PORTLAND GENERAL ELECTRIC CO quarterly report, Q3 FY2015

Portland General Electric Company — Q3 2015 Form 10-Q

Reporting period: Three and nine months ended September 30, 2015. Unaudited. PGE is a vertically integrated electric utility serving Oregon; it reported as a single operating segment.

Financial performance and position

Metric	Q3 2015	Q3 2014	Nine months 2015	Nine months 2014
Revenue	$476 million	$484 million	$1,399 million	$1,400 million
Gross margin	$295 million	$282 million	$909 million	$872 million
Operating income	$68 million	$65 million	$225 million	$221 million
Net income attributable to PGE	$36 million	$39 million	$121 million	$132 million
Diluted EPS	$0.40	$0.47	$1.47	$1.63

• Q3 purchased power and fuel expense fell $21 million year over year, as average variable power cost declined 9% to $31.90/MWh, aided by lower natural gas prices and greater gas and wind generation. Wholesale revenue declined $10 million.
• For the first nine months, purchased power and fuel expense declined $38 million and average variable power cost fell 8% to $30.76/MWh. Lower costs supported gross margin despite nearly flat revenue.
• Net income and EPS declined year over year. PGE cited weather-related lower residential deliveries and less favorable net variable power costs versus 2014; Q3 EPS also reflected the 10.4 million shares issued in June. Higher interest, operating, administrative and other expenses also weighed on results.
• Cash from operations was $439 million versus $473 million in the prior-year period. Capital expenditures were $452 million versus $824 million; net investing cash outflow was $377 million. Financing cash outflow was $97 million, including $442 million of debt repayments, partly offset by $271 million of equity proceeds and $145 million of debt issuance. Cash ended the period at $92 million.
• At September 30, PGE had $2.204 billion of long-term debt and no current portion reported. Its credit-agreement debt-to-capital ratio was 49.7%, below the 65% covenant limit; common equity was 50.3% of capitalization. Current assets were $605 million and current liabilities $465 million.
• PGE had a $500 million revolving facility with $497 million available after letters of credit, and separate letter-of-credit facilities totaling $135 million, of which $93 million was outstanding. Debt ratings were investment grade with stable outlooks.
• Dividends declared were $0.30 per share in Q3, versus $0.28 a year earlier. The nine-month declared dividend was $0.88 per share.

Material changes and operating drivers

• Retail energy deliveries rose 0.7% for the first nine months: industrial deliveries increased 7.6% and commercial 0.5%, while residential deliveries fell 3.0%. Warmer first-quarter weather contributed to lower residential use.
• PGE’s own generation supplied about 60% of retail load for the first nine months, up from 55% in 2014, reflecting new Tucannon River wind and Port Westward 2 generation and increased gas-fired output. Hydro receipts were 7% below projections and wind receipts 20% below projections for the period.
• Interest expense rose $15 million year over year for the first nine months, primarily due to higher average debt and reduced construction-related interest allowances. Other income declined $12 million, largely because of lower allowance for equity funds used during construction.
• The June equity issuance increased shares outstanding to approximately 88.8 million at September 30, from 78.2 million at year-end 2014. PGE used proceeds in part to support capital spending and debt maturities.

Outlook, management commentary and risks

• Management estimated 2015 capital expenditures of approximately $580 million, including $162 million for Carty Generating Station. Carty’s estimated total cost was $450 million excluding AFDC, described as on budget, with service expected in Q2 2016. PGE reported $396 million, including $34 million of AFDC, in Carty construction work-in-progress at September 30.
• Management expected 2015 cash from operations of $455–$495 million and planned to fund capital expenditures and debt maturities with operating cash, debt and equity financing. These are estimates, not guarantees.
• The proposed 2016 rate-case settlement, still subject to OPUC approval, indicated a net annual revenue requirement increase of $13 million. It contemplated a $43 million annualized decrease in customer prices effective January 1, 2016, followed by a $56 million annualized increase when Carty entered service, conditional on it being operational by July 31, 2016. If delayed, PGE said it would need a new rate request for Carty costs. A final OPUC order was expected in December 2015.
• PGE estimated 2015 net variable power costs would be above baseline but within the PCAM deadband; no 2015 customer collection or refund was expected under that mechanism.
• Important risks include weather and hydro/wind variability, wholesale power and fuel prices, plant availability, capital-project execution and recovery, regulatory decisions, environmental requirements, credit-rating changes and related collateral calls, and pending legal proceedings.
• Potential contingencies include Trojan-related customer class actions (plaintiffs seek $260 million plus interest; PGE said a loss was reasonably possible but could not estimate it), Portland Harbor remediation (PGE’s share not estimable; total cleanup alternatives were estimated at $800 million–$2.4 billion), and Colstrip environmental litigation and compliance costs. PGE recorded a $15 million increase in Colstrip asset retirement obligations for coal-ash rule impacts and planned to seek recovery from customers. Downtown Reach remediation was expected to cost about $3 million, with recovery through rates.

Most important facts for investors to verify

• Whether Carty remained on budget and entered service by the rate-case deadline, and whether its costs received final regulatory recovery approval.
• The final OPUC decision and actual timing and amount of the 2016 customer-price changes.
• Subsequent earnings, cash flow and financing needs in light of lower year-to-date net income, substantial capital spending and the enlarged share count.
• Changes in hydro and wind output, fuel and wholesale prices, and any resulting PCAM effects or collateral requirements.
• Developments and any estimable exposure in the Trojan, Portland Harbor and Colstrip proceedings, including costs and recovery prospects.