NWN-2013-6.30-10Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2013
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to____________
Commission file number 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
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Oregon | 93-0256722 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (503) 226-4211
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [ X ] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer [ X ] Accelerated Filer [ ]
Non-accelerated Filer [ ] Smaller Reporting Company [ ]
(Do not check if a Smaller Reporting Company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [ X ]
At July 26, 2013, 26,975,108 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.
NORTHWEST NATURAL GAS COMPANY
For the Quarterly Period Ended June 30, 2013
TABLE OF CONTENTS
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PART 1. | FINANCIAL INFORMATION | |
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| Consolidated Financial Statements: |
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PART II. | OTHER INFORMATION |
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FORWARD-LOOKING STATEMENTS
This report contains “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following:
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• | assumptions and estimates; |
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• | future events or performance; |
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• | operational performance and costs; |
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• | efficacy of derivatives and hedges; |
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• | liquidity and financial positions; |
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• | project development and expansion; |
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• | procurement and development of gas supplies; |
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• | rate recovery and refunds; |
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• | impacts of laws, rules and regulations; |
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• | tax liabilities or refunds; |
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• | outcomes and effects of litigation, regulatory actions, and other administrative matters; |
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• | projected obligations under retirement plans; |
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• | availability, adequacy, and shift in mix of gas supplies; |
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• | approval and adequacy of regulatory deferrals; and |
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• | environmental, regulatory, litigation and insurance costs and recoveries. |
Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks, and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our 2012 Annual Report on Form 10-K, Part I, Item 1A. “Risk Factors” and Part II, Item 7. and Item 7A., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A, “Risk Factors,” herein.
Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
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| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
In thousands, except per share data | | 2013 | | 2012 | | 2013 | | 2012 |
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Operating revenues | | $ | 131,714 |
| | $ | 103,991 |
| | $ | 409,575 |
| | $ | 413,630 |
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Operating expenses: | | | | | | | | |
Cost of gas | | 59,142 |
| | 34,498 |
| | 201,501 |
| | 204,253 |
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Operations and maintenance | | 33,217 |
| | 32,138 |
| | 66,974 |
| | 66,570 |
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General taxes | | 7,342 |
| | 7,417 |
| | 16,074 |
| | 16,253 |
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Depreciation and amortization | | 18,930 |
| | 18,099 |
| | 37,737 |
| | 36,049 |
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Total operating expenses | | 118,631 |
| | 92,152 |
| | 322,286 |
| | 323,125 |
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Income from operations | | 13,083 |
| | 11,839 |
| | 87,289 |
| | 90,505 |
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Other income and expense, net | | 1,450 |
| | 620 |
| | 1,970 |
| | 1,092 |
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Interest expense, net | | 11,069 |
| | 10,464 |
| | 22,196 |
| | 21,655 |
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Income before income taxes | | 3,464 |
| | 1,995 |
| | 67,063 |
| | 69,942 |
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Income tax expense | | 1,338 |
| | 768 |
| | 27,298 |
| | 28,431 |
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Net income | | 2,126 |
| | 1,227 |
| | 39,765 |
| | 41,511 |
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Other comprehensive income: | | | | | | | | |
Amortization of non-qualified employee benefit plan liability, net of taxes of $151 and $109 for the three months and $302 and $217 for the six months ended June 30, 2013 and 2012, respectively | | 232 |
| | 166 |
| | 465 |
| | 332 |
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Comprehensive income | | $ | 2,358 |
| | $ | 1,393 |
| | $ | 40,230 |
| | $ | 41,843 |
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Average common shares outstanding: | | | | | | |
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Basic | | 26,958 |
| | 26,812 |
| | 26,943 |
| | 26,797 |
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Diluted | | 26,999 |
| | 26,896 |
| | 26,991 |
| | 26,879 |
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Earnings per share of common stock: | | | | | | | | |
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Basic | | $ | 0.08 |
| | $ | 0.05 |
| | $ | 1.48 |
| | $ | 1.55 |
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Diluted | | 0.08 |
| | 0.05 |
| | 1.47 |
| | 1.54 |
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Dividends declared per share of common stock | | 0.455 |
| | 0.445 |
| | 0.910 |
| | 0.890 |
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See Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
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In thousands | | June 30, 2013 | | June 30, 2012 | | December 31, 2012 |
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Assets: | | | | | | |
Current assets: | | | | | | |
Cash and cash equivalents | | $ | 12,214 |
| | $ | 4,002 |
| | $ | 8,923 |
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Accounts receivable | | 39,061 |
| | 13,459 |
| | 61,229 |
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Accrued unbilled revenue | | 14,692 |
| | 12,921 |
| | 56,955 |
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Allowance for uncollectible accounts | | (1,189 | ) | | (2,653 | ) | | (2,518 | ) |
Regulatory assets | | 25,952 |
| | 65,297 |
| | 52,448 |
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Derivative instruments | | 623 |
| | 2,142 |
| | 1,950 |
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Inventories | | 62,412 |
| | 68,868 |
| | 67,602 |
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Gas reserves | | 15,324 |
| | 11,021 |
| | 14,966 |
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Income taxes receivable | | 1,297 |
| | 3,119 |
| | 2,552 |
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Other current assets | | 8,781 |
| | 8,606 |
| | 19,592 |
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Total current assets | | 179,167 |
| | 186,782 |
| | 283,699 |
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Non-current assets: | | | | | | |
Property, plant, and equipment | | 2,833,083 |
| | 2,720,037 |
| | 2,786,008 |
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Less: Accumulated depreciation | | 833,851 |
| | 791,021 |
| | 812,396 |
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Total property, plant, and equipment, net | | 1,999,232 |
| | 1,929,016 |
| | 1,973,612 |
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Gas reserves | | 113,762 |
| | 65,026 |
| | 84,693 |
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Regulatory assets | | 393,652 |
| | 362,290 |
| | 382,255 |
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Derivative instruments | | 1,054 |
| | 1,170 |
| | 3,639 |
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Other investments | | 67,410 |
| | 68,230 |
| | 67,667 |
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Restricted cash | | 4,000 |
| | 4,000 |
| | 4,000 |
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Other non-current assets | | 14,312 |
| | 13,936 |
| | 13,555 |
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Total non-current assets | | 2,593,422 |
| | 2,443,668 |
| | 2,529,421 |
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Total assets | | $ | 2,772,589 |
| | $ | 2,630,450 |
| | $ | 2,813,120 |
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See Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
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In thousands | | June 30, 2013 | | June 30, 2012 | | December 31, 2012 |
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Liabilities and equity: | | | | | | |
Current liabilities: | | | | | | |
Short-term debt | | $ | 136,000 |
| | $ | 113,200 |
| | $ | 190,250 |
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Accounts payable | | 63,466 |
| | 48,361 |
| | 85,613 |
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Taxes accrued | | 6,798 |
| | 5,205 |
| | 9,588 |
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Interest accrued | | 6,404 |
| | 5,607 |
| | 5,953 |
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Regulatory liabilities | | 16,644 |
| | 20,748 |
| | 20,792 |
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Derivative instruments | | 9,392 |
| | 29,407 |
| | 10,796 |
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Other current liabilities | | 34,446 |
| | 42,336 |
| | 45,444 |
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Total current liabilities | | 273,150 |
| | 264,864 |
| | 368,436 |
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Long-term debt | | 691,700 |
| | 641,700 |
| | 691,700 |
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Deferred credits and other non-current liabilities: | | | | | | |
Deferred tax liabilities | | 469,964 |
| | 438,217 |
| | 444,377 |
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Regulatory liabilities | | 294,202 |
| | 280,295 |
| | 288,113 |
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Pension and other postretirement benefit liabilities | | 214,125 |
| | 185,844 |
| | 215,792 |
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Derivative instruments | | 1,754 |
| | 2,130 |
| | 578 |
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Other non-current liabilities | | 79,145 |
| | 82,665 |
| | 74,497 |
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Total deferred credits and other non-current liabilities | | 1,059,190 |
| | 989,151 |
| | 1,023,357 |
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Commitments and contingencies (see Note 13) | | — |
| | — |
| | — |
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Equity: | | | | | | |
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,972, 26,827, and 26,917 at June 30, 2013 and 2012 and December 31, 2012, respectively | | 359,772 |
| | 352,955 |
| | 356,571 |
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Retained earnings | | 397,603 |
| | 389,247 |
| | 382,347 |
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Accumulated other comprehensive loss | | (8,826 | ) | | (7,467 | ) | | (9,291 | ) |
Total equity | | 748,549 |
| | 734,735 |
| | 729,627 |
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Total liabilities and equity | | $ | 2,772,589 |
| | $ | 2,630,450 |
| | $ | 2,813,120 |
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See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
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| | Six Months Ended |
| | June 30, |
In thousands | | 2013 | | 2012 |
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Operating activities: | | | | |
Net income | | $ | 39,765 |
| | $ | 41,511 |
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Adjustments to reconcile net income to cash provided by operations: | | | | |
Depreciation and amortization | | 37,737 |
| | 36,049 |
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Deferred tax liabilities | | 28,401 |
| | 28,346 |
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Non-cash expenses related to qualified defined benefit pension plans | | 2,773 |
| | 4,109 |
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Contributions to qualified defined benefit pension plans | | (4,200 | ) | | (18,400 | ) |
Deferred environmental expenditures, net of recoveries | | (2,989 | ) | | (3,925 | ) |
Other | | 3,403 |
| | 1,459 |
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Changes in assets and liabilities: | | | | |
Receivables | | 63,102 |
| | 114,117 |
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Inventories | | 5,190 |
| | 5,495 |
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Taxes accrued | | (1,535 | ) | | (1,616 | ) |
Accounts payable | | (22,155 | ) | | (37,854 | ) |
Interest accrued | | 451 |
| | (250 | ) |
Deferred gas costs | | (648 | ) | | (11,830 | ) |
Other, net | | 10,847 |
| | 18,171 |
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Cash provided by operating activities | | 160,142 |
| | 175,382 |
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Investing activities: | | | | |
Capital expenditures | | (55,055 | ) | | (61,552 | ) |
Utility gas reserves | | (34,397 | ) | | (27,060 | ) |
Proceeds from sale of assets | | 6,580 |
| | — |
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Other | | 1,743 |
| | 61 |
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Cash used in investing activities | | (81,129 | ) | | (88,551 | ) |
Financing activities: | | | | |
Common stock issued, net | | 2,355 |
| | 2,910 |
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Long-term debt retired | | — |
| | (40,000 | ) |
Change in short-term debt | | (54,250 | ) | | (28,400 | ) |
Cash dividend payments on common stock | | (24,509 | ) | | (23,839 | ) |
Other | | 682 |
| | 667 |
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Cash used in financing activities | | (75,722 | ) | | (88,662 | ) |
Increase (decrease) in cash and cash equivalents | | 3,291 |
| | (1,831 | ) |
Cash and cash equivalents, beginning of period | | 8,923 |
| | 5,833 |
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Cash and cash equivalents, end of period | | $ | 12,214 |
| | $ | 4,002 |
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Supplemental disclosure of cash flow information: | | | | |
Interest paid | | $ | 21,746 |
| | $ | 21,652 |
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Income taxes paid | | — |
| | 2,648 |
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See Notes to Consolidated Financial Statements.
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements represent the consolidation of Northwest Natural Gas Company (NW Natural or the Company) and all companies that we directly or indirectly control, either through majority ownership or otherwise. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NW Natural Gas Reserves, LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships that we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method or the cost method, which includes NWN Energy’s investment in Palomar Gas Holdings, LLC (PGH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all significant intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage business and other non-utility investments and business activities.
During the first quarter of 2013, we identified an error in the rate used to calculate interest on regulatory assets. We assessed the materiality of this error on prior period financial statements and concluded it was not material to any prior annual or interim periods; however, the cumulative impact would have been material to the interim period ending March 31, 2013, if corrected in 2013. As a result, in accordance with accounting standards, we have revised our prior period financial statements as shown in Note 14 to correct for this error.
Certain prior year balances in our consolidated financial statements and notes have been reclassified to conform with the current presentation. These changes had no material impact on our prior year’s consolidated results of operations, financial condition or cash flows.
Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments that management considers necessary for a fair statement of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2012 Annual Report on Form 10-K (2012 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.
2. SIGNIFICANT ACCOUNTING POLICIES
Our significant accounting policies are described in Note 2 of the 2012 Form 10-K. There were no material changes to those accounting policies during the six months ended June 30, 2013. The following are current updates to certain critical accounting policy estimates and accounting standards in general.
Regulatory Accounting
In applying regulatory accounting in accordance with generally accepted accounting principles in the United States of America (GAAP), we capitalize or defer certain costs and revenues as regulatory assets and liabilities. The amounts deferred as regulatory assets and liabilities were as follows:
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| | Regulatory Assets |
| | June 30, | | December 31, |
In thousands | | 2013 | | 2012 | | 2012 |
Current: | | | | | | |
Unrealized loss on derivatives(1) | | $ | 9,392 |
| | $ | 29,407 |
| | $ | 10,796 |
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Other(2) | | 16,560 |
| | 35,890 |
| | 41,652 |
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Total current | | $ | 25,952 |
| | $ | 65,297 |
| | $ | 52,448 |
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Non-current: | | | | | | |
Unrealized loss on derivatives(1) | | $ | 1,754 |
| | $ | 2,130 |
| | $ | 578 |
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Pension balancing(3) | | 20,327 |
| | 10,611 |
| | 14,727 |
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Income tax asset | | 53,065 |
| | 63,452 |
| | 55,879 |
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Pension and other postretirement benefit liabilities(3) | | 191,312 |
| | 162,767 |
| | 182,688 |
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Environmental costs(4) | | 120,224 |
| | 113,369 |
| | 121,144 |
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Other(2) | | 6,970 |
| | 9,961 |
| | 7,239 |
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Total non-current | | $ | 393,652 |
| | $ | 362,290 |
| | $ | 382,255 |
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| | Regulatory Liabilities |
| | June 30, | | December 31, |
In thousands | | 2013 | | 2012 | | 2012 |
Current: | | | | | | |
Gas costs | | $ | 6,353 |
| | $ | 12,980 |
| | $ | 9,100 |
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Unrealized gain on derivatives(1) | | 547 |
| | 2,142 |
| | 1,950 |
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Other(2) | | 9,744 |
| | 5,626 |
| | 9,742 |
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Total current | | $ | 16,644 |
| | $ | 20,748 |
| | $ | 20,792 |
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Non-current: | | | | | | |
Gas costs | | $ | 481 |
| | $ | 1,504 |
| | $ | — |
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Unrealized gain on derivatives(1) | | 1,054 |
| | 1,170 |
| | 3,639 |
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Accrued asset removal costs | | 289,105 |
| | 274,756 |
| | 281,213 |
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Other(2) | | 3,562 |
| | 2,865 |
| | 3,261 |
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Total non-current | | $ | 294,202 |
| | $ | 280,295 |
| | $ | 288,113 |
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(1) | Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement. |
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(2) | Other primarily consists of several deferrals and amortizations under other approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge. |
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(3) | Certain utility pension costs are approved for regulatory deferral, including amounts recorded to the pension balancing account, to mitigate the effects of higher and lower pension expenses. Pension costs that are deferred include an interest component when recognized in net periodic benefit costs. See Note 7. |
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(4) | Environmental costs relate to specific sites approved for regulatory deferral by the Public Utility Commission of Oregon (OPUC) and Washington Utilities and Transportation Commission (WUTC). In Oregon, we earn a carrying charge on amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. In the 2012 Oregon general rate case, the OPUC authorized a Site Remediation and Recovery Mechanism (SRRM) that allows the Company to recover prudently incurred environmental costs, subject to an earnings test. For further information on environmental matters, see Note 13 and Note 15. |
New Accounting Standards
Recent Accounting Pronouncements
OBLIGATIONS RESULTING FROM JOINT AND SEVERAL LIABILITY ARRANGEMENTS. In February 2013, the Financial Accounting Standards Board (FASB) issued guidance regarding the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. This new guidance does not apply to obligations previously addressed within existing guidance. Under the new guidance, an entity is required to measure those fixed obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, an entity must disclose the nature and amount of the obligation as well as other information about the obligations. The guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. We are currently assessing the impact, if any, of this guidance on our financial position, results of operations, and disclosures.
Subsequent Events
Two stipulated settlements were filed with the OPUC on July 11, 2013 with regards to the implementation of our new environmental recovery mechanism and the recovery of carrying costs on working gas inventory. See Note 15 for more information.
3. EARNINGS PER SHARE
Basic earnings per share are computed using net income and the weighted-average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted-average number of common shares outstanding plus the effects of the assumed exercise of stock options, and payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Diluted earnings per share are calculated as follows: |
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| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
In thousands, except per share data | | 2013 | | 2012 | | 2013 | | 2012 |
Net income | | $ | 2,126 |
| | $ | 1,227 |
| | $ | 39,765 |
| | $ | 41,511 |
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Average common shares outstanding - basic | | 26,958 |
| | 26,812 |
| | 26,943 |
| | 26,797 |
|
Additional shares for stock-based compensation plans outstanding | | 41 |
| | 84 |
| | 48 |
| | 82 |
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Average common shares outstanding - diluted | | 26,999 |
| | 26,896 |
| | 26,991 |
| | 26,879 |
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Earnings per share of common stock - basic | | $ | 0.08 |
| | $ | 0.05 |
| | $ | 1.48 |
| | $ | 1.55 |
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Earnings per share of common stock - diluted | | $ | 0.08 |
| | $ | 0.05 |
| | $ | 1.47 |
| | $ | 1.54 |
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Additional information: | | | | | | | | |
Anti-dilutive shares excluded from net income per diluted common share calculation | | 43 |
| | 1 |
| | 28 |
| | 1 |
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4. SEGMENT INFORMATION
We operate in two primary reportable business segments, local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as “other.” We refer to our local gas distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-utility.” Our utility segment also includes NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp, and the utility portion of our Mist underground storage facility in Oregon (Mist). Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and all third-party asset management services. Our “other” segment includes NNG Financial and NWN Energy's equity investment in PGH, which is pursuing development of a cross-Cascades pipeline project. See Note 4 in our 2012 Form 10-K for further discussion of our segments.
The following table presents summary financial information concerning the reportable segments. Inter-segment transactions are insignificant: |
| | | | | | | | | | | | | | | | |
| | Three Months Ended Three Months Ended June 30, |
In thousands | | Utility | | Gas Storage | | Other | | Total |
2013 | |
| |
| |
| |
|
Operating revenues | | $ | 123,943 |
| | $ | 7,715 |
| | $ | 56 |
| | $ | 131,714 |
|
Depreciation and amortization | | 17,311 |
| | 1,619 |
| | — |
| | 18,930 |
|
Income from operations | | 9,437 |
| | 3,625 |
| | 21 |
| | 13,083 |
|
Net income | | 657 |
| | 1,452 |
| | 17 |
| | 2,126 |
|
Capital expenditures | | 32,134 |
| | 247 |
| | — |
| | 32,381 |
|
2012 | |
|
| |
|
| |
|
| |
|
|
Operating revenues | | $ | 95,938 |
| | $ | 7,996 |
| | $ | 57 |
| | $ | 103,991 |
|
Depreciation and amortization | | 16,478 |
| | 1,621 |
| | — |
| | 18,099 |
|
Income from operations | | 8,547 |
| | 3,264 |
| | 28 |
| | 11,839 |
|
Net income (loss) | | 130 |
| | 1,124 |
| | (27 | ) | | 1,227 |
|
Capital expenditures | | 40,786 |
| | 319 |
| | — |
| | 41,105 |
|
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended Six Months Ended June 30, |
In thousands | | Utility | | Gas Storage | | Other | | Total |
2013 | |
| |
| |
| |
|
Operating revenues | | $ | 393,602 |
| | $ | 15,861 |
| | $ | 112 |
| | $ | 409,575 |
|
Depreciation and amortization | | 34,499 |
| | 3,238 |
| | — |
| | 37,737 |
|
Income from operations | | 79,665 |
| | 7,582 |
| | 42 |
| | 87,289 |
|
Net income (loss) | | 36,688 |
| | 3,088 |
| | (11 | ) | | 39,765 |
|
Capital expenditures | | 54,522 |
| | 533 |
| | — |
| | 55,055 |
|
Total assets at June 30, 2013 | | 2,469,320 |
| | 287,341 |
| | 15,928 |
| | 2,772,589 |
|
2012 | |
|
| |
|
| |
|
| |
|
|
Operating revenues | | $ | 398,843 |
| | $ | 14,675 |
| | $ | 112 |
| | $ | 413,630 |
|
Depreciation and amortization | | 32,816 |
| | 3,233 |
| | — |
| | 36,049 |
|
Income from operations | | 84,511 |
| | 5,943 |
| | 51 |
| | 90,505 |
|
Net income (loss) | | 39,598 |
| | 1,930 |
| | (17 | ) | | 41,511 |
|
Capital expenditures | | 60,442 |
| | 1,110 |
| | — |
| | 61,552 |
|
Total assets at June 30, 2012 | | 2,326,919 |
| | 287,622 |
| | 15,909 |
| | 2,630,450 |
|
| | | | | | | | |
Total assets at December 31, 2012 | | 2,505,655 |
| | 291,568 |
| | 15,897 |
| | 2,813,120 |
|
Utility Margin
Utility margin is a financial measure consisting of utility operating revenues less revenue taxes and the associated cost of gas. By netting fluctuating costs of gas from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The following table presents additional segment information concerning utility margin. The gas storage and other segments emphasize growth in operating revenues and net income as opposed to margin because these segments do not incur commodity cost of sales like the utility and, therefore, use operating revenues and net income to assess performance.
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
In thousands | | 2013 | | 2012 | | 2013 | | 2012 |
Utility margin calculation: | | | | | | | | |
Utility operating revenues | | $ | 123,943 |
| | $ | 95,938 |
| | $ | 393,602 |
| | $ | 398,843 |
|
Less: Utility cost of gas | | 59,142 |
| | 34,498 |
| | 201,501 |
| | 204,253 |
|
Utility margin | | $ | 64,801 |
| | $ | 61,440 |
| | $ | 192,101 |
| | $ | 194,590 |
|
5. STOCK-BASED COMPENSATION
Our stock-based compensation plans include a Long-Term Incentive Plan (LTIP) under which various types of equity awards may be granted, an Employee Stock Purchase Plan, and a Restated Stock Option Plan (Restated SOP). These plans are designed to promote stock ownership in NW Natural by employees and officers. For additional information on our stock-based compensation plans, see Note 6 in the 2012 Form 10-K and updates provided below.
Long-Term Incentive Plan
Performance-Based Stock Awards
LTIP performance shares incorporate market, performance, and service-based factors. On February 27, 2013, 37,300 performance-based shares were granted under the LTIP based on target-level awards and a weighted-average grant date fair value of $38.96 per share. Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:
|
| | | |
Stock price on valuation date | $ | 45.38 |
|
Performance term (in years) | 3.0 |
|
Quarterly dividends paid per share | $ | 0.455 |
|
Expected dividend yield | 3.9 | % |
Dividend discount factor | 0.8943 |
|
Performance-Based Restricted Stock Units (RSUs)
On February 27, 2013, 25,748 performance-based RSUs were granted under the LTIP with a grant date fair value of $45.38 per share. As of June 30, 2013, there was $1.9 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2017. The RSUs awarded include a performance-based threshold and a vesting period of four years from the grant date. An RSU obligates the Company upon vesting to issue the RSU holder one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of that portion of the RSU.
Restated Stock Option Plan
As of June 30, 2013, there was $0.3 million of unrecognized compensation cost from grants of stock options issued in prior years, which is expected to be recognized over a period extending through 2014. The Restated SOP was terminated for new option grants in 2012; however, options that had been granted before the Restated SOP was terminated will remain outstanding until the earlier of their expiration, forfeiture, or exercise. Any new grants of stock options would be made under the LTIP. No stock options were granted in the six months ended June 30, 2013.
6. DEBT
Short-Term Debt
At June 30, 2013, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 57 days, an average maturity of 43 days, and an outstanding balance of $136.0 million. The carrying cost of our commercial paper approximates fair value using Level 2 inputs due to the short-term nature of the notes. See Note 2 in our 2012 Form 10-K for a description of the fair value hierarchy.
Long-Term Debt
At June 30, 2013, our utility's long-term debt consisted of $651.7 million of first mortgage bonds (FMBs) with maturity dates ranging from 2014 through 2042, interest rates ranging from 3.176% to 9.05%, and a weighted-average coupon rate of 5.71%. During the six months ended June 30, 2012, we did not issue or redeem any FMBs.
At June 30, 2013, our gas storage segment’s long-term debt consisted of $40 million of senior secured debt with a maturity date of November 30, 2016. This debt consists of $20 million of fixed rate debt with an interest rate of 7.75% and $20 million of variable interest rate debt, which currently has an interest rate of 7.00%. The debt is secured by all of the membership interests in Gill Ranch and is nonrecourse to NW Natural.
As our outstanding debt does not trade in active markets, we estimate the fair value of our outstanding long-term debt using interest rates of other companies’ outstanding debt issuances that actively trade in public markets and have similar credit ratings, terms, and remaining maturities to our debt. These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2 in our 2012 Form 10-K.
The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date:
|
| | | | | | | | | | | | |
| | June 30, | | December 31, |
In thousands | | 2013 | | 2012 | | 2012 |
Carrying amount | | $ | 691,700 |
| | $ | 641,700 |
| | $ | 691,700 |
|
Estimated fair value | | 769,679 |
| | 768,429 |
| | 834,664 |
|
See Note 7 in our 2012 Form 10-K for more detail on our long-term debt.
7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
The following table provides the components of net periodic benefit cost for the Company's pension and other postretirement benefit plans:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended Three Months Ended June 30, |
| |
| |
| | Other Postretirement |
| | Pension Benefits | | Benefits |
In thousands | | 2013 | | 2012 | | 2013 | | 2012 |
Service cost | | $ | 2,341 |
| | $ | 2,130 |
| | $ | 179 |
| | $ | 177 |
|
Interest cost | | 4,104 |
| | 4,304 |
| | 286 |
| | 315 |
|
Expected return on plan assets | | (4,678 | ) | | (4,639 | ) | | — |
| | — |
|
Amortization of net actuarial loss | | 4,421 |
| | 3,844 |
| | 169 |
| | 103 |
|
Amortization of prior service costs | | 55 |
| | 49 |
| | 49 |
| | 49 |
|
Amortization of transition obligations | | — |
| | — |
| | — |
| | 103 |
|
Net periodic benefit cost | | 6,243 |
| | 5,688 |
| | 683 |
| | 747 |
|
Amount allocated to construction | | (1,801 | ) | | (1,428 | ) | | (211 | ) | | (215 | ) |
Amount deferred to regulatory balancing account(1) | | (2,271 | ) | | (2,094 | ) | | — |
| | — |
|
Net amount charged to expense | | $ | 2,171 |
| | $ | 2,166 |
| | $ | 472 |
| | $ | 532 |
|
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended Six Months Ended June 30, |
| |
| |
| | Other Postretirement |
| | Pension Benefits | | Benefits |
In thousands | | 2013 | | 2012 | | 2013 | | 2012 |
Service cost | | $ | 4,682 |
| | $ | 4,260 |
| | $ | 358 |
| | $ | 354 |
|
Interest cost | | 8,207 |
| | 8,608 |
| | 572 |
| | 629 |
|
Expected return on plan assets | | (9,356 | ) | | (9,277 | ) | | — |
| | — |
|
Amortization of net actuarial loss | | 8,842 |
| | 7,687 |
| | 338 |
| | 206 |
|
Amortization of prior service costs | | 111 |
| | 98 |
| | 98 |
| | 98 |
|
Amortization of transition obligations | | — |
| | — |
| | — |
| | 206 |
|
Net periodic benefit cost | | 12,486 |
| | 11,376 |
| | 1,366 |
| | 1,493 |
|
Amount allocated to construction | | (3,656 | ) | | (2,846 | ) | | (430 | ) | | (429 | ) |
Amount deferred to regulatory balancing account(1) | | (4,620 | ) | | (4,162 | ) | | — |
| | — |
|
Net amount charged to expense | | $ | 4,210 |
| | $ | 4,368 |
| | $ | 936 |
| | $ | 1,064 |
|
(1) Effective January 1, 2011, the OPUC approved the deferral of certain pension expenses above or below the amount set in rates, with recovery of these deferred amounts through the implementation of a balancing account, which includes the
expectation of lower net periodic benefit costs in future years. Deferred pension expense balances accrue interest at the utility’s actual cost of long-term debt. See Note 2.
The following table presents amounts recognized in accumulated other comprehensive loss (AOCL) and the changes in AOCL related to our non-qualified employee benefit plan:
|
| | | | | | | |
| Three Months Ended | | Six Months Ended |
In thousands | June 30, 2013 | | June 30, 2013 |
Beginning balance | $ | (9,058 | ) | | $ | (9,291 | ) |
Amounts reclassified into AOCL | — |
| | — |
|
Amounts reclassified from AOCL: | | | |
Amortization of prior service costs | (2 | ) | | (4 | ) |
Amortization of actuarial losses | 385 |
| | 771 |
|
Total reclassifications before tax | 383 |
| | 767 |
|
Tax expense | (151 | ) | | (302 | ) |
Total reclassifications for the period | 232 |
| | 465 |
|
Ending balance | $ | (8,826 | ) | | $ | (8,826 | ) |
Employer Contributions to Company-Sponsored Defined Benefit Pension Plan
In the six months ended June 30, 2013, we made cash contributions totaling $4.2 million to our qualified defined benefit pension plan. In 2012, Congress passed the "Moving Ahead for Progress in the 21st Century Act" (MAP-21), which among other things, includes provisions that reduce the level of minimum required contributions in the near-term but generally increase contributions in the long-run as well as increase the operational costs of running a pension plan. Including the impacts of MAP-21, we expect to make approximately $8 million in additional pension contributions during 2013.
Multiemployer Pension Plan
In addition to the Company-sponsored defined benefit pension plan referred to above, we contribute to a multiemployer pension plan for our utility’s union employees known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan) in accordance with our collective bargaining agreement. The employer identification number of the plan is 94-6076144. The cost of this plan, and corresponding future liabilities, are in addition to pension expense presented in the table above. Our contributions to the Western States Plan amounted to $0.2 million for the six months ended June 30, 2013 and 2012. Under the terms of our current collective bargaining agreement, we can withdraw from the Western States Plan at any time. However, if the plan is underfunded at the time we withdraw, we would be assessed a withdrawal liability. In accordance with accounting rules for multiemployer plans, we have not recognized these potential withdrawal liabilities on the balance sheet. Currently, we have made no decision to withdraw from the plan. We continue to monitor the financial condition of the plan and consider options with respect to this plan.
Defined Contribution Plan
The Retirement K Savings Plan provided to our employees is a qualified defined contribution plan under Internal Revenue Code Section 401(k). Our contributions to this plan totaled $1.6 million and $1.2 million for the six months ended June 30, 2013 and 2012, respectively.
See Note 8 in the 2012 Form 10-K for more information about these retirement and other postretirement benefit plans.
8. INCOME TAX
The effective income tax rate varied from the combined federal and state statutory tax rates principally due to the following: |
| | | | | |
| June 30, |
| 2013 | | 2012 |
Federal statutory tax rate | 35.0 | % | | 35.0 | % |
Increase (decrease): |
|
| |
|
|
Current state income tax, net of federal tax benefit | 4.6 |
| | 4.8 |
|
Amortization of investment and energy tax credits | (0.3 | ) | | (0.3 | ) |
Differences required to be flowed-through by regulatory commissions | 2.3 |
| | 1.5 |
|
Gains on company and trust-owned life insurance | (0.8 | ) | | (0.7 | ) |
Other, net | (0.1 | ) | | 0.3 |
|
Effective income tax rate | 40.7 | % | | 40.6 | % |
See Note 9 in the 2012 Form 10-K for more detail on income taxes and effective tax rates.
9. PROPERTY, PLANT, AND EQUIPMENT
The following table sets forth the major classifications of our property, plant, and equipment and related accumulated depreciation:
|
| | | | | | | | | | | | |
| | June 30, | | December 31, |
In thousands | | 2013 | | 2012 | | 2012 |
Utility plant in service | | $ | 2,468,853 |
| | $ | 2,363,061 |
| | $ | 2,435,886 |
|
Utility construction work in progress | | 61,283 |
| | 54,039 |
| | 46,831 |
|
Less: Accumulated depreciation | | 807,652 |
| | 770,825 |
| | 789,201 |
|
Utility plant, net | | 1,722,484 |
| | 1,646,275 |
| | 1,693,516 |
|
Non-utility plant in service | | 296,167 |
| | 296,619 |
| | 296,781 |
|
Non-utility construction work in progress | | 6,780 |
| | 6,318 |
| | 6,510 |
|
Less: Accumulated depreciation | | 26,199 |
| | 20,196 |
| | 23,195 |
|
Non-utility plant, net | | 276,748 |
| | 282,741 |
| | 280,096 |
|
Total property, plant, and equipment | | $ | 1,999,232 |
| | $ | 1,929,016 |
| | $ | 1,973,612 |
|
10. GAS RESERVES
We have agreements with Encana Oil & Gas (USA) Inc. (Encana) to develop physical gas reserves. These agreements are intended to provide long-term gas price protection for our utility customers rather than serving as a source of gas supply. Encana began drilling in 2011 under these agreements, and gas which is currently being produced from our working interests in these gas fields is sold by Encana at then prevailing market prices, with revenues from such sales, net of associated production costs, credited to our cost of gas. The cost of gas, including a carrying cost for the net rate base investment, is part of our annual Oregon PGA filing, which allows us to recover our costs through customer rates in a manner previously approved by the OPUC. This transaction acted to hedge the cost of gas for approximately 6% and 3% of our gas supplies for the six months ended June 30, 2013 and 2012, respectively. Our utility gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. The following table outlines our net investment in gas reserves:
|
| | | | | | | | | | | | |
| | June 30, | | December 31, |
In thousands | | 2013 | | 2012 | | 2012 |
Gas reserves, current | | $ | 15,324 |
| | $ | 11,021 |
| | $ | 14,966 |
|
Gas reserves, non-current | | 126,215 |
| | 69,097 |
| | 92,179 |
|
Less: Accumulated amortization | | 12,453 |
| | 4,071 |
| | 7,486 |
|
Total gas reserves | | 129,086 |
| | 76,047 |
| | 99,659 |
|
Less: Deferred tax liabilities on gas reserves | | 39,963 |
| | 26,839 |
| | 28,329 |
|
Net investment in gas reserves | | $ | 89,123 |
| | $ | 49,208 |
| | $ | 71,330 |
|
11. INVESTMENTS
Equity Method Investments
Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50% by NWN Energy and 50% by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation. PGH is a development stage VIE and Palomar is reported under equity method accounting based on the determination that we are not the primary beneficiary of PGH’s activities, as defined by the authoritative guidance related to consolidations, due to the fact that we have a 50% share and there are no stipulations that allow disproportionate influence over the entity. Our investment in PGH and Palomar are included in other investments on our balance sheet. Our maximum loss exposure related to PGH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50% owner. See Note 12 in our 2012 Form 10-K for more detail.
Other Investments
Other investments include financial investments in life insurance policies, which are accounted for at fair value. See Note 12 in the 2012 Form 10-K for more detail on other investments.
12. DERIVATIVE INSTRUMENTS
We enter into swap, option, and combinations of option contracts for the purpose of hedging natural gas. We primarily use these derivative financial instruments to manage commodity price variability related to our natural gas purchase requirements. A small portion of our derivative hedging strategy involves foreign currency exchange transactions related to purchases of natural gas from Canadian suppliers.
In the normal course of business, we enter into indexed-price physical forward natural gas commodity purchase (gas supply) contracts to meet the requirements of utility customers. We also enter into financial derivatives, up to prescribed limits, to hedge price variability related to these physical gas supply contracts as well as to hedge spot purchases of natural gas. The following table presents the absolute notional amounts related to open positions on financial derivative instruments:
|
| | | | | | | | | | | | |
| | June 30, | | December 31, |
Dollars in thousands | | 2013 | | 2012 | | 2012 |
Open position absolute notional amount: | | | | | | |
Natural gas (millions of therms) | | 35.9 |
| | 35.1 |
| | 39.5 |
|
Foreign exchange | | $ | 17,171 |
| | $ | 13,725 |
| | $ | 13,231 |
|
Derivatives entered into by the utility for the procurement or hedging of natural gas for future gas years and prior to our annual PGA filing receive regulatory deferred accounting treatment. Derivative contracts entered into after the annual PGA rate is set for the current gas contract year are subject to our PGA incentive sharing mechanism, which provides for either an 80% or 90% deferral of any gains and losses as regulatory assets or liabilities, with the remaining 10% or 20% recognized in current income. All of our commodity hedging for the 2012-13 gas year was completed prior to the start of the gas year, and these hedge prices were included in the Company's PGA filing.
The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. We also enter into exchange contracts related to the optimization of our gas portfolio, which are derivatives but do not qualify for hedge accounting or regulatory deferral, and are subject to our regulatory sharing agreement.
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended |
| | June 30, 2013 | | June 30, 2012 |
In thousands | | Natural gas commodity | | Foreign currency | | Natural gas commodity | | Foreign currency |
Cost of sales increase (decrease) | | $ | (16,139 | ) | | $ | — |
| | $ | 27,780 |
| | $ | — |
|
Other comprehensive loss | | — |
| | (274 | ) | | — |
| | (237 | ) |
Less: | |
|
| |
|
| |
|
| |
|
|
Amounts deferred to regulatory accounts | | 16,069 |
| | 274 |
| | (27,780 | ) | | 237 |
|
Total loss in pre-tax earnings | | $ | (70 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | |
| | Six Months Ended |
| | June 30, 2013 | | June 30, 2012 |
In thousands | | Natural gas commodity | | Foreign currency | | Natural gas commodity | | Foreign currency |
Cost of sales increase (decrease) | | $ | (8,956 | ) | | $ | — |
| | $ | (28,114 | ) | | $ | — |
|
Other comprehensive loss | | — |
| | (513 | ) | | — |
| | (111 | ) |
Less: | |
|
| |
|
| |
|
| |
|
|
Amounts deferred to regulatory accounts | | 9,032 |
| | 513 |
| | 28,114 |
| | 111 |
|
Total gain in pre-tax earnings | | $ | 76 |
| | $ | — |
| | $ | — |
| | $ | — |
|
No collateral was posted with or by our counterparties as of June 30, 2013 or 2012. We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio diversification, we have not been subject to collateral calls in 2012 or 2013. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change. Based upon current financial derivative contracts outstanding, which reflect unrealized losses of $8.8 million at June 30, 2013, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| |
| | Credit Rating Downgrade Scenarios |
In thousands | | (Current Ratings) A+/A3 | | BBB+/Baa1 | | BBB/Baa2 | | BBB-/Baa3 | | Speculative |
With Adequate Assurance Calls | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 6,337 |
|
Without Adequate Assurance Calls | | — |
| | — |
| | — |
| | — |
| | 6,180 |
|
Our derivative financial instruments are subject to master netting arrangements; however, they are presented on a gross basis on the face of our statement of financial position. The Company and its counterparties have the ability to set-off their obligations to each other under specified circumstances. Generally set-off of any early termination amount payable to one party by the other party, in circumstances where there is a defaulting party or where there is one affected party in the case where either a credit event upon merger has occurred, the occurrence of an event of default or any other termination event, will, at the option of the non-defaulting party be reduced by or set-off against any other amounts payable. If netted by counterparty, our derivative position would result in an asset of $0.2 million and $0.9 million and a liability of $9.7 million and $29.1 million as of June 30, 2013 and June 30, 2012, respectively.
In the three and six months ended June 30, 2013, we realized a net gain of $1.4 million and a net loss of $4.0 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as decreases and increases to the cost of gas, compared to net losses of $21.3 million and $50.7 million, respectively, for the three and six months ended June 30, 2012. The currency exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts.
We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in our 2012 Form 10-K for more information on our derivative instruments.
Fair Value
In accordance with fair value accounting, we include nonperformance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation techniques include natural gas futures, volatility, credit default swap spreads and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at June 30, 2013. As of June 30, 2013 and 2012 and December 31, 2012, the fair value was a liability of $9.5 million, $28.2 million, and $5.8 million, respectively, using significant other observable, or Level 2, inputs. We have used no Level 3 inputs in our derivative valuations. We did not have any transfers between Level 1 or Level 2 during the six months ended June 30, 2013 and 2012.
13. ENVIRONMENTAL MATTERS
We own, or previously owned, properties that may require environmental remediation or action. We estimate the range of loss for environmental liabilities based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated. Unless there is an estimate within a range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low end of this range. It is likely that changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to our continued evaluation and clarification concerning our responsibility, the complexity of environmental laws and regulations and the determination by regulators of remediation alternatives.
Environmental site remediation costs are deferred under regulatory approval from the OPUC and WUTC. In addition, the OPUC authorized a mechanism (SRRM) that allows the Company to recover prudently incurred environmental site remediation costs, subject to an earnings test. Actual cost recovery under SRRM depends upon future insurance recoveries, future expenditures, annual prudence reviews, and the impacts of an earnings test. Cost recovery and carrying charges on amounts deferred for costs associated with services provided to Washington customers will be determined in a future proceeding. We annually review all regulatory assets for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets no longer meet the criteria for continued application of regulatory accounting, then we would be required to write off the net unrecoverable balances against earnings in the period such determination is made. See Note 15 for information on the settlement agreement filed with the OPUC to resolve implementation issues for SRRM.
In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon (see Item 3. Legal Proceedings). In the complaint, NW Natural sought damages in excess of the $50 million in losses it had incurred through the date of the complaint, as well as declaratory relief for additional losses it expected to incur in the future.
The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other non-current liabilities on the balance sheet:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Current Liabilities | | Non-Current Liabilities |
| | June 30, | | December 31, | | June 30, |
| December 31, |
In thousands | | 2013 | | 2012 | | 2012 | | 2013 | | 2012 |
| 2012 |
Portland Harbor site: | |
| |
| |
| |
| |
| |
|
Gasco/Siltronic Sediments | | $ | 427 |
| | $ | 2,340 |
| | $ | 2,207 |
| | $ | 38,058 |
| | $ | 43,066 |
| | $ | 36,087 |
|
Other Portland Harbor | | 1,729 |
| | 1,286 |
| | 1,767 |
| | 2,598 |
| | 3,409 |
| | 3,160 |
|
Gasco Uplands site | | 11,354 |
| | 12,606 |
| | 18,722 |
| | 8,230 |
| | 10,769 |
| | 5,028 |
|
Siltronic Uplands site | | 496 |
| | 467 |
| | 637 |
| | 392 |
| | 620 |
| | 379 |
|
Central Service Center site | | 100 |
| | 100 |
| | 140 |
| | 338 |
| | 436 |
| | 396 |
|
Front Street site | | 475 |
| | 866 |
| | 993 |
| | 178 |
| | 646 |
| | — |
|
Oregon Steel Mills | | — |
| | — |
| | — |
| | 179 |
| | 117 |
| | 185 |
|
Total | | $ | 14,581 |
| | $ | 17,665 |
| | $ | 24,466 |
| | $ | 49,973 |
| | $ | 59,063 |
| | $ | 45,235 |
|
The following table presents information regarding the total amount of cash paid for environmental sites and the total regulatory asset deferred:
|
| | | | | | | | | | | | |
| | June 30, | | December 31, |
In thousands | | 2013 | | 2012 | | 2012 |
Cash paid | | $ | 83,936 |
| | $ | 62,468 |
| | $ | 71,124 |
|
Total regulatory asset deferral(1) | | 120,224 |
| | 113,369 |
| | 121,144 |
|
(1) Total regulatory asset deferral includes cash paid, remaining liability, and interest, net of insurance reimbursement.
PORTLAND HARBOR SITE. The Portland Harbor is an EPA listed Superfund site that is approximately 11 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and Siltronic uplands sites. We have been notified that we are a potentially responsible party to the Superfund site and we have joined with other potentially responsible parties (the Lower Willamette Group or LWG) to develop a Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). The LWG submitted a draft Feasibility Study (FS) to EPA in March 2012 that provides a range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of costs estimated for various remedial alternatives for the entire Portland Harbor, as provided in the draft FS, is $169 million to $1.8 billion. NW Natural's potential liability is a portion of the costs of the remedy EPA will select for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 potentially responsible parties. NW Natural is participating in a non-binding allocation process in an effort to settle this potential liability. We manage our liability related to the Superfund site as two distinct remediation projects, the Gasco/Siltronic Sediments and Other Portland Harbor projects.
Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. NW Natural submitted a draft Engineering Evaluation/Cost Analysis (EE/CA) to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA range from $38.5 million to $350 million. We have recorded a liability of $34.0 million for the sediment clean-up, which reflects the low end of the EE/CA range. We have recorded an additional liability of $4.5 million for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above.
Other Portland Harbor. NW Natural incurs costs related to its membership in the LWG which is performing the RI/FS for EPA. NW Natural may also incur costs related to natural resource damages. In 2008, the Portland Harbor Natural Resource Trustee Council advised a number of potentially responsible parties that it intended to pursue natural resource damage claims at the Portland Harbor Superfund site. The Company and other parties have signed a cooperative agreement with the Natural Resource Trustees to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. We have accrued a liability for these claims which is at the low end of the range of the potential liability. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor.
GASCO UPLANDS SITE. NW Natural owns a former gas manufacturing plant that was closed in 1956 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality (ODEQ) Voluntary Clean-Up Program. It is not included in the range of remedial costs for the Portland Harbor site. We manage the Gasco site in two parts, the uplands portion and the groundwater source control action.
In May 2007, we completed a revised Remedial Investigation Report for the uplands portion and submitted it to ODEQ for review. We have recognized a liability for this portion of the site remediation which is at the low end of the range of potential liability.
In 2012, ODEQ approved our final design remediation plan for a groundwater source control system on which we began construction in October 2012. Based on the information currently available for groundwater source control at the Gasco site and our current assumptions regarding the effectiveness of the source control system, we have estimated a range of liability between $10.7 million and $25 million, for which we have recorded an accrued liability
which is at the low end of the range of the potential liability. This range has uncertainty due to potential additional ODEQ requirements and actions needed to meet those requirements, including uncertainty about how to meet the agreed standards set by ODEQ subsequent to the initial testing of the system and as part of the final remedy for the uplands portion of the Gasco site.
OTHER SITES. In addition to those sites above, we have environmental exposures at four other sites, Siltronic, Central Service Center, Front Street, and Oregon Steel Mills. Due to the uncertainty of the design of remediation, regulation, timing of the liabilities, and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites has been recognized at their respective low end of the range of potential liability and the high end of the range cannot be reasonably estimated. See “Legal Proceedings” below.
Legal Proceedings
NW Natural is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, NW Natural does not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows. See also Part II, Item 1, “Legal Proceedings.”
OREGON STEEL MILLS SITE. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants, were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect that the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.
14. REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS
During the first quarter of 2013, we identified an error in the rate used to calculate interest on certain regulatory assets. Accounting standards allow for the capitalization of all or part of an incurred cost that would otherwise be charged to expense if the regulator provides orders that create probable recovery of past costs through future revenues. Historically we had accrued interest as specified by regulatory order on certain regulatory balances at our authorized rate of return (ROR). This ROR includes both a debt and equity component, which we are allowed to recover from customers in the form of a carrying cost on regulatory deferred account balances. As the equity component of our ROR is not an incurred cost that would otherwise be charged to expense, this portion of the carrying cost should not have been capitalized for financial reporting purposes.
We assessed the materiality of this error on prior period financial statements and concluded it was not material to any prior annual or interim periods; however, the cumulative impact would have been material to the interim period ending March 31, 2013, if corrected in 2013. As a result, in accordance with accounting standards, we revised our prior period financial statements as described below to correct for this error. The revision had no effect on reported cash flows.
The adjustment impacted years 2003 through 2012 with a cumulative pre-tax decrease over that period of $5.6 million to regulatory assets and other income and expense. The revision decreased net income by $1.1 million, $0.9 million and $0.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. The cumulative decrease to January 1, 2010 retained earnings was $0.7 million as a result of the revision.
The following table presents the income statement impacts of this revision for the years ended December 31:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2012 | | 2011 | | 2010 |
In thousands, except per share data | | Reported Balance | | Adjust- ment | | Adjusted Balance | | Reported Balance | | Adjust- ment | | Adjusted Balance | | Reported Balance | | Adjust- ment | | Adjusted Balance |
Other income and expense, net | | $ | 4,936 |
| | $ | (1,777 | ) | | $ | 3,159 |
| | $ | 4,523 |
| | $ | (1,411 | ) | | $ | 3,112 |
| | $ | 7,102 |
| | $ | (1,083 | ) | | $ | 6,019 |
|
Income before income taxes | | 103,959 |
| | (1,777 | ) | | 102,182 |
| | 107,280 |
| | (1,411 | ) | | 105,869 |
| | 122,129 |
| | (1,083 | ) | | 121,046 |
|
Income tax expense | | 44,104 |
| | (701 | ) | | 43,403 |
| | 43,382 |
| | (557 | ) | | 42,825 |
| | 49,462 |
| | (429 | ) | | 49,033 |
|
Net Income | | 59,855 |
| | (1,076 | ) | | 58,779 |
| | 63,898 |
| | (854 | ) | | 63,044 |
| | 72,667 |
| | (654 | ) | | 72,013 |
|
Comprehensive income | | 58,364 |
| | (1,076 | ) | | 57,288 |
| | 62,702 |
| | (854 | ) | | 61,848 |
| | 72,031 |
| | (654 | ) | | 71,377 |
|
Basic EPS | | 2.23 |
| | (0.04 | ) | | 2.19 |
| | 2.39 |
| | (0.03 | ) | | 2.36 |
| | 2.73 |
| | (0.02 | ) | | 2.71 |
|
Diluted EPS | | 2.22 |
| | (0.04 | ) | | 2.18 |
| | 2.39 |
| | (0.03 | ) | | 2.36 |
| | 2.73 |
| | (0.03 | ) | | 2.70 |
|
The following table presents the balance sheet impacts of this revision as of December 31:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2012 | | 2011 |
In thousands | | Reported Balance | | Adjustment | | Adjusted Balance | | Reported Balance | | Adjustment | | Adjusted Balance |
Non-current assets: | | | | | |
| | | | | |
|
Regulatory assets | | $ | 387,888 |
| | $ | (5,633 | ) | | $ | 382,255 |
| | $ | 371,392 |
| | $ | (3,856 | ) | | $ | 367,536 |
|
Total non-current assets | | 2,535,054 |
| | (5,633 | ) | | 2,529,421 |
| | 2,397,885 |
| | (3,856 | ) | | 2,394,029 |
|
Total assets | | 2,818,753 |
| | (5,633 | ) | | 2,813,120 |
| | 2,746,574 |
| | (3,856 | ) | | 2,742,718 |
|
Liabilities and equity: | | | | | |
| | | | | |
|
Deferred credits and other non-current liabilities: | | | | | | | | | | | | |
Deferred tax liabilities | | $ | 446,604 |
| | $ | (2,227 | ) | | $ | 444,377 |
| | $ | 413,209 |
| | $ | (1,526 | ) | | $ | 411,683 |
|
Total deferred credits and other non-current liabilities | | 1,025,584 |
| | (2,227 | ) | | 1,023,357 |
| | 975,922 |
| | (1,526 | ) | | 974,396 |
|
Equity: | | | | | | | | | | | | |
Retained earnings | | 385,753 |
| | (3,406 | ) | | 382,347 |
| | 373,905 |
| | (2,330 | ) | | 371,575 |
|
Total equity | | 733,033 |
| | (3,406 | ) | | 729,627 |
| | 714,488 |
| | (2,330 | ) | | 712,158 |
|
Total liabilities and equity | | 2,818,753 |
| | (5,633 | ) | | 2,813,120 |
| | 2,746,574 |
| | (3,856 | ) | | 2,742,718 |
|
The following tables present the income statement and balance sheet corrections for the following quarters:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2012 |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
In thousands, except per share data | | Reported Balance | | Adjusted Balance | | Reported Balance | | Adjusted Balance | | Reported Balance | | Adjusted Balance | | Reported Balance | | Adjusted Balance |
Other income and expense, net | | $ | 1,005 |
| | $ | 472 |
| | $ | 921 |
| | $ | 620 |
| | $ | 1,710 |
| | $ | 1,180 |
| | $ | 1,300 |
| | $ | 887 |
|
Income (loss) before income taxes | | 68,480 |
| | 67,947 |
| | 2,296 |
| | 1,995 |
| | (13,594 | ) | | (14,124 | ) | | 46,777 |
| | 46,364 |
|
Income tax expense (benefit) | | 27,873 |
| | 27,663 |
| | 887 |
| | 768 |
| | (3,036 | ) | | (3,245 | ) | | 18,380 |
| | 18,217 |
|
Net income (loss) | | 40,607 |
| | 40,284 |
| | 1,409 |
| | 1,227 |
| | (10,558 | ) | | (10,879 | ) | | 28,397 |
| | 28,147 |
|
Comprehensive income (loss) | |