Big Cajun II coal plant (1,490 MW) generates most of this region’s EBITDA, which represents 5% of NRG’s total. This region lacks a regional transmission organization and remains a bilateral market where NRG operates almost like a regulated utility with long term contractual agreements for power and other ancillary services. These contracts provide for a recovery of environmental capital expenditures and future CO2 costs.
 
The West Coast plants (2,130 MW) are primarily older natural gas units serving a reliability function in San Diego County. This region generated 2% of NRG’s EBITDA. Most of these plants are tolled near-term resulting in stable cash flow. Existing emission allowances and site space provide brownfield opportunities with other excess land available for non-power uses (estimated value >$300 MM).
 
NRG’s other businesses generate 6% of EBITDA. These non-core assets should be sold in the medium-term. The international assets include interests in a coal plant in Australia, generating and mining assets in Germany and a hydroelectric facility in Brazil. The Brazilian asset was recently sold for $348 MM. The Australian facility was sold for $209 MM, but NRG’s joint venture partners have withheld consent, which has delayed the closing of the transaction. The remaining assets are thermal and chilled water businesses providing steam heating to 525 customers and chilled water to 100 customers in five US cities.
 
Reserve Margins
NRG is levered to tightening power markets, specifically Texas, New York, New England, Delaware and California. Declining reserve margins should drive heat rates upward as more inefficient plants are required to serve incremental load requirements.
 
ERCOT estimates that Texas reserve margins will run 13.8%, 16.5%, 17.3%, 15.0%, 14.5% and 12.3% in 2008-2013. Reserve margins increase in 2009 and 2010 as TXU’s Sandow 5 and Oak Grove 1 & 2 units come online. Wind additions from western Texas are a possibility, but that entails new transmission, which adds significant uncertainty. Beyond 2012, there should be limited (reliable) low cost power additions until NRG’s nuclear units come online in 2015-2016. Most likely, new nuclear will be delayed. Given TXU’s new coal units and other plant additions, I do not expect a material improvement in heat rates until after 2010.
 
The ERCOT region is one of the faster growing power markets in the US, especially considering the commodities boom the state is now enjoying. Previous demand growth estimates by ERCOT proved overly conservative (i.e. 2006 peak load hit levels not expected until 2008). Additionally, the recent surge in power prices (see WSJ 5/30/08 – “Power-Price Surge Strikes Texas”) suggests supply may not be as abundant as previously estimated.
 
NRG’s operations in the Northeast are located in three control areas: ISO-NE, NYISO and PJM. In New England, reserve margins are expected to be 21.0%, 18.5%, 22.2%, 19.8% and 17.0% in 2008-2012. These estimates capture New England as a whole, while NRG’s plants are predominantly in Southwest Connecticut, an area with lower reserve margins. However, since NRG’s New England plants are old and inefficient, the bulk of any earnings improvement will come from higher capacity prices or new builds/repowerings. In New York (East), reserve margins are expected to be 15.2%, 16.1%, 15.8%, 14.3% and 13.2% in 2008-2012. However, several of NRG’s plants are in NYC, which is even tighter. A few of NRG’s plants reside in PJM. Reserve margins in PJM (East) are projected to be 15.1%, 13.5%, 12.0%, 11.9% and 10.2% in 2008-2012. In the near-to-medium term, capacity prices and/or heat rates in the Northeast should increase.
 
I will not spend any time on NRG’s South Central plants given NRG operates more like a regulated utility in that region. As the company’s contracts expire, new agreements should incorporate higher gas prices. Similarly, the West region is largely contracted (tolled). Reserve margins are tight in California, especially the southern region, so these plants have good locational value leading to brownfield and repowering opportunities.
 
Capital Structure
Revolver                                $0  
Term Loan                             $2,673
Capital Leases                        $181
7.25% Sr Nts (2014)              $1,200
7.375% Sr Nts (2016)            $2,400
7.375% Sr Nts (2017)            $1,100
Non-Recourse Debt                $373
CSF Obligations                      $428    
Total Debt                               $8,355                   
Cash                                      ($1,078)
Environmental                          $453
NOLs                                     ($555)
 
Equity Market Cap (FD)         $12,157 
Enterprise Value                      $19,330
 
*Cash is pro forma for sale of ITISA, but not for the expected return of collateral by year-end ($130-$140 MM).
*Environmental is a post-tax discounted figure. Not pro forma for recently announced delays.
*Equity market capitalization assumes conversion of preferred shares and stock options.
 
Hedges
Baseload                Natgas*                 Fuel                        $1 ?Gas                  1 ?HR
2008        97%                   $7.50                    100%                       $4/-4                       $80
2009        85%                   $7.70                     97%                        $64/-62                   $277
2010        65%                   $7.49                     64%                        $168/-166               $480
2011        61%                   $7.03                     59%                        $187/-185               $512
2012        34%                   $6.70                     53%                        $322/-322               $506
2013        25%                   NA                        23%                        $366/-366               $505
 
NRG’s hedges protect near-term EBITDA downside in the event natural gas falls, while limiting the company’s upside to escalating prices. In essence, near-term cash flow is very bond-like. As the company’s below-market hedges roll-off, NRG’s true earnings power should become more visible to the market. On the fuel side, the company’s coal costs have not risen as much as other power producers due to hedges and NRG’s Powder River Basin (PRB) and lignite exposure, which is not as volatile and as subject to exports like eastern coal. 
 
*Natgas hedge prices per 10K, excluding South Central. As NRG increased its hedges at higher prices in 1Q, the new numbers should be higher.
**Coal requirements: PRB 8800 (20%), PRB 8400 (54%), lignite (20%) and other (6%).
 
Earnings
For 2008, NRG guided to $2.2 BN of EBITDA. FCF before growth capital expenditures (repowerings and brownfields) and environmental spending should be around $3.45/share. Based on NRG’s 2009 hedges, the forward gas curve implies over $300 MM of pre-tax earnings pick up just from higher natgas prices. As such, my 2008 FCF/share increases to ~$4.10. If NRG resets its hedges like it did after it acquired Texas Genco, EBITDA and FCF would go up significantly. Assuming the Texas and Northeast baseload hedges are reset via additional debt, the company’s coal contracts are marked to reflect current prices and $15/ton is added for carbon costs, I still calculate nearly $5.50 of FCF/share based on the NYMEX Henry Hub natgas futures curve (average of 2009-2010). Even if natural gas falls to $9, FCF is still $4.00/share (pro forma for $15 CO2 & higher coal prices).
 
*FCF is after-tax. I assume NOLs and environmental spending offsets each other. Out-of-the-money hedges are reset via debt issuances.
**The unwinding of NRG’s underwater hedges (Texas and NE) would generate a sizable NOL. No value has been assigned to this.
***No value assigned to NRG’s in-the-money coal hedges.
****No value assigned for NRG’s SOx and NOx credits after environmental capital spending is completed.
*****No value assigned to non-earning assets (nuclear JV, Texas gas plants, excess land in California, etc.)
 
Valuation
Many investors assume power plants are capital intensive and highly cyclical. Unlike refineries or railroads, a power plant does not have overly burdensome maintenance capital expenditures. Environmental capital spending is always a risk and the cost to build a new plant is certainly expensive, but maintenance capital expenditures are significantly lower than depreciation. In NRG’s case, maintenance capex is less than 40% of depreciation.
 
I believe the most appropriate power valuation metric is “open” free cash flow (the liability from underwater hedges is treated like debt). The other metrics I use are replacement cost, EBITDA and unlevered FCF.  NRG trades at a discount to competitors using the metrics, although I believe most of the industry is undervalued. Based on the earnings noted above 2008, 2009 and “open” FCF multiples are 12.0x, 10.2x and <8x.
 
Other sources of value include non-earning assets. These consist of NRG’s development portfolio, specifically the STP nuclear brownfield (Toshiba JV should have some value), the wind farms, natural gas plants (CA & TX), other coal/coke (LA & TX) units and excess land in California valued in the $300 MM area. Additionally, many of NRG’s “older” assets are located in capacity constrained areas, which have locational value, albeit limited current profitability. These plants could be repowered or brownfield units could be added. NRG is engaging in some of this per its “Repowering NRG” agenda. Another pocket of value is NRG’s natural gas fleet in Texas. These plants could probably be sold for >$2 BN ($365/kW), despite generating virtually no EBITDA.
 
*Analysts are valuing the nuclear JV at >$3/share, but cost overruns are always a risk. At the very least, the site should have $1-$2 of value.
 
New Build Costs
Another metric that is important to highlight is replacement cost. Compared to last year, new build costs are up around 10%. Per a Citibank survey of industry expects, these costs are expected to continue to increase by 10% for the next three years. Also, the significant build times ensure longer mid and peak earnings cycles. Dynegy indicates replacement costs are in this range (1Q presentation).    
 

Solar-      Concentrate                          $4,600-6,800/kW (3-5 years)                                                                                              

                Photovoltaic                         $8,000-12,000/kW (3-5 years)

Wind                                                      $2,000-2,200/kW (3-5 years)

Gas simple cycle                                   $550-$900/kW (3-6 years)

Gas combined cycle                             $800-$1,200/kW (4-6 years)

Pulverized super critical coal              $3,000-$4,200/kW (7-10 years)

IGCC & IGCC with CO2 capture        $3,800-$4,900/kW (8-10 years)

Nuclear                                                  $4,900-$6,000/kW (10-15 years)

 
Applying the low-end of these multiples to NRG’s existing assets and assuming all natural gas and oil plants are akin to single cycle gas plants results in a replacement cost of almost $100/share. Considering the age of many of NRG’s non-coal and nuclear assets and their limited cash generation, this analysis might be too aggressive. Excluding the natural gas and oil assets and valuing the coal plants at $2,500/kW and the nuclear at $3,000/kW still leads to a low $50s share price.
 
A good comparable to NRG is the TXU LBO given the significant ERCOT concentration and huge bet on natural gas prices. The TXU transaction was completed at an estimated 2,630/kW for the baseload plants (coal and nuclear plus new builds). Given the run in natural gas, these plants have certainly appreciated (bonds issued at a discount now trade over par).
 
*Dynegy sold a portion of its Plum Point coal plant in Arkansas at an implied $2,800/kW
**Another data point is the sale of the Ravenswood plant in NYC for $1,169/kW.  Applying $1,000 to NRG’s in-city portfolio results in another $1.4 BN of value, or almost $5/share.

Conclusion
Power companies represent an excellent asset class. There is no Wal-Mart threat, no international low-cost competition and demand is fairly inelastic. Supply is difficult to add, especially considering higher costs, long lead times, environmental concerns and NIMBY (Not in My Back Yard).
 
A company like NRG should be a good cash generator. Rising replacement costs will raise reinvestment thresholds.  Public outcry against coal and long lead cycles for nuclear power will limit the addition of low cost generation, thereby extending the mid and peak power cycles. Higher cash earnings should become more visible as hedges roll-off or are reset. In the event market-clearing heat rates remain at current levels and natural gas falls, NRG’s hedges should limit the impact with FCF/share of over $4 in 2009.
 
Risks
  1. Completing the Calpine transaction as structured, or offering up more value. NRG is overpaying, but the combined company is still cheap considering NRG’s significant discount to intrinsic value.    
  2. Falling natural gas prices. LNG terminals could result in more volatile natgas prices. Long-dated hedges protect the company from <$7 prices. Natural gas prices, while backwardated in 2009-2011 are now contango in 2012-2013 versus 2011, which signals $9-$10 gas is here to stay.     
  3. Supply additions, specifically low-cost coal and nuclear plants. NRG’s earnings will fall if natural gas ceases to set the price of power around the clock. Significant wind generation (assuming transmission is added) could impact off-peak heat rates in the 2012 timeframe.
  4. Carbon legislation. See appendix.
  5. Rising coal and/or uranium prices. NRG’s uses PRB and lignite coals, which have been less volatile given minimal export opportunities unlike eastern coal.
  6. Re-regulation. As power prices escalate, there will invariably be cries to re-regulate the business, much like a windfall profits tax on oil companies. This will always be a risk.
  7. Cost overruns on the South Texas nuclear plant addition funded on a recourse basis to NRG.
  8. Demand response programs, which increase reserve margins.
  9. Slowdown in demand growth (multi-year recession).
  10. Cash traps from high yield covenants limiting dividend and share repurchases.
  11. Significant seasonality as the bulk of earnings should fall in the summer months (3Q).
  12. Lawsuit filed by CDWR alleging $940 MM of overcharging.
  13. Lots of buy reports from sellside analysts. However, most analysts use a terminal natgas price in the $7-8 range despite natural gas futures prices of $11.11, $10.25, $9.97, $10.00 and $10.14 for 2009-2013. Even using these low terminal natgas prices, most analysts still come up with a high $40s/low $50s target price. 

Appendix
Carbon Discussion:
The regulation of CO2 is a big risk considering NRG’s heavy carbon footprint. However, calculating the impact is very difficult. Here are some of the unknowns:
 
1)       Form the legislation will take (cap-and-trade or tax)
2)       Implementation date (2012-2014)
3)       Amount of permits that will be allocated for free
4)       Caps on how high per ton costs can go
5)       Offsets
 
Unlike SO2 and NOx, there is no commercially proven carbon abatement technology. In the short run, the only way to reduce carbon emissions is to increase the utilization of natural gas plants and reduce the run times of coal plants. As an example, let’s assume coal (PRB + transport) costs $2.00/mmbtu and a heat rate for an inefficient coal plant is 12,000/btu/KWh versus $11.00 and 7,000 for natgas. Before variable and fixed costs, it costs coal $24/mwh compared to $77 for gas. Assuming a gas plant emits 50% of the CO2 as a coal plant, CO2 emission prices must exceed $100 for gas to displace coal ((77-24)/50%). With coal more expensive in the east, this transition point is lower, but it still results in significantly higher power prices.
 
Unlike many natural gas plants, coal plants were not designed to cycle up and down. Additionally, what would the increased natural gas usage do to natural gas prices? The US would either need to extract more gas domestically or import LNG. Overseas, natural gas is more expensive and more supply contracts are being signed at rates tied to oil prices. On an energy equivalent basis, natural gas should trade close to $20/mmbtu.
 
Then there is the circular reference argument. Presumably declining coal demand would cause coal prices to fall, while greater natural gas demand would lead to higher gas prices. For the coal to gas flipping to occur, carbon would need to go even higher, again leading to higher power prices. Much like ethanol, the law of unintended consequences takes hold.
 
If Congress acts rationally (a big if), my sense is they will realize that power generated via coal is inevitable, but they will incentivize the development of alternative power sources (i.e. nuclear, renewables, gas) and carbon sequestration through a carbon tax or a reasonable cap-and-trade program. Existing coal will not be displaced; rather the new economics of carbon-light fuels will make new build decisions easier to justify. Still, power prices will undoubtedly increase.
 
Impact on NRG:
NRG’s risk is magnified in regions (e.g. ERCOT) where gas sets the price of power around-the-clock (i.e. on-peak and off-peak hours) as a natural gas plant emits roughly 50% of the carbon that a coal plant releases. NRG’s nuclear plant(s) and wind additions should mitigate some of this risk, especially if the company is successful in expanding its South Texas nuclear facility. Excluding the nuclear plant addition, my calculations suggest a pre-tax hit of $14 MM for every dollar per ton cost of CO2 emissions. This calculation includes the wind plants and assumes the South Central costs are passed along to customers in accordance with NRG’s contractual rights. It also assumes no allocations and no concurrent increase in natural gas prices as demand for gas grows.
 
There are various bills circulating Congress (Lieberman-Warner, Bingaman-Specter, etc.). Using my assumptions, I calculate a $3-$7 NPV/share hit. Again, this assumes no increase in natural gas prices and adds no value for NRG’s nuclear brownfield addition. Both of these factors should substantially lessen the impact on NRG. Plus, NRG’s Texas natural gas plants should see higher run times and greater value. Other potential offsets include some of NRG’s carbon sequestration activities (i.e. Powerspan’s technology and testing at the WA Parish facility).
 
As an aside, I recently spoke with a consultant specializing in carbon legislation, who indicated that this country’s priorities when it comes to energy are price, security of supply and the environment in that order. Apparently TPG and KKR agree or they would not have purchased TXU for $45 BN with significant value allotted to the development of several coal plants with 2009-2010 start-dates.
 
For further analysis, Credit Suisse put out a good piece back in November (“The Inconvenient Math”).
 
Calpine Acquisition
On May 21st, Harbinger publicly released a letter it sent to Calpine’s Board of Directors recommending that the company engage in a merger of equals with NRG. In mid-May, NRG offered 0.534 shares of NRG stock for each share of Calpine. The implied Calpine price was $23/share with an enterprise value of around $20 BN, net of the NOL. This values the company at 12.0x, 11.0x and 9.6x 2008, 2009 and “open” EBITDA. If one assumes the SERC/SPP Calpine assets are sold (non-earning assets) at recent transaction prices, the aforementioned multiples decline slightly over a turn. Calpine also has CO2 upside, which should be worth north of $1 BN. While Calpine certainly has great assets, I believe NRG is overpaying, especially considering that NRG is offering up its undervalued stock as currency.
 
The magnitude of NRG’s standalone discount results in a combined entity (“Newco”) that is still cheap. Using my 2008 and 2009 estimates plus synergies ($100 MM), I compute EV/EBITDA multiples of 10.2x and 9.1x and FCF multiples of 15.3x and 12.9x, respectively. However, these numbers are misleading because they do not capture the value of NRG’s non-earning assets or the company’s earnings upside if the hedges are reset. Since some asset sales would be mandated by Texas law, NRG would probably divest its gas assets, which generate minimal earnings.  
 
Using an “open” EBITDA calculation and adding in the negative NPV from the hedges results in 7.7x and 9.7x EBITDA and FCF multiples. Taking this a step further and excluding the value of non-earning assets (Texas Genco gas units and SERC/SPP assets) leads to EBITDA and FCF multiples of 7.0x and 9.2x, respectively. While it is tough to say which assets will be sold and if the hedges will be reset, this analysis illustrates the value embedded in NRG and the potential earnings power of the business. One thing to note is that with the Calpine assets, the overhang from potential CO2 legislation would also diminish.   
 
In summary, my best case scenario is the NRG standalone situation. I hope the transaction does not go through, or it is done for no more than $23 as Calpine has a great asset base. However, even if the transaction is completed as structured, or at a slightly higher price, the Newco will be a bellwether power company trading a reasonable multiple with good growth prospects and a bright future.

Catalyst

1. Termination of offer for Calpine
2. Earnings growth and share buybacks
3. Hedge reset
4. Rising natgas and replacement costs
5. Delays in CO2 legislation
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