FREIF North American Power I LLC (FREIF; BB-/Stable) acquired a portfolio of electric generation assets that ArcLight Capital had managed. This includes the Borger project. FREIF is owned by First Reserve Energy Infrastructure Fund. Consolidated Asset Management Services will continue to be the asset manager and be responsible for operations.
In early December 2011, the project experienced a forced outage on one of the two units and this unit was returned to service in February 2012. The project estimates total repair expenses at $4.6 million (insurance deductible of $1 million), significantly above the operator’s initial estimate of about $2 million. However, the variance will not hurt the project’s financial performance, as ArcLight Capital is directly funding the repair expenses and reimburses the project for lost revenues. ArcLight Capital funded the insurance deductible of $1 million in the first quarter of 2012 and in the interim; it is directly funding the repair bills while receiving the insurance proceeds. Through June 2012, the project has received insurance proceeds of $750,000 from insurance providers. The project expects the remaining insurance claim to be received in the fourth quarter of 2012 and to be transferred to ArcLight Capital. The project expects the lost revenues and profits of about $1.5 million to be reimbursed by ArcLight Capital and insurance during the second half of 2012.
The project’s financial performance during the past several years has suffered significantly from unscheduled outages, low natural gas prices, and higher major maintenance funding that caused the project’s debt service coverage ratio (DSCR; including funding of major maintenance reserve) to decline significantly to 0.96x in 2011, 1.12x in 2010, and 0.96x in 2009 from 1.49x for 2008. Coverage in the 12 months ended June 30, 2012 was 0.92x because of pending reimbursement of lost margins from ArcLight Capital pertaining to the December 2011 forced outage. The project funded the shortfall with cash in 2009, 2011, and the 12 months ended June 31, 2012. The project budgets to achieve a year-end coverage (including the year-to-date June 2012 performance) of slightly above 1.0x for 2012.
The weighted-average cost of gas (WACOG) that the project uses fell below $2 per million Btu (mmBTU) in April and May 2012 from $3.0 per mmBTU in January 2012 and then recovered to $2.41 per mmBTU in June 2012. The project’s steam payments are directly linked to gas prices so they fell significantly.
Following the recovery in prompt gas prices from the low levels of end of March 2012, we updated our gas price assumptions in late July 2012 (see “Standard & Poor’s Raises Its U. S. Natural Gas Price Assumptions; Oil Price Assumptions Are Unchanged,” published July 24, 2012). Specifically, we raised our Henry Hub 2012 gas price assumption to $2.50 from $2.0 per mmBtu. Based on adjustments, this translates into an average annual gas price assumption for the Southwest Power Pool (SPP) of about $2.32 per mmBTU for 2012 ($2.85 in 2013; $3.32 in 2014). Based on these gas prices, we expect the project’s coverage to remain in the 1.0x to 1.15x range, if the operation remains stable. We view the project’s liquidity, consisting of six months debt service reserve and restricted and unrestricted cash balance of $5.6 million, as providing some cushion against low gas prices.
The December 2011 forced outage caused the 12-month availability as of June 2012 to drop to 87%, just below the 92% target per the power purchase agreement (PPA). The project anticipates that the availability would remain below the PPA minimum until the effect of December outage rolls over in January-February 2013. The on-peak summer availability was about 100%. As of June 2012, year-to-date generation volume was about 17% below budget and steam production was about 7% below budget because of the December 2011 outage, offset by continued strong demand from steam offtaker, ConocoPhillips However, this increased the combined-cycle heat rate by 4% above budget as a result of higher duct burner fuel consumption.
The ‘B+’ rating on Borger reflects the following risks:
-- Low gas prices directly hurt steam revenues, a key source of cash flow for the project.
-- Steam revenue is subject to demand variability under the agreement with ConocoPhillips. Under the contract, ConocoPhillips can modify its steam offtake volumes and terminate its obligation by paying a nominal, one-time termination fee that falls to zero over the agreement’s term.
-- Historical operational issues have brought the plant’s reliability as a steam provider into play.
-- Borger is a fleet leader for the Siemens Westinghouse 501D5A turbines. The project continues its discussion with Siemens about the need to evaluate the life of the rotors through inspection and subsequently possibly the need to refurbish the rotors. The major maintenance funding requirement does not include this cost, but the project’s management asserts that recent guidance from Siemens indicates that possible outages related to the life evaluationmay not have to take place until 2016, later than the previous guidance of 2013-2014. At this time, SAIC Energy, Environmental & Infrastructure LLC, an independent engineer, has not opined on the need to inspect the rotor.
-- The definition of the DSCR for purposes of distribution is weak because it excludes some key expenses, including funding of the major maintenance requirements.
The following strengths offset these risks at the ‘B+’ rating level:
-- The 25-year PPA, under which the plant provides 100% of its electrical capacity to Southwestern in exchange for fixed and variable payments.
-- The project’s management asserts it has the most cost-effective steam supply for the ConocoPhillips refinery compared with other alternatives.
-- The PPA somewhat mitigates the risk of losing the “steam host” (the refinery that uses the steam) by requiring Southwestern to continue to pay capacity payments and assume all fuel costs. When the project originally structured the deal, the capacity payments would have been enough to cover debt-service requirements if it lost the steam host. However, given higher-than-expected costs for insurance and standby power, plus partnership, general, and administrative costs, it is not clear that capacity payments would be sufficient under that scenario.
-- If ConocoPhillips terminates its minimum payment obligation under the agreement, it must continue to purchase steam from Borger as long as it needs more than by-product steam. Therefore, as long as ConocoPhillips’ Borger refinery is in operation, the company will likely buy steam from the Borger project.
Given low gas prices, liquidity coming from operating cash flow is tight and will likely remain so over the next year. The project has a six-month debt service reserve. The reserve increases to 12 months in 2018 unless the steam agreement continues (continuance being the likely scenario). A letter of credit provides the reserve. Unrestricted cash balance totaled $0.8 million as of June 30, 2012. There is a major maintenance reserve fund (part of restricted cash on balance sheet), which, as of June 30, 2012, had a cash balance of $4.2 million. The project also had other restricted cash balance of $0.7 million as of June 30, 2012.
Borger’s $117 million senior secured notes are rated ‘B+’ with a recovery rating of ‘4’, indicating the expectation for an average (30% to 50%) recovery if a payment default occurs.
At the ‘B+’ rating level, the stable outlook incorporates uncertainties surrounding the project’s exposure to operational and financial risks, including the rotor life evaluation and steam offtake by ConocoPhillips. Under our gas price scenario and using the project’s current major maintenance funding assumptions, we think it likely that the average DSCR will be about 1.2x through maturity. We could lower the rating if the plant’s operational performance deteriorates, it does not realize savings in major maintenance costs, our assumptions for gas pricing decrease materially (particularly for 2013 onward), the refinery’s steam offtake declines such that the DSCR falls to about 1.0x for the next two or three years (recognizing it has been below 1.0x in recent years), or the project draws on the debt service reserve fund. Moreover, if the need to conduct the life evaluation becomes certain, then we could lower the rating by multiple notches. Although less likely, we could raise the rating if the average DSCR rises above 1.2x on a sustained basis. Furthermore, such a rating increase would be contingent on greater clarity around the need for life evaluation of the rotors.
Related Criteria And Research
-- Updated Project Finance Summary Debt Rating Criteria, Sept. 18, 2007