Northwest Natural Gas Company 10-Q 2010
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2010
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition period from _______ to _______
Commission File No. 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
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 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):
(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 30, 2010, 26,576,278 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, 2010
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:
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 caution you therefore 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 2009 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,” respectively.
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.
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
Notes to Consolidated Financial Statements
Organization and Principles of Consolidation
The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), primarily consisting of our regulated gas distribution business and our gas storage business, which includes our wholly-owned subsidiary Gill Ranch Storage, LLC (Gill Ranch), NW Natural Gas Storage, LLC (NW Gas Storage), a wholly-owned subsidiary of our subsidiary NW Natural Energy, LLC, and other investments and business activities, which primarily consist of our wholly-owned subsidiary NNG Financial Corporation (Financial Corporation) and an equity investment in Palomar Gas Holdings, LLC (PGH) that is developing a proposed natural gas transmission pipeline through its wholly-owned subsidiary Palomar Gas Transmission LLC (Palomar) (see Note 2). Investments in corporate joint ventures and partnerships in which we are not the primary beneficiary are accounted for by the equity method or the cost method.
In this report, the term “utility” is used to describe the gas distribution business and the term “non-utility” is used to describe the gas storage business and other non-utility investments and business activities (see Note 2). Intercompany accounts and transactions have been eliminated, except for transactions required to be included under regulatory accounting standards to reflect the effect of such regulation.
The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that management considers necessary for a fair statement of the results for each period reported. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2009 Annual Report on Form 10-K (2009 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.
Our significant accounting policies are described in Note 1 of the 2009 Form 10-K. There were no material changes to those accounting policies during the six months ended June 30, 2010. See below for a further discussion of newly adopted standards and recent accounting pronouncements. We do not have any subsequent events to report.
Certain prior year balances on our consolidated financial statements have been combined or reclassified to conform with the current presentation. These changes had no impact on our prior year’s consolidated results of operations and no material impact on financial condition or cash flows.
At June 30, 2010 and 2009 and at December 31, 2009, the amounts deferred as regulatory assets and liabilities were as follows:
New Accounting Standards
Variable Interest Entity.> Effective January 1, 2010, we adopted the amended authoritative guidance on variable interest entities (VIE). This guidance requires a continuing analysis to determine whether an entity has a controlling financial interest and whether it is the primary beneficiary. As the primary beneficiary with a controlling financial interest we would be required to consolidate the VIE in our financial statements. The guidance defines the primary beneficiary as the entity having:
Although we do have an ownership interest in PGH, which is the entity that owns Palomar and is a VIE, we are not the primary beneficiary (see Note 8) and therefore the adoption of this standard has not had a material effect on our financial condition, results of operations or cash flows; however, if we are required to consolidate PGH or other VIEs that may be acquired in future periods, it could have a material impact on our financial statements (see Note 8).
Recent Accounting Pronouncements
Fair Value Disclosures.> In January 2010, the Financial Accounting Standards Board issued authoritative guidance on new fair value measurements and disclosures. This guidance requires additional disclosures for fair value measurements that use significant assumptions not observable in active markets (i.e. level 3 valuations) including a rollforward schedule. These changes are effective for periods beginning after December 15, 2010; however, we elected to early adopt these disclosure requirements, as shown in Note 7 of our 2009 Form 10-K. The adoption of this standard did not have, and is not expected to have, a material effect on our financial statement disclosures.
Basic earnings per share are computed using the weighted average number of common shares outstanding during each period presented. Diluted earnings per share are computed using the weighted average number of common shares outstanding plus the potential effects of the assumed exercise of stock options and the 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:
For the three months ended June 30, 2010 and 2009, 5,052 and 6,228 common share equivalents, respectively, were excluded from the calculation of diluted earnings per share because the effect of these additional shares on the net income for both periods would have been anti-dilutive. For the six months ended June 30, 2010 and 2009, 1,364 and 5,143 common share equivalents, respectively, were excluded from the calculation of diluted earnings per share because the effect of these shares would have been anti-dilutive.
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 “gas storage” segment includes NW Gas Storage, Gill Ranch and a portion of the gas storage services related to our Mist underground storage facility in Oregon. Our “other” segment includes our equity investment in PGH to develop the Palomar project and Financial Corporation. For further discussion of our segments, see Note 2 in our 2009 Form 10-K.
NW Gas Storage was recently formed to manage our gas storage operations, including Gill Ranch. NW Gas Storage commenced operations during the second quarter of 2010 and was not operational during 2009.
The following table presents information about the reportable segments for the three and six months ended June 30, 2010 and 2009. Inter-segment transactions are insignificant.
As of June 30, 2010, our common shares authorized were 100,000,000 and our outstanding shares were 26,576,278.
We have a share repurchase program for our common stock under which we may purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2011 to repurchase up to an aggregate of 2.8 million shares or up to $100 million. No shares of common stock were repurchased under this program during the six months ended June 30, 2010. Since inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.
We have several stock-based compensation plans, including a Long-Term Incentive Plan (LTIP), a Restated Stock Option Plan (Restated SOP) and an Employee Stock Purchase Plan. 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 Part II, Item 8., Note 4, in the 2009 Form 10-K and current updates provided below.
Long-Term Incentive Plan.> On February 24, 2010, 41,500 performance-based shares were granted under the LTIP, which include a market condition, based on target-level awards and a weighted-average grant date fair value of $25.64 per share. Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:
In February 2010, the Board approved a payout of performance-based stock awards for the 2007-09 award period. Shares of common stock were purchased on the open market to satisfy the approved awards.
Restated Stock Option Plan.> On February 24, 2010, options to purchase 119,750 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of $44.25 per share on the date of grant, vesting over a four-year period following the date of grant and with a term of 10 years and 7 days. The weighted-average grant date fair value was $6.36 per share. Fair value was estimated as of the date of grant using the Black-Scholes option pricing model based on the following assumptions:
As of June 30, 2010, there was $1.1 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2013.
Cost of Long-Term Debt
Our long-term debt consists of medium-term notes (MTNs) that have maturity dates from 2010 through 2035, and have interest rates ranging from 3.95 percent to 9.05 percent with an average interest rate of 6.19 percent. For the six months ended June 30, 2010 we did not issue or redeem any secured MTNs. In March 2009, we issued $75 million of 5.37 percent secured MTNs due February 1, 2020, and in July 2009, we issued another $50 million of secured MTNs with an interest rate of 3.95 percent and a maturity of July 15, 2014. Proceeds from these MTNs were used to fund utility capital expenditures, to redeem utility short-term and long-term debt, and to provide utility working capital for general corporate purposes.
Fair Value of Long-Term Debt
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. Because our debt outstanding does not trade in active markets, we used interest rates for outstanding debt issues that actively trade and have similar credit ratings, terms and remaining maturities to estimate fair value for our long-term debt issues.
6. Pension and Other Postretirement Benefits
The following tables provide the components of net periodic benefit cost for our company-sponsored qualified and non-qualified defined benefit pension plans and other postretirement benefit plans:
See Part II, Item 8., Note 7, in the 2009 Form 10-K for more information about our pension and other postretirement benefit plans.
In addition to the company-sponsored defined benefit plans referred to above, we contribute to a multiemployer pension plan for our bargaining unit employees in accordance with our collective bargaining agreement, known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan). The Western States Plan is managed by a board of trustees that includes equal representation from participating employers and labor unions. Contribution rates are established by collective bargaining agreements and benefit levels are set by the board of trustees based on the advice of an independent actuary regarding the level of benefits that agreed-upon contributions are expected to support. As of January 1, 2010, the Western States Plan had an accumulated funding deficiency for the current plan year and remained in “critical status.” A plan is considered to be in critical status if its funded status is 65 percent or less. Federal law requires pension plans in critical status to adopt a rehabilitation plan designed to restore the financial health of the plan. Rehabilitation plans may specify benefit reductions, contribution surcharges, or a combination of the two. We made contributions totaling $0.2 million to the Western States Plan for both the six months ended June 30, 2010 and 2009. The Western States Plan board of trustees imposed a 5 percent contribution surcharge to participating employers, including NW Natural, beginning in August 2009, which increased to a 10 percent contribution surcharge beginning January 2010. The board of trustees also adopted a rehabilitation plan that reduced benefit accrual rates and adjustable benefits for active employee participants and increased future employer contribution rates. These changes are expected to improve the funding status of the plan. Contribution surcharges above 10 percent will be assessed to employer participants, but these higher surcharges will not go into effect for NW Natural until its next collective bargaining agreement, which is expected to be no earlier than June 1, 2014. Under the terms of our current collective bargaining agreement, which became effective in July 2009, we can withdraw from the Western States Plan at any time. If we withdraw and the plan is underfunded, we could be assessed a withdrawal liability. We have no current intent to withdraw from the plan, so we have not recorded a withdrawal liability.
Employer Pension Contributions
In February 2010, we made a $10 million cash contribution to our qualified defined benefit pension plans, portions of which were for the 2009 and 2010 plan years. We also continue to make cash contributions for our unfunded, non-qualified pension plans and other postretirement benefit plans. For more information see Part II, Item 8., Note 7, in the 2009 Form 10-K.
7. Income Tax
The effective income tax rate for the six months ended June 30, 2010 and 2009 varied from the combined federal and state statutory tax rates principally due to the following:
The increase in our effective tax rate for the six months ended June 30, 2010 compared to the same period in 2009 was primarily due to the increase in the Oregon statutory tax rate from 6.6 percent to 7.9 percent and an increase in the amortization rate of our regulatory tax asset pursuant to a regulatory order effective November 1, 2009, which we largely recover in utility rates or through a regulatory adjustment for income taxes paid.
Property, plant and equipment – net consists of the following as of June 30, 2010 and 2009 and December 31, 2009:
Our other long-term investments include financial investments in life insurance policies, which are accounted for at fair value, and equity investments in certain partnerships and limited liability companies, which are accounted for under the equity or cost methods (see Note 1 above for the newly adopted standard on variable interest entities, and see Part II, Item 8., Note 9, in the 2009 Form 10-K for more detail on our investments).
Variable Interest Entities. >PGH is a VIE owned 50 percent by us and 50 percent by Gas Transmission Northwest Corporation, an indirect wholly-owned subsidiary of TransCanada Corporation. PGH intends to develop a natural gas transmission pipeline in Oregon to serve our utility as well as the growing natural gas markets in Oregon and other parts of the Pacific Northwest, through its wholly-owned subsidiary Palomar. Palomar is a development stage entity. As of June 30, 2010, we updated our VIE analysis and determined that we are not the primary beneficiary of PGH’s activities as defined by the authoritative guidance related to consolidations (see Note 1). Therefore, we account for our investment in PGH and the Palomar project under the equity method, and our equity investment balance at June 30, 2010 and 2009 was $14.8 million and $10.6 million, respectively, which is included in other investments on our balance sheet. The increase in our equity investment balance over the last 12 months is due to $2.7 million of equity contributions plus $1.5 million for our share of income allocation based on our 50 percent ownership interest. 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 percent owner.
PGH Impairment Analysis. >In May 2010, we learned that the company proposing to build an LNG terminal on the Columbia River had suspended its operations and filed for bankruptcy. This company previously entered into a precedent agreement with Palomar for a majority of the transmission capacity on the proposed pipeline. As of June 30, 2010, Palomar had incurred a total $44.8 million of capital costs, including AFUDC (allowance for funds used during construction), toward the development of the pipeline (both east and west segments), and it had collected $15.8 million from a letter of credit which supported the bankrupt shipper’s obligations under a prior precedent agreement. In addition, Palomar holds credit support in the form of a lien on assets of the bankrupt shipper under terms of the current precedent agreement.
Our equity investment balance in PGH as of June 30, 2010 was $14.8 million. We performed an impairment analysis of our total equity investment as of June 30, 2010 and determined that no impairment write-down is needed because the value of the expected development of this pipeline will exceed our total equity investment. If, however, we learn that the project is not viable, we could be required to recognize an impairment of up to approximately $14 million based on the amount of our equity investment as of June 30, 2010 net of cash and working capital at Palomar. We will continue to monitor and update our impairment analysis as needed.
Items excluded from net income and charged directly to stockholders’ equity are included in accumulated other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss in stockholders’ equity is $5.8 million and $4.3 million as of June 30, 2010 and 2009, respectively, which is related to employee benefit plan liabilities. The following table provides a reconciliation of net income to total comprehensive income for the three and six months ended June 30, 2010 and 2009.
We enter into swap, option and combinations of option contracts for the purpose of hedging natural gas and the forecasted issuance of fixed-rate debt which qualify as derivative instruments under accounting rules for derivative instruments and hedging activities. We primarily use these derivative financial instruments to manage commodity prices related to our natural gas purchase requirements and to manage interest rate risk exposure related to our long-term debt issuances.
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 core utility customers. We also enter into financial derivatives, up to prescribed limits, to hedge price variability related to the physical gas supply contracts. Derivatives entered into prudently for future gas years prior to our annual Purchased Gas Adjustment (PGA) filing receive regulatory deferred accounting treatment. Derivative contracts entered into after the annual PGA rate was set on November 1, 2009 that are for the current gas contract year are subject to our PGA incentive sharing mechanism, which provides for 90 percent of the changes in fair value to be deferred as regulatory assets or liabilities and the remaining 10 percent to be recorded to the income statement for contracts not qualifying for cash flow hedge accounting and to other comprehensive income for contracts qualifying for cash flow hedge accounting.
Most of our commodity hedging for the upcoming gas year is completed prior to the start of each gas year, and these hedge prices are included in our annual PGA filing. We typically hedge approximately 75 percent of our anticipated year-round sales volumes based on normal weather. We entered the 2009-10 gas year (November 1, 2009 – October 31, 2010) hedged at a targeted level of 75 percent, including 60 percent financially hedged and 15 percent physically hedged through gas storage volumes. Our policy allows us to hedge price risk for up to 100 percent of our gas supplies for the next gas year and up to 50 percent for the following gas year.
At June 30, 2010 and 2009, we were hedged with financial contracts for the upcoming gas year at approximately 45 percent and 48 percent, respectively, based on anticipated sales volumes. At June 30, 2010, we were also hedged with financial contracts for the 2011-12 gas year between 10 and 15 percent.
The following table discloses the balance sheet presentation of our derivative instruments as of June 30, 2010 and 2009 and December 31, 2009:
The following table discloses the income statement presentation for the unrealized gains and losses from our derivative instruments for the three and six months ended June 30, 2010 and 2009. All of our currently outstanding derivative instruments are related to regulated utility operations as illustrated by the derivative gains and losses being deferred to balance sheet accounts in accordance with regulatory accounting.
Our derivative liabilities exclude the netting of collateral. We had no collateral posted with our counterparties as of June 30, 2010 or 2009. We attempt to minimize the potential exposure to collateral calls by our counterparties to manage our liquidity risk. Based on our current credit ratings, most counterparties allow us credit limits ranging from $15 million to $25 million before collateral postings are required. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We also could 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 contracts outstanding, which reflect unrealized losses of $50.3 million at June 30, 2010, we have estimated the projected collateral demands, with and without potential adequate assurance calls, using current gas prices and various downgrade credit rating scenarios for NW Natural as follows:
In the three and six months ended June 30, 2010, we realized net losses of $14.6 million and $20.8 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases to the cost of gas, compared to net losses of $42.4 million and $121.7 million, respectively, for the three and six months ended June 30, 2009. 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 settled our $50 million interest rate swap in March 2009, concurrent with our issuance of the underlying long-term debt, and realized a $10.1 million effective hedge loss which is being amortized to interest expense over the term of the debt.
We are exposed to derivative credit risk primarily through securing pay-fixed natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases on behalf of customers. We utilize master netting arrangements through International Swaps and Derivatives Association contracts to minimize this risk along with collateral support agreements with counterparties based on their credit ratings. In certain cases we require guarantees or letters of credit from counterparties in order for them to meet our minimum credit requirement standards.
Our financial derivatives policy requires counterparties to have a certain investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating. We do not speculate on derivatives; instead we utilize derivatives to hedge our exposure above risk tolerance limits. Any increase in market risk created by the use of derivatives should be offset by the exposures they modify.
We actively monitor our derivative credit exposure and place counterparties on hold for trading purposes or require other forms of credit assurance, such as letters of credit, cash collateral or guarantees as circumstances warrant. Our ongoing assessment of counterparty credit risk includes consideration of credit ratings, credit default swap spreads, bond market credit spreads, financial condition, government actions and market news. We utilize a Monte-Carlo simulation model to estimate the change in credit and liquidity risk from the volatility of natural gas prices. We use the results of the model to establish earnings at-risk trading limits. Our credit risk for all outstanding derivatives at June 30, 2010 does not extend beyond October 2012.
We could become materially exposed to credit risk with one or more of our counterparties if natural gas prices experience a significant increase. If a counterparty were to become insolvent or fail to perform on its obligations, we could suffer a material loss, but we would expect such loss to be eligible for regulatory deferral and rate recovery, subject to prudency review. All of our existing counterparties currently have investment-grade credit ratings.
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. 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, 2010. We also did not have any transfers between level 1 or level 2 during the six months ended June 30, 2010 and 2009.
The following table provides the fair value hierarchy of our derivative assets and liabilities as of the six months ended June 30, 2010 and 2009 and December 31, 2009:
We own, or have previously owned, properties that may require environmental remediation or action. We accrue all material loss contingencies relating to these properties that we believe to be probable of assertion and reasonably estimable. We continue to study and evaluate the extent of our potential environmental liabilities, but due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several environmental site investigations, the range of potential loss beyond the amounts currently accrued, and the probabilities thereof, cannot currently be reasonably estimated. See Part II, Item 8., Note 11, in the 2009 Form 10-K.
The status of each site currently under investigation is provided below.
Gasco site.> We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised Upland Remediation Investigation Report and submitted it to the ODEQ for review. In November 2007, we submitted a Focused Feasibility Study (FFS) for groundwater source control, ODEQ conditionally approved the FFS in March 2008, subject to the submission of additional information. We have provided that information to ODEQ and are waiting for final approval from the agency. During the third quarter of 2009, we signed a joint Order on Consent with the Environmental Protection Agency (EPA) which requires the design of a final remedial action for the Gasco sediments. We have a liability accrued of $51.5 million at June 30, 2010 for the Gasco site, which is estimated at the low end of the range of potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.
Siltronic site. >We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ. The liability accrued at June 30, 2010 for the Siltronic site is $1.1 million, which is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.
Portland Harbor site.> In 1998, the ODEQ and the EPA completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes an area adjacent to the Gasco and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties, referred to as the Lower Willamette Group, to fund environmental studies in the Portland Harbor. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS), completion of which is scheduled for 2011. The EPA and the Lower Willamette Group are conducting focused studies on approximately nine miles of the lower Willamette River, including the 5.5-mile segment previously studied by the EPA. In August 2008, we signed a cooperative agreement to participate in a phased natural resource damage assessment, with the intent to identify what, if any, additional information is necessary to estimate further liabilities sufficient to support an early restoration-based settlement of natural resource damage claims. As of June 30, 2010, we have a liability accrued of $8.4 million for this site, which is at the low end of the range of the potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.
In April 2004, we entered into an Administrative Order on Consent providing for early action removal of a deposit of tar in the river sediments adjacent to the Gasco site. We completed this removal of the tar deposit in the Portland Harbor in October 2005, and on November 5, 2005 the EPA approved the completed project. The total cost of removal, including technical work, oversight, consultant fees, legal fees and ongoing monitoring, was about $9.9 million. To date, we have paid $9.6 million on work related to the removal of the tar deposit. As of June 30, 2010, we have a liability accrued of $0.3 million for our estimate of ongoing costs related to this tar deposit removal.
Central Service Center site.> In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (the Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas as a result of historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated surface soils and removed accessible waste from some of the abandoned piping. In early 2008, we received notice that this site was added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and to its list where additional investigation or cleanup is necessary. We are currently performing an environmental investigation of the property with the ODEQ’s Independent Cleanup Pathway. As of June 30, 2010, we have a liability accrued of $0.5 million for investigation at this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.
Front Street site.> The Front Street site was the former location of a gas manufacturing plant we operated. It is near but outside the geographic scope of the current Portland Harbor site sediment studies, the EPA directed the Lower Willamette Group to collect a series of surface and subsurface sediment samples off the river bank adjacent to where that facility was located. Based on the results of that sampling, the EPA notified the Lower Willamette Group that additional sampling would be required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it could be managed separately from the Portland Harbor site under ODEQ authority. Work plans for source control investigation and a historical report were submitted to ODEQ and initial studies have been completed. ODEQ approval of the work plans has been received and studies are underway. As of June 30, 2010, we have an estimated liability accrued of $0.2 million for the study of the site, which will include investigation of sediments and the preparation of a report of historical upland activities. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.
Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating to environmental sites at June 30, 2010 and 2009 and December 31, 2009:
Regulatory and Insurance Recovery for Environmental Costs.> In May 2003, the Oregon Public Utility Commission (OPUC) approved our request to defer unreimbursed environmental costs associated with certain named sites, including those described above. Beginning in 2006, the OPUC granted us additional authorization to accrue interest on deferred environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, the authorized cost deferral and interest accrual has been extended through January 2011.
On a cumulative basis, we have recognized a total of $102.6 million for environmental costs, including legal, investigation, monitoring and remediation costs, including $4.9 million accrued and paid prior to regulatory deferral order approval. At June 30, 2010, we had a regulatory asset of $109.3 million, which includes $41 million of total paid expenditures to date, $56.7 million for additional environmental costs expected to be paid in the future and accrued interest of $11.6 million. While we believe recovery of these deferred charges is probable through the regulatory process, we intend to pursue recovery from insurance carriers under our general liability insurance policies prior to seeking recovery through rates. Our regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We consider insurance recovery of most of our environmental costs to date probable based on a combination of factors including: a review of the terms of our insurance policies; the financial condition of the insurance companies providing coverage; a review of successful claims filed by other utilities with similar gas manufacturing facilities; and Oregon law that allows an insured party to seek recovery of “all sums” from one insurance company. We have initiated settlement discussions with a majority of our insurers. In the event that settlements cannot be reached, we intend to pursue other legal remedies. We continue to anticipate that our overall insurance recovery effort will extend over several years.
We anticipate that our regulatory recovery of environmental cost deferrals will not be initiated within the next 12 months because we do not expect to have completed our insurance recovery efforts during that time period. As such we have classified our regulatory assets for environmental cost deferrals as non-current. The following table summarizes the non-current regulatory assets relating to environmental sites at June 30, 2010 and 2009 and December 31, 2009: