When Edison Mission Energy first got into the coal-fired independent power business in 1999, it made money, but a combination of tough power markets, cheap natural gas and new emissions regulations have caused it and related companies to bleed money of late.
That it is a summary of much of a Dec. 17 first-day bankruptcy filing by Edison Mission Energy (EME) and related companies that sought Chapter 11 protection at the U.S. Bankruptcy Court for the Northern District of Illinois. There is a parallel effort ongoing to refinance these companies and de-couple them from long-time parent Edison International (NYSE: EIX).
EME acquired the bulk of its coal generation facilities in 1999, when Midwest Generation LLC (MWG), a subsidiary of EME that is also in bankruptcy, was formed to purchase a portfolio of assets from Commonwealth Edison that included the four coal-fired power plants in Illinois that it currently operates. The deal was designed to grant EME a significant toehold upon entering the Midwest electricity market, said a first-day filing sponsored by Maria Rigatti, Senior Vice President and CFO of Edison Mission Energy.
At the time of this buy, electricity prices were anticipated to rise, and coal commodity and transportation prices were very favorable. Edison International forecasted the plants’ early successes to help EME grow over 20% a year. Indeed, MWG’s annual performance shifted from a loss of $12m in 1999 to earnings of $477m in 2008.
EME originally operated its coal plants under a power purchase agreement (PPA) with ComEd but completely transitioned to merchant operation by Jan. 1, 2005.
In 1999, EME subsidiary MWG invested in several coal power plants (as well as a subsequently-retired gas plant and certain small gas and oil peaker plants), tripling the domestic power portfolio of EME and its subsidiaries and making coal their largest domestic source of power. EME’s decision to expand its exposure to coal was based on positive market conditions.
“Fuel was cheap and demand was strong—coal prices were low, rail contracts to transport coal were favorably priced, and coal power generated more than half of the electricity consumed in the United States,” Rigatti wrote. “Analysts celebrated the move, noting the ‘sound marketing strategy, minimal technology risk, and the low variable cost’ of EME’s assets after the transaction. At that time, the coal industry as a whole was bullish on its future prospects, particularly given the high relative cost of natural gas and the corresponding costs for gas plants to produce power. Indeed, as late as July 2005, power industry analysts worried whether enough coal plants would come online to take advantage of ‘[s]ustained higher natural gas prices.’”
The debtors’ current financial crisis comes from two disparate yet intertwined sources, Rigatti wrote.
- First, state and federal regulatory regimes imposed rigorous emissions requirements on coal, requiring the debtors to make significant capital expenditures on existing coal plants.
- Second, a confluence of economic and technological drivers has encouraged rampant natural gas production, resulting in a glut of cheap natural gas and has caused wholesale electricity prices (and EME’s resultant revenues) to plummet.
These two factors—higher capital expenditure requirements and declining revenues—have come at precisely the same time as debt interest payments and maturities loom.
Midwest Gen works way through Illinois CPS rule compliance
The environmental problems right now are not so much from new U.S. Environmental Protection Agency initiatives, but are due to a very tough Combined Pollutant Standard (CPS) that the company worked out several years ago with the state of Illinois. These CPS rules largely anticipated later federal requirements and, importantly, scheduled compliance deadlines so that EME could manage its most expensive capital expenditures in a responsible way.
CPS established three distinct phases, each for a different pollutant.
- Phase I required EME to implement measures to reduce mercury emissions by 2008. EME anticipated that implementation of Phase I would require $60m in capital expenditures, and spent approximately $50m.
- Phase II requires plants to reduce NOx emissions to 0.11 lbs/mmBtu before 2011. At the time that CPS was adopted, EME estimated that the selective catalytic reduction equipment required to comply with Phase II would cost $450m. EME then sought out alternative technologies that would allow it to comply at a lower cost. Prior to the required 2011 date, EME had evaluated selective non-catalytic reduction technologies which, when coupled with operational enhancements, in conjunction with independent engineering and construction support, allowed the fleet to successfully meet the stringent targets in a more economical manner. The result—an expenditure of only $105m—saved EME $345m without sacrificing performance. As of May 2012, the debtors’ fleet of coal power plants met and exceeded the CPS standards by averaging 0.101 lbs/mmBtu.
- EME is now making efforts to comply with Phase III, which requires it to reduce SO2 emissions by 2013. Compliance was initially estimated to cost between $2.2bn and $2.9bn. The first approach was to reduce fixed costs by assessing the applicability of a form of flue-gas desulfurization utilizing dry sorbent injection (DSI), using Trona as the sorbent. Trona equipment uses a form of baking soda to remove SO2 and has a substantially lower capital cost than other types of SO2 technologies. Their second approach was to switch to low-sulfur coal to reduce the amount of SO2 be scrubbed. The combination of the future utilization of Trona equipment in conjunction with lower sulfur coal will eliminate 80% to 90% of EME’s SO2 emissions, with a projected capital cost of $620m to $840m, depending upon the number of units that are retrofitted— substantially below the original estimate of almost $3bn. Further, the utilization of lower sulfur coal is likely to reduce the operating costs associated with the DSI. On Nov. 30, debtor MWG requested a variance from the Illinois Pollution Control Board from the 2015 and 2016 CPS rates and a deferral of five months (from Dec, 31, 2014, to May 31, 2015) for the deadline to install required equipment at its Waukegan Unit 8 coal facility.
When gas got cheap, the going at coal plants got hard
The rise of cheap natural gas, based in large part of gas “fracking” technology, transformed the energy market. The wholesale price of electricity closely tracks the price of natural gas. As the price of natural gas crashed in 2008, so did the wholesale price of electricity, Rigatti noted. By 2012, power generators were selling electricity for almost half the 2008 price.
“Although natural gas plants saw an even more pronounced decline in the price of the fuel they purchased to generate electricity, coal plants saw no such decline,” Rigatti added. “In fact, as natural gas prices plummeted, global demand for coal elevated its price. Rail costs to transport coal from producing regions to generating stations were also on the rise. The ‘dark spread,’ or the differential between the cost to produce coal-fired electricity and wholesale power prices, has been squeezed. These developments have led to what observers call ‘coal displacement,’ in which the traditional role for coal as a cheap, always-on energy source has given way to natural gas.”
Coal displacement has seriously impacted EME’s coal business. As an unregulated power producer earning revenues from the spot market, EME stands to gain when wholesale electricity prices rise. Conversely, it is also exposed to risk when prices substantially decline. Historically low wholesale electricity prices—along with rising coal prices—have magnified this risk beyond conservative estimates, and thus eroded EME’s bottom line, Rigatti noted. “Unfortunately, EME continues to face a depressed wholesale electricity market just as its significant, one-time environmental expenditures and debt maturities come due.”
Problems for coal-fired power abound, Rigatti noted. In fact, earlier this year, the U.S. Energy Information Administration announced that:
- plant owners and operators expect to retire almost 27 GW of capacity from 175 coal-fired generators between 2012 and 2016, which represents the retirement of 8.5% of total 2011 coal-fired capacity;
- this retirement of 27 GW of capacity between 2012 and 2016 is more than four times greater than the retirements of 6.5 GW of capacity performed during the preceding five-year period; and
- the retirement of 9 GW of coal-fired capacity expected to occur over the course of 2012 will likely be the largest one-year amount in the nation’s history.
EME worked to diversify and reduce its dependence on coal plants
Faced with the new reality of fracking, looming environmental expenditures, and upcoming debt payments, EME went beyond its innovative efforts to reduce compliance capital expenditures and started engaging in several additional initiatives to restructure its operations and improve its financial condition.
- First, it has diversified its energy portfolio, developing and constructing natural gas and wind assets in a manner designed to be least impactful on corporate liquidity including the use of non-recourse project debt, partner equity investments, and other financing sources.
- Second, EME has focused on improving reliability and efficiency.
- Third, where necessary, it reduced headcount and retired unprofitable plants.
- Fourth, it has improved safety in the course of undertaking these efforts.
- Finally, EME has been able to bolster its cash position by realizing benefits under certain Tax Sharing Agreements, pursuant to which EME can monetize tax losses used by Edison International and other affiliates.
The debtors and their non-debtor affiliates have diversified their holdings by developing and constructing those with potential for growth. This strategy has, for example, led to a refocused wind power strategy. Wind currently constitutes 22% of the debtors’ total electricity generating capacity (1,780 MW).
The debtors also have analyzed their natural gas holdings and, seeing an opportunity to invest in a growing source of electricity, have been expanding that capacity as well. Natural gas is currently 15% of the debtors’ total electricity generating capacity at 1,108 MW, and an additional 479 MW is under construction. The debtors’ natural gas facilities also generally operate under long-term PPAs, which stabilize their portfolio by reducing market risk.
The debtors have made significant investments in equipment monitoring and preventative maintenance of their coal fleet. These investments have resulted in a decline in “forced outages,” when unforeseen equipment failure prevents a power plant from generating power. These advances have reduced the number of forced outages at the debtors’ power plants by 25% from third quarter 2011 to third quarter 2012.
“Even with improved efficiency, the Debtors decided that two of their coal power plants could not be profitable over the long term,” Rigatti wrote. “In September 2012, the Debtors retired their Fisk and Crawford coal-fired power plants in Chicago, Illinois after they determined that they could not operate them profitably, particularly given the capital expenditures they would require. Due to compliance costs and declining revenue, EME also facilitated the consensual transition of its leasehold interest in the Homer City coal plant [in Pennsylvania] to stakeholders.”
Some EME companies are in bankruptcy (as debtors), some aren’t
Through its subsidiaries, EME owns or otherwise operates 42 operating and in-development projects with an aggregate net physical capacity of 8,762 MW, of which EME’s pro rata share (accounting for joint ventures) is 7,436 MW. Other than the Doga project, located in the Republic of Turkey, all of EME’s operations are in the United States. Most of EME’s project-level affiliates are not debtors in these Chapter 11 cases.
- MWG and its affiliates currently operate four coal plants in Illinois, including: the Joliet Station in Joliet; the Powerton Station in Pekin; the Waukegan Station, in Waukegan; and the Will County Station in Romeoville. As of the bankruptcy petition date, the net physical capacity for MWG’s four coal plants was 4,314 MW. MWG owns the coal facilities of Waukegan, Will County and Unit 6 at Joliet. It leases Powerton and Units 7 and 8 of Joliet under sale-leaseback transactions effected in August 2000.
- Two non-debtor EME subsidiaries are joint venture partners and, together, 50% owners of the non-debtor American Bituminous Power Partners LP (AmBit). AmBit operates an 80-MW waste coal facility located in Grant Town, W.Va., and sells its power under a 35-year PPA.
- Four of the debtors are joint venture partners in the Kern River, Midway-Sunset, Sycamore, and Watson natural gas power projects located in California (known as the “Big Four”). The Big Four facilities are cogenerators that simultaneously generate electricity and capture by-product heat and steam to use for other purposes or processes. By-product heat from the Big Four plants is used at nearby oil refinery facilities or for enhanced oil recovery. The refineries and oil operations are operated by the non-debtor joint venture counterparties. The debtors holding interests in the Big Four gas projects are holding companies with no operations or funded debt obligations. In the aggregate, the debtors’ share of the Big Four’s pre-tax net income was approximately $44m in 2011, down from about $52m in 2010. The debtors holding interests in the Big Four gas projects have filed petitions to protect their interests in those projects from alleged cross-defaults threatened by joint venture partners.
- Certain of the debtors’ non-debtor affiliates own interests in seven gas-fired generating projects in California and Turkey. Non-debtor Walnut Creek Energy LLC owns the 479-MW Walnut Creek Energy Park gas project in City of Industry, Calif. Construction on Walnut Creek began in June 2011 and commercial operation is anticipated in 2013. Walnut Creek and its direct and indirect owners are borrowers and guarantors of approximately $370m in outstanding construction and term loans and letters of credit. No debtors are obligors or guarantors of that debt.
- In addition, EME subsidiaries own 50% interests in and operate five other gas-fired power plants in California in joint venture with non-affiliates. Four of these projects are 38-MW cogeneration facilities that sell electricity under agreements that expire in 2016. The fifth plant is a 572-MW facility that operates as a merchant generator. None of these projects have any funded debt obligations.
- Debtor EME owns an 80% interest in a partnership that owns and operates Doga Enerji, a 180-MW gas-fired cogen plant near Istanbul, Turkey. Doga sells electricity under a PPA that expires in 2019, when the facility will be conveyed to the Turkish government. The Doga project does not have any funded debt obligations.
- Certain of the debtors’ non-debtor affiliates (including joint-venture affiliates) own and operate 29 wind generating facilities in Illinois, Iowa, Minnesota, Nebraska, New Mexico, Oklahoma, Pennsylvania, Texas, Utah, West Virginia, and Wyoming. In addition, certain of the debtors’ non-debtor affiliates have rights to acquire or participate in various other wind projects in early stages of planning or development.
- EME engages in hedging and energy trading activities through its Boston-based non-debtor subsidiary Edison Mission Marketing and Trading (EMMT). EMMT manages the energy and capacity of EME’s merchant generating plants and, in addition, trades power, capacity, fossil fuels, emissions allowances, and other energy-related products and derivatives.