June 8, 2016
Mr. James Allegretto
Senior Assistant Chief Accountant
Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549
Re: Northwest Natural Gas Company
Form 10-K for Fiscal Year Ended December 31, 2015
Filed February 26, 2016
File No. 1-15973
Dear Mr. Allegretto:
Northwest Natural Gas Company (“NW Natural”) acknowledges receipt of your letter on May 11, 2016 commenting on the above-referenced filing.
This letter contains our responses to the comments and explanations to the requested information. Please feel free to call me at the telephone number listed at the end of this letter if you would like to discuss any of the responses.
For the convenience of the Staff, each of the Staff's comments is included in bold and is followed by our corresponding response.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 24
Application of Critical Accounting Policies and Estimates, page 43
Impairment of Long-Lived Assets, page 46
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| 1. | We note your review of the Gill Ranch Storage facility for impairment. Please tell us your consideration of expanding your disclosures regarding the impairment review of the Gill Ranch Storage facility to: |
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| • | include the amount of the Gill Ranch storage assets at risk of potential impairment; |
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| • | indicate the percentage by which undiscounted cash flows exceeded carrying value as of the date of the most recent test; |
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| • | define the period of time over which you have assumed a recovery of storage pricing and an ability to contract with higher value customers; and |
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| • | describe the potential events and/or changes in circumstances that could reasonably be expected to negatively affect the key assumptions so that investors can assess the probability of a future material impairment charge. |
Response: Our Gill Ranch Storage facility was placed into service in 2010 and is included in our Gas Storage segment. At December 31, 2015, the facility had a net book value of approximately $200 million. In the fourth quarter of 2015, we identified factors which necessitated a review of our Gill Ranch Storage facility for impairment at December 31, 2015. The primary factor considered was historical and projected near-term negative cash flows resulting from the business. We prepared our projected probability weighted undiscounted cash flows over a remaining service life of 37 years with an assumed terminal value that resulted in the cash flows significantly exceeding the carrying value of the asset. The two key assumptions in our cash flow model were the ability to obtain new higher value customers and the recovery of storage market prices. Accordingly, if new higher value customers are not obtained and/or storage pricing does not improve, future analysis may result in an impairment of these long-lived assets.
Taking into consideration the results of our analysis, we evaluated the disclosure requirements set forth in ASC 360 and also considered the disclosure guidance around risks and uncertainties in ASC 275-10-50-8. In considering the guidance in ASC 275, we noted our undiscounted cash flow analysis included significant assumptions around improvement in storage market prices and our ability to obtain new higher value customers. Given the significance of those assumptions, we noted in our disclosures that changes in events or circumstances of our expectation of the storage market improvement and/or ability to obtain higher value customers could impact our conclusion in the future. Given the significant amount of headroom and our disclosure of any risks or uncertainties associated with our conclusions, we did not believe additional disclosures were warranted. We will continue to evaluate our Gill Ranch assets for triggering events and will consider whether any additional disclosure is warranted based on the results and circumstances of our review.
Notes to Financial Statements, page 56
Note 1. Organization and Principles of Consolidation, page 56
Environmental Regulatory Accounting, page 57
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| 2. | Please explain the circumstances that permitted recognition of $5.3 million of pre-tax interest income related to the equity earnings on your deferred environmental expenses. If such income related to the equity component of your deferred environmental expenditures, please explain how the 2015 Order permitted recognition under ASC 980 and whether such amounts were ever billed in rates. Please also explain how the $2.8 million of disallowed interest related to the 2016 OPUC order was calculated and why it bears a disproportionate relationship to the amount of interest recognized compared to the disallowance of $15 million relative to the $95 million of remediation expenses. Please be detailed in your response. |
Response: We began deferring environmental expenditures in 2003 under an order received from the Oregon Public Utilities Commission (“OPUC”). The order also allowed for the company to accrue interest on the deferral balance at our authorized rate of return. The authorized rate of return includes both a debt and equity component, which we are allowed to recover from customers on regulatory deferred account balances. Consistent with the guidance in ASC 980-340-25-5, we did not recognize the interest income associated with our shareholder equity investment.
In December 2010, we commenced litigation against certain historical insurers to recover amounts for damages incurred and expected to occur in the future arising from environmental contamination caused or alleged to be caused by our historical operations. In February 2014, we settled the majority of our remaining claims and received, in aggregate, $150 million of insurance proceeds associated with this litigation. The insurance proceeds were recorded as a regulatory liability while we awaited direction from the OPUC on the application methodology of the proceeds.
In our 2012 Oregon general rate case, we sought recovery of our deferred environmental costs. On February 20, 2015, the OPUC issued an order (“2015 Order”) approving our Site Recovery Remediation Mechanism. This mechanism allows us to recover environmental remediation expenses and we began collection of these costs in rates on November 1, 2015. Further, the Order deemed prudent substantially all environmental costs incurred through December 31, 2012, and directed us to apply $50.2 million (or the equivalent of 1/3 of the total) of insurance proceeds against deferred environmental remediation expense balances incurred through December 31, 2012. Consistent with the guidance in ASC 980, the receipt of the cash insurance proceeds prior to receiving the 2015 Order, coupled with the 2015 Order directing us to apply those insurance proceeds to past environmental remediation expenses, resulted in the Company realizing the shareholder investment associated with those past costs and triggered the recognition of $5.3 million of the equity component of interest expense. The $5.3 million represented the equity component of interest related to past environmental remediation expenses.
In the 2015 Order, the OPUC required that we forego the collection of $15 million out of approximately $95 million of environmental remediation expenses and associated carrying costs that the Company had deferred through 2012 based on the OPUC’s determination of how an earnings test should apply to amounts deferred from 2003 to 2012, with adjustments for other factors the OPUC deemed relevant. Subsequent to the issuance of the 2015 Order we made a compliance filing with the OPUC as required by the 2015 Order; in that filing we indicated our interpretation that the Commission’s intention was to limit the disallowance to encompass only the $15 million of past remediation expenses. The OPUC issued an additional order in January 2016 (2016 Order) clarifying certain parts of our compliance filing, including specifically disallowing interest we accrued on the $15 million disallowance from January 1, 2013 through February 2015. This additional disallowance was calculated at $2.8 million using our authorized rate of return which includes both the debt and equity components. The equity component of the $2.8 million disallowance had been previously recognized in 2015 as part of the $5.3 million noted above. Interest calculated on the $15 million prior to December 31, 2012 was not disallowed.
The $2.8 million of disallowed interest is disproportionate to the $5.3 million of interest income related to the equity component discussed above because the interest rates, amounts, and time periods over which the amounts were calculated are different. The $5.3 million of equity interest income was calculated on growing balances of environmental remediation expenses beginning in 2003 and includes only the equity component of our carrying cost. The $2.8 million of disallowed interest was calculated on the $15 million disallowance from January 1, 2013 through December 31, 2015 at a rate that included both the debt and equity component.
Note 11. Gas Reserves, page 77
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| 3. | We note your investment in the gas reserves program in the Jonah field. Please provide us a supplemental description of how the program operates and the specifics of how the costs of the program, including depletion, are calculated and included in your annual PGA filing. Please tell us how you viewed such operations under ASC 932 and whether you applied the successful efforts method or full cost method of accounting for the costs of exploration and production. If you did not apply either of the 2 accepted methods of accounting for gas extractive activities, please describe the method by which you determined the amount and rate of depletion and your basis in GAAP for the use of such method. If you believe such operations should be accounted for under ASC 980, please describe in detail how your regulated rates were designed to recover the specific costs of the program and whether sale of the program’s gas produced into the market, as opposed to use in servicing gas customers, |
impacted your decision to account for the program under ASC 980. Please also consider and advise whether existing disclosure adequately quantifies the extent to which such gas operations are being supported by your annual PGA filing. Please finally explain in detail how you are accounting for the amended agreement in which additional volumes produced are be included in your PGA at a fixed rate per therm as opposed to the specific costs of exploring and producing such volumes net of revenues received. We may have further comment upon receipt of your response.
Response: In 2011, we began a gas reserves program that was approved by the Oregon Public Utility Commission (“OPUC”) to hedge the cost of gas for the following 30 years. This program is included as part of our hedging plan that we provide annually to the OPUC. We have invested $188 million in our gas reserves program as of December 31, 2015 and account for our investment in gas reserves as a regulatory investment under ASC 980, which acted to hedge approximately 11% of our total gas requirements for the year-ended 2015. Our investments are made through a partnership arrangement originally with Encana and subsequently assigned to Jonah Energy.
Under the Carry and Earning Agreement (“the Original Agreement”), we are assigned working interests in leases throughout the Jonah Field. Operation of the wells is governed by a joint operating agreement under which Encana, then Jonah Energy, were and are the operators, and we pay our proportionate share of operating costs. In 2014, to facilitate Encana’s sale of their interest in the Jonah Field to Jonah Energy, we amended our Carry and Earning Agreement to terminate the obligation to fund and drill “carry” wells. Under the amended agreement with Jonah Energy, we have the ability to participate in undeveloped wells under the original agreement. Of the total $188 million invested, $8.0 million relates to investments made under the amended agreement with Jonah Energy. However, the operation of any additional wells is also governed by the same joint operating agreement that Jonah Energy assumed in its acquisition of Encana’s interest in the Jonah Field.
These investments in gas reserves are included as part of the Company’s cost of gas. The costs associated with the investments made under the Original Agreement are adjusted annually through the Oregon Purchase Gas Adjustment (“PGA”) mechanism for recovery from customers pursuant to an order issued by the OPUC in 2011. In proposing the gas reserves transaction to the OPUC, we analogized to and used the Full Cost Method for determining the appropriate costs to capitalize and include in the PGA. We calculate the amounts included in the PGA to include regulatory amortization (the cost of the investment amortized based on forecasted gas volumes produced over 30 years) plus a return on the investment, plus lease operating expenditures, less marketing revenues (revenues from gas sold less replacement gas purchases). Any differences in purchase and sale prices on the day are deferred and recovered through the PGA as well. The marketing aspects of the agreement are embedded in the Order from the OPUC and the overall transaction is a long-term hedge of the price of gas, so whether the company takes physical possession of the gas from the reserves does not impact the results of the hedge on the price of gas.
In the PGA calculation, we refer to regulatory amortization, which represents the depletion of the reserves, and is calculated in accordance with the regulatory order issued by the OPUC which requires that we “amortize our investment over 30 years in a manner designed to match the expected volumes.”
We have distinguished in our disclosures the differences between the investments under the Original Agreement and those made in 2014 under the amended agreement due to the difference in how they are included in the PGA, but believe we have adequately disclosed the extent to which these costs are being recovered and accounted for through the balance sheet and statement of comprehensive income. While we treat this transaction as a hedge of gas supplies and account for the transaction under ASC 980, we have
also evaluated the disclosure requirements under ASC 932 annually to determine whether or not our investments in gas reserves would be considered significant. In performing the significance tests under ASC 932-235-50-20 and reviewing S-K disclosure requirements, we have concluded the investments are not significant and additional disclosures are not required.
We have accounted for our amended agreement under ASC 980 consistent with the previous agreement. Our investment in gas reserves is regulated by the OPUC; they had and have the right to review all of the decisions made by us under the agreements and determine prudence and set recoverability measures. In reviewing the amended agreement, the Commission approved an alternative recovery mechanism for our investments in future wells. This was to allow for recovery at a comparable alternative rate, which they determined to be the cost of a 10 year hedge, plus the cost of a credit facility. In the Order, the OPUC approved the recovery of all volumes under the amended agreement at this fixed rate with any benefit or detriment being realized by the Company in the period it is incurred. In 2015, the Company recognized an immaterial benefit from the transaction. Overall, the Company is fully recovering its costs associated with its gas reserve investments and earning a return on those investments through its regulatory recovery mechanisms. As disclosed in our Form 10-K, our net investment in additional wells drilled under the amended agreements was $4.3 million as of December 31, 2015. At the present time, we expect that our participation in additional wells under the amended agreement will be limited to the 2014 wells. We do not currently expect to participate in future wells under the amended agreement.
We acknowledge that:
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| • | the company is responsible for the adequacy and accuracy of the disclosures in the filing; |
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| • | staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and |
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| • | the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
If you would like to discuss any of the responses to the Staff's comments or if you would like to discuss any other matters, please contact me at (503) 220-2345.
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| | Sincerely, |
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| | NORTHWEST NATURAL GAS COMPANY |
| | By: | /s/ Gregory C. Hazelton |
| | Gregory C. Hazelton |
| | Senior Vice President, Chief Financial Officer and |
| | Treasurer |
cc: Robyn Manuel, Staff Accountant
Shawn Filippi, Vice President and Corporate Secretary
John T. Hood, Morgan, Lewis & Bockius LLP
Roger Mills, PricewaterhouseCoopers LLP
