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| NWN > SEC Filings for NWN > Form 10-K on 2-Mar-2009 | All Recent SEC Filings |
2-Mar-2009
Annual Report
The following is management's assessment of Northwest Natural Gas Company's (NW Natural) financial condition, including the principal factors that affect results of operations. The discussion refers to our consolidated activities for the years ended December 31, 2008, 2007 and 2006. Unless otherwise indicated, references in this discussion to "Notes" are to the Notes to Consolidated Financial Statements in this report.
The consolidated financial statements include the accounts of NW Natural and its wholly-owned subsidiaries, NNG Financial Corporation (Financial Corporation) and Gill Ranch Storage, LLC (Gill Ranch), and an equity investment in a proposed natural gas pipeline. These accounts consist of our regulated local gas distribution business, our regulated gas storage business, and other regulated and non-regulated investments primarily in energy-related businesses. In this report, the term "Utility" is used to describe our regulated local gas distribution segment, and the term "Non-utility" is used to describe our gas storage segment (gas storage) and our other regulated and non-regulated investments and business activities (other segment) (see "Strategic Opportunities," below, and Note 2).
In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references in this section to earnings per share are on the basis of diluted shares (see Note 1).
Executive Summary
Highlights of 2008:
• Consolidated net income was $69.5 million, or $2.61 per share;
• Net operating revenues decreased 3 percent from $369.0 million to $356.2 million, largely due to a $17.6 million swing in our utility's sharing of higher gas costs;
• Operations and maintenance expense decreased 6 percent or $7.1 million;
• Cash flow from operations decreased $148.9 million due to temporary working capital requirements, while our credit and liquidity position remained strong;
• General rate case was approved in Washington with a $2.7 million increase in annual revenues, effective January 1, 2009;
• Permit applications were filed for our gas storage project in California and our gas transmission pipeline project in Oregon, keeping these strategic investment opportunities on track for potential development over the next few years;
• We ranked number one in the nation among gas utilities in the 2008 J.D.
Power and Associates Gas Utility Residential Customer Satisfaction
Survey; and
• We raised the quarterly common stock dividend by 5 percent to $0.395 per share in the fourth quarter of 2008, making this the 53rd consecutive year of increasing dividends paid to shareholders.
Our business primarily consists of our regulated utility and gas storage
operations. Factors critical to the success of the utility business include:
maintaining a safe and reliable distribution system; acquiring an adequate
supply of natural gas; providing distribution services at competitive prices;
and being able to recover our operating and capital costs in the rates charged
to customers in a
reasonable and timely manner. Our utility is regulated by two state commissions, the Oregon Public Utility Commission (OPUC) and the Washington Utilities and Transportation Commission (WUTC). Factors critical to the success of our gas storage business include: developing additional storage capacity at competitive market prices; retaining existing customers or being able to market storage capacity to new customers; planning for the replacement of capacity that is expected to be recalled by the utility to serve growing demands of its customers; obtaining timely approval of reasonable rate increases; and with respect to future development of gas storage projects, being able to obtain financing to fund future development. Our existing gas storage business charges rates that are approved by the Federal Energy Regulatory Commission (FERC) for interstate customers or the OPUC for intrastate customers. The Gill Ranch gas storage project currently under development will be subject to regulation by the California Public Utilities Commission (CPUC), upon completion of certain milestones (see "2009 Outlook-Strategic Opportunities-Gas Storage Development," below).
2009 Outlook
In 2009, we intend to remain focused on improving our core businesses, enhancing our strategic position, advancing business development projects related to our primary businesses, and strengthening our organizational effectiveness. The following is a brief summary of management's plans and objectives in these four areas.
Business Improvements. We are developing and implementing new technology into our operations while honing the new processes established by the changes to our operating model over the last several years. Our goal is to integrate, consolidate and streamline operations and support our employees with new technology tools that should enable us to become more effective and efficient. We intend to continue developing new technology such as: an enterprise resource planning system, which provides an integrated comprehensive suite of business application software to more efficiently process and manage information in all parts of our business; continued deployment of our new automated dispatching system throughout the business, which provides integrated planning and scheduling with global positioning capabilities to more effectively collect and distribute data to employees in remote locations; and completing the installation of our automated meter reading system, which will convert the remaining customer meters so that all of our meters can be read electronically by the end of 2009. We expect these and other new technologies to continue supporting our new operating model, which re-aligned our operating functions into key process areas such as customer services, energy supply and gas delivery, to help centralize and standardize all of our business operations. For further discussion, see "Strategic Opportunities," below.
Strategic Position. In our rapidly changing business environment, we remain focused on creating shareholder value while balancing the interests of our customers, employees and the communities we serve. In doing so, we intend to develop and re-work plans in response to our changing business environment, including potential climate change legislation as well as ongoing economic, regulatory, business development and workforce challenges and opportunities. For further discussion, see "Issues, Challenges and Performance Measures," and "Strategic Opportunities," below.
Business Development. In addition to exploring new growth opportunities, we intend to continue advancing key natural gas infrastructure investments during 2009, including our gas transmission pipeline project in Oregon and our gas storage project in California. For further discussion of these two projects, see "Strategic Opportunities," below.
Organizational Effectiveness. Our employees continue to be our most highly valued resource. We intend to continue supporting our employees with a positive work environment, providing
development training, and developing new technologies to achieve our goals and facilitate improvements to our operating model. For further discussion see "Strategic Opportunities," below.
Issues, Challenges and Performance Measures
Managing the business in a period of gas price volatility. Our gas acquisition strategy is primarily designed to secure sufficient supplies of natural gas to meet the needs of our utility's residential, commercial and industrial customers on firm service. Equally important, however, is our strategy to hedge gas prices for a significant portion of our annual purchase requirements based upon our utility's gas load forecast for core utility customers. We have hedged gas prices for the majority of our gas purchases for the gas contract year that began on November 1, 2008, and we believe we have sufficient supplies of natural gas to meet the needs of our core utility customers. Although gas prices reached historically high levels during the third quarter of 2008, the price of natural gas has declined significantly in recent months and is currently below the prices embedded in our customers' rates through our annual purchased gas adjustment (PGA). Gas costs lower or higher than those set in the PGA may positively or negatively impact earnings, respectively, due to an incentive sharing mechanism in Oregon. Higher gas costs are also likely to affect our competitive advantage because they could reduce our ability to add residential and commercial customers and potentially cause industrial customers to shift their energy needs to alternative fuel sources. In October 2008, the OPUC approved a change to the PGA incentive sharing mechanism that allows us to select a cost-sharing ratio annually. The PGA cost-sharing ratio, along with gas hedging strategies and inventories in storage, enables us to manage and reduce earnings risk exposure due to higher gas costs. We believe the modification to the Oregon PGA better aligns customer and shareholder interests. In Washington, where we recover 100 percent of our actual gas purchase costs from customers, there has been no change to the PGA mechanism (see "Results of Operations-Regulatory Matters-Rate Mechanisms-Purchased Gas Adjustment," below).
Economic weakness and financial market stress. The overall weakness in the U.S. economy, including disruption in the global credit and financial markets, increasing numbers of foreclosures and bankruptcies, lower rates of new housing construction, and volatility in energy prices, has resulted in significant negative pressure on consumer demand and business spending. These conditions could have a negative impact on our financial results including certain key performance measures such as margins, customer growth rates, bad debt expense, and net interest charges. Our customer growth rate, which in recent years has slowed but continues at a rate above the national average, declined to 1.6 percent during 2008 compared to 2.4 percent in 2007. Based on current market conditions, we expect customer growth rates in 2009 to continue at or near 2008 levels, or possibly lower if economic conditions deteriorate further, but our growth rate should remain above the national average due to a relatively low market penetration of natural gas in our service territory, the forecasted population growth in our service territory, the potential for environmental initiatives in Oregon and Washington that could favor natural gas as an energy source, and our efforts to convert existing homes from other heating fuels to natural gas.
Our funding for strategic investment opportunities is dependent upon our ability to access capital markets and maintain working capital sufficient to meet operating requirements. We intend to continue focusing on: maintaining a strong balance sheet; providing sufficient liquidity resources; monitoring and managing critical business risks; and securing, as needed, proceeds from the issuance of equity or long-term debt securities in order to fund utility and business development capital expenditures. To help mitigate the effect of the negative economic and capital market trends referred to
above, we expect to manage costs, extend short-term debt maturities, maintain higher cash balances, increase the aggregate commitment amount under existing or new credit facilities as needed, and access capital markets to secure proceeds from the issuance of long-term securities for capital expenditure requirements. If we are unable to secure financing to fund certain strategic opportunities, we may look at potentially re-prioritizing the use of existing resources or consider delaying investments until market conditions improve.
We believe that, despite the current economic and credit market environment, our financial condition, including our liquidity position, is strong and we can access capital at reasonable costs. See Part I, Item 1A., "Risk Factors," above and "Financial Condition-Liquidity and Capital Resources," below.
Strategic Opportunities
Business Process Improvements. To address our economic and competitive challenges, we intend to re-assess business processes for continuous improvements. Our goal is to integrate, consolidate and streamline operations and support our employees with new technology tools that enable us to become more effective and efficient. In 2008, we implemented the first phase of our new enterprise resource planning (ERP) system, and in February 2009 we implemented the second phase. This new ERP system provides a comprehensive suite of business application software that interfaces with our existing customer information and automated dispatching systems. We expect this new ERP system to improve overall operating efficiencies by automating:
• the integration of systems and data;
• the control procedures with auditable financial and operational workflows; and
• certain areas of our monthly closing and financial reporting process.
In 2006, we automated the reading of gas meters on approximately one-third of our customers' meters. The meters equipped with this technology now electronically transmit usage data to receiving devices located in our vehicles as they are driven in the area, substantially reducing the labor costs associated with manually reading those customer meters. In 2008, we initiated a project to automate the reading of gas meters (AMR) for our remaining customers. The capital cost of this project is estimated to be $30 million, and in January 2009 we filed for regulatory recovery of this investment. Also in 2008, we initiated an automated dispatching system, which provides integrated planning and scheduling with global positioning system capabilities to more effectively collect and distribute data. These technology investments and other initiatives are expected to facilitate process improvements and contribute to long-term operational efficiencies throughout NW Natural.
Pipeline Diversification. Currently, we depend on a single interstate pipeline company to ship gas supplies to our system. Palomar Gas Transmission, LLC, (Palomar) is a wholly-owned subsidiary of Palomar Gas Holdings, LLC, (PGH). PGH is owned 50 percent by NW Natural and 50 percent by TransCanada Gas Transmission Northwest's (GTN). Palomar is seeking to build and operate a 217-mile natural gas transmission pipeline in Oregon to serve our utility and the growing markets in Oregon and other parts of the western United States. The Palomar pipeline would extend west from an interconnection with GTN's existing interstate transmission mainline near Madras, Oregon to an interconnection with NW Natural's gas distribution system near Molalla, Oregon and then extend further west to additional interconnections including a possible connection to one of the several liquefied natural gas (LNG) terminals proposed to be built on the Columbia River. Palomar would
diversify NW Natural's delivery options and enhance the reliability of service to our utility customers by providing an alternate transportation path for gas purchases from different regions in western Canada and the U.S. Rocky Mountains. Palomar would also provide our utility customers with access to a new source of gas supply if an LNG terminal is built on the Columbia River. The Palomar pipeline would be regulated by the FERC. In December 2008, Palomar filed for a Certificate of Public Convenience and Necessity with the FERC.
Palomar continues to work on the planning and permitting phase of the project, which is expected to extend through 2010. The total cost for planning and permitting is estimated to be between $40 million and $45 million, 50 percent of which is our investment based on our ownership interest. At December 31, 2008, the amount we had invested was $14.2 million. The total cost estimate for the entire 217-mile pipeline, if constructed, is estimated to be between $700 million and $800 million, with our current 50 percent share estimated at between approximately $350 million and $400 million. During 2009 and 2010, PGH will continue to evaluate market conditions and project status to determine if and when to proceed with construction of all or some portion of the project. Palomar has executed binding precedent agreements with shippers, including our own utility, for a majority of the current design capacity on the pipeline. These agreements also provide commitments of credit support to the project. We will continue to assess project risks and evaluate the project costs and fair value of our investment on a quarterly basis, including a valuation of the available credit support.
Gas Storage Development. In September 2007, we announced a joint project with Pacific Gas & Electric Company (PG&E) to develop an underground natural gas storage facility near Fresno, California. We formed a wholly-owned subsidiary, Gill Ranch, to plan, develop and operate the facility. In July 2008, Gill Ranch filed an application with the CPUC for a Certificate of Public Convenience and Necessity. In December 2008, the CPUC indicated that our application qualified for a Mitigated Negative Declaration, which allows an expedited review process. We expect to establish the application review schedule with the CPUC early in 2009 and to receive a decision on our application by the end of 2009. Gill Ranch will become subject to CPUC regulation regarding various matters including, but not limited to, securities issuances, lien grants and sales of property. We estimate our share of the total cost of this project to be between $160 and $180 million. Our share represents 75 percent of the total cost of the initial phase of storage development for an estimated 20 Bcf of gas storage capacity and approximately 27 miles of gas transmission pipeline during the 2008 to 2010 period. The initial phase of gas storage at Gill Ranch is currently scheduled to be in-service by late 2010.
Earnings and Dividends
Net income was $69.5 million, or $2.61 per share, for the year ended December 31, 2008, compared to $74.5 million, or $2.76 per share, and $63.4 million, or $2.29 per share, for the years ended December 31, 2007 and 2006, respectively. Returns on equity for these three years were 11.4 percent, 12.5 percent and 10.7 percent, respectively.
2008 compared to 2007:
Factors contributing to decreased earnings were:
• a $5.5 million loss in utility margin from our regulatory share of gas cost increases in 2008 compared to a margin gain of $12.1 million in 2007 from gas cost decreases;
• a $4.2 million decrease in utility margin from a lower customer surcharge related to regulatory adjustments for income taxes paid;
• a $2.9 million decrease in margin due to a temporary mark-to-market gain in 2007; and
• a $1.6 million decrease in utility margin from industrial customers due to weaker economic conditions.
Partially offsetting the above factors were:
• a $7.1 million increase in utility margin from higher sales volumes to residential and commercial customers due to colder weather and customer growth, after decoupling and weather mechanism adjustments;
• a $7.1 million decrease in operation and maintenance expense, partially due to higher costs in 2007 for strategic initiatives, and partially due to lower bonuses and employee benefit costs in 2008;
• a $3.4 million decrease in income tax expense due to lower taxable income;
• a $1.1 million after-tax gain from the sale of our investment in an aircraft leased to a commercial airline; and
• a $0.8 million increase in utility margin due to curtailment charges for use by a small number of industrial customers during cold weather.
2007 compared to 2006:
Positive factors contributing to increased earnings were:
• a $9.7 million increase in utility margin from higher sales volumes to residential and commercial customers due to customer growth;
• a $6.0 million increase in utility margin from a regulatory adjustment for income taxes paid;
• a $4.0 million increase in utility margin from our regulatory share of gas cost savings, up from $8.1 million in 2006 to $12.1 million in 2007;
• a $5.8 million increase in utility margin from temporary mark-to-market adjustments on derivative contracts, with a $2.9 million gain realized in 2007 and a $2.9 million loss realized in 2006; and
• a $4.2 million increase in margin from gas storage operations, due to an expansion of firm storage capacity and higher revenues sharing from asset optimization.
Partially offsetting the above positive factors were:
• a $3.9 million increase in depreciation expense, primarily related to increased utility plant in service;
• a $5.9 million increase in operations and maintenance expense due to higher bonuses tied to improved operating results and increases for certain strategic initiatives including utility maintenance projects and training; and
• a $7.8 million increase in income tax expense related to higher taxable income.
Dividends paid on our common stock were $1.52 a share in 2008, compared to $1.44 a share in 2007 and $1.39 a share in 2006. The current indicated annual dividend rate is $1.58 per share.
Application of Critical Accounting Policies and Estimates
In preparing our financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of
accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management's most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or used different assumptions. Our most critical estimates and judgments include accounting for:
• regulatory cost recovery and amortizations;
• revenue recognition;
• derivative instruments and hedging activities;
• pensions;
• income taxes; and
• environmental contingencies.
Management has discussed the estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board. Within the context of our critical accounting policies and estimates, management is not aware of any reasonably likely events or circumstances that would result in materially different amounts being reported. For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 1.
Regulatory Accounting
We are regulated by the OPUC and WUTC, which establish our utility rates and rules governing utility services provided to customers, and, to a certain extent, set forth the accounting treatment for certain regulatory transactions. In general, we use the same accounting principles as non-regulated companies reporting under GAAP. However, certain accounting principles, primarily Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," require different accounting treatment for regulated companies to show the effects of such regulation. For example, we account for the cost of gas using a PGA deferral and cost recovery mechanism, which is submitted for approval annually to the OPUC and WUTC (see "Results of Operations-Regulatory Matters-Rate Mechanisms," below). There are other expenses or revenues that the OPUC or WUTC may require us to defer for recovery or refund in future periods. SFAS No. 71 requires us to account for these types of deferred expenses (or deferred revenues) as regulatory assets (or regulatory liabilities) on the balance sheet. When we are allowed to recover these expenses from or required to refund them to customers, we recognize the expense or revenue on the income statement at the same time we realize the adjustment to amounts included in utility rates charged to customers.
The conditions we must satisfy to adopt the accounting policies and practices of SFAS No. 71, which are applicable to regulated companies, include:
• an independent regulator sets rates;
• the regulator sets the rates to cover specific costs of delivering service; and
• the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.
We continue to apply SFAS No. 71 in accounting for our regulated utility operations. Future regulatory changes or changes in the competitive environment could require us to discontinue the
application of SFAS No. 71 for some or all of our regulated businesses. This would require the write-off of those regulatory assets and liabilities that would no longer be probable of recovery from or refund to customers. Based on current regulatory and competitive conditions, we believe that it is reasonable to expect continued application of SFAS No. 71 for our regulated activities, and that all of our regulatory assets and liabilities at December 31, 2008 and 2007 are recoverable or refundable through future customer rates. See Note 1, "Industry Regulation."
Revenue Recognition
Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized when gas is delivered to and received by the customer. Revenues are accrued for gas delivered to customers, but not yet billed, based on estimates of gas deliveries from the last meter reading date to month end (accrued unbilled revenues). Accrued unbilled revenues are primarily based on a percentage estimate of our unbilled gas deliveries each month, which is dependent upon a number of factors, some of which require management's judgment. These factors include total gas receipts and deliveries, customer meter reading dates, customer usage patterns and weather. Accrued unbilled revenue estimates are reversed the following month when actual billings occur. Estimated unbilled revenues at December 31, 2008 and 2007 were $102.7 million and $78.0 million, respectively. The increase in accrued unbilled revenues at year-end 2008 was primarily due to higher volumes reflecting colder weather and higher gas prices included in customer rates. If the estimated percentage of unbilled volume at December 31, 2008 was adjusted up or down by 1 percent, then our unbilled revenues, net operating revenues and net income would have increased or decreased by an estimated $4.4 million, $0.4 million and $0.4 million, respectively.
Utility revenues may also include the recognition of a regulatory adjustment for . . .
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