Portland General Electric Company — Q3 2013 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2013. Unaudited results. PGE is a vertically integrated electric utility serving Oregon; it reported 835,540 retail customers at quarter-end.
Financial performance
| Metric | Q3 2013 | Q3 2012 | Nine months 2013 | Nine months 2012 |
|---|---|---|---|---|
| Revenue | $435 million | $450 million | $1,311 million | $1,342 million |
| Gross margin | $245 million; 56% | $268 million; 60% | $773 million; 59% | $809 million; 60% |
| Operating income | $53 million | $82 million | $129 million | $231 million |
| Net income attributable to PGE | $31 million | $38 million | $58 million | $113 million |
| Diluted EPS | $0.40 | $0.50 | $0.76 | $1.49 |
Q3 operating margin was 12%, versus 18% a year earlier; nine-month operating margin was 10%, versus 17%. Q3 earnings declined mainly because higher average variable power costs reflected unplanned plant outages and lower hydro output, partly offset by a lower effective tax rate. Nine-month earnings fell mainly due to the $52 million Cascade Crossing charge and a $9 million industrial-customer refund, as well as higher power and operating costs. The lower estimated tax rate partly cushioned the year-to-date decline.
Cash flow and liquidity: Nine-month operating cash flow was $459 million, compared with $450 million. Capital expenditures were $453 million, and net cash used in investing was $491 million. Financing provided $111 million, including stock and bond proceeds; dividends paid were $62 million. Cash increased from $12 million to $91 million. PGE had no short-term debt or commercial paper outstanding and reported $696 million of available credit capacity. Management estimated full-year 2013 operating cash flow of $490–$500 million.
Debt and capitalization: Long-term debt was $1.761 billion at September 30, versus $1.536 billion at year-end 2012; no current portion or short-term debt was reported at quarter-end. The credit-agreement debt ratio was 49.6%, below the 65% covenant limit, and the common equity ratio was 50.5%. PGE issued $225 million of first mortgage bonds and repaid $100 million of maturities during the nine months. It agreed after quarter-end to issue another $155 million of bonds in two tranches.
Material changes and operating developments
- Nine-month revenue declined 2%; retail revenue fell 4%, primarily from lower prices following the 2013 power-cost update, the $9 million customer refund, lower energy deliveries, and PCAM-related changes. Wholesale revenue increased 55%, largely on higher average prices.
- Nine-month retail energy deliveries decreased 0.4%; average retail customers increased by about 5,300. Management said weather-adjusted deliveries were comparable to 2012 and expected 2013 deliveries to be comparable with weather-adjusted 2012 levels.
- Unplanned outages affected Colstrip Unit 4, Boardman, and Coyote Springs. PGE estimated $16–$18 million in 2013 replacement-power costs, including about $11 million incurred in Q3. Colstrip Unit 4 was expected back online in Q1 2014; Coyote Springs by the end of November 2013.
- PGE expensed $52 million of capitalized Cascade Crossing costs after suspending project development. In October, PGE and BPA discontinued discussions on an alternative transmission-capacity arrangement; PGE planned to withdraw its OPUC deferral request and rely on BPA tariff transmission service under current conditions.
- A $44 million PGE share of a Trojan spent-fuel settlement was received in Q3 and deposited into the nuclear decommissioning trust. The settlement proceeds are expected to benefit customers through future regulatory proceedings.
- PGE’s planned 2013 capital expenditures were approximately $720 million. Major projects included Port Westward Unit 2, Carty Generating Station, and Tucannon River Wind Farm; their stated estimated costs were $300 million, $450 million, and $500 million, respectively, excluding allowance for funds used during construction.
Outlook, regulation, and risks
- The 2013 power cost adjustment forecast was within the deadband, and PGE expected no 2013 PCAM collection from or refund to customers. Actual nine-month net variable power costs were $5 million below baseline.
- In the 2014 general rate case, PGE, OPUC staff, and certain customer groups reached agreements, subject to OPUC approval, for a revised $67 million annual revenue-requirement increase, approximately 4% in customer prices. The initial proposal had been $105 million. New prices were expected January 1, 2014; a final OPUC order was expected in mid-December 2013.
- The proposed rate-case terms included a 9.75% return on equity, 7.65% cost of capital, and extension of decoupling through 2016, all subject to regulatory approval.
- Management cited risks from weather, generation outages, fuel and wholesale power prices, capital-market access and credit ratings, regulatory cost recovery, environmental requirements, and legal proceedings. Potential collateral calls following a downgrade below investment grade were estimated at approximately $84 million for a single-agency downgrade or $225 million for a dual-agency downgrade as of September 30.
- Material unresolved matters included Trojan-related customer claims, Pacific Northwest power-market refund proceedings, Portland Harbor and Downtown Reach environmental matters, and Colstrip environmental litigation. Management said potential losses could not currently be reasonably estimated for several of these matters. The Colstrip case was scheduled for trial in October 2014.
Important facts for investors to verify
- Whether the OPUC approved the revised 2014 rate case and its proposed 4% customer-price increase.
- Actual outage repair and replacement-power costs, plant return-to-service timing, and any insurance recoveries.
- Whether planned capital projects remained on schedule and within budget, and how their financing affected debt and equity.
- Developments in Trojan, environmental, and wholesale-market proceedings, including any changes to estimated exposure or customer impacts.
- Whether full-year operating cash flow met management’s $490–$500 million estimate and whether customer deliveries tracked the weather-adjusted outlook.