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SPECTRA ENERGY PARTNERS, LP - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations.(Edgar Glimpses Via Acquire Media NewsEdge) INTRODUCTION Management's Discussion and Analysis should be read in conjunction with Item 8. Financial Statements and Supplementary Data. As the Express-Platte acquisition and the U.S. Assets Dropdown represented transfers of entities under common control, the Consolidated Financial Statements and related information presented herein have been recast to present results as if the related assets had been owned historically. As a result of these transactions, we realigned our reportable segments structure. Amounts presented herein for segment information have been recast for all periods presented to conform to our current segment reporting presentation. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the transactions. EXECUTIVE OVERVIEW During 2013, we successfully advanced one of our primary business strategies of actively engaging in the marketplace for strategic acquisitions of assets that enhance our portfolio. We accomplished this by completing two significant dropdowns of assets from Spectra Energy during 2013. On August 2, 2013, we acquired a 40% ownership interest in the Express US and a 100% ownership interest in Express Canada from Spectra Energy. On November 1, 2013, we completed the closing of the first transaction of the U.S. Assets Dropdown from Spectra Energy, which consisted of substantially all of Spectra Energy's remaining interests in its subsidiaries that own U.S. transmission and storage and liquids assets, including its remaining 60% interest in Express US. These dropdowns significantly increase our size, geographic footprint and asset mix. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the dropdowns. We reported net income from controlling interests of $1,070 million in 2013 compared with $580 million in 2012 and $570 million in 2011. Earnings increased mainly due to the elimination of deferred income tax liabilities related to the U.S. Assets Dropdown, which resulted in a tax benefit in 2013. Distributable cash flow was $315 million in 2013 compared with $229 million in 2012 and $212 million in 2011. We increased our quarterly cash distribution each quarter in 2013, from $0.495 per limited partner unit for the fourth quarter of 2012 which was paid in February 2013, to $0.54625 per unit for the fourth quarter of 2013 which was paid on February 28, 2014. With the closing of the U.S. Assets Dropdown, we increased our quarterly distribution paid by three cents per unit in the first quarter of 2014, and intend to increase our quarterly distribution by at least one cent per unit each quarter through 2015. The declaration and payment of distributions is subject to the sole discretion of our Board of Directors and depends upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints, our partnership agreement and other factors deemed relevant by our Board of Directors. We will rely upon cash flows from operations, including cash distributions received from our equity investments, and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for 2014. Given that we expect to continue to pursue expansion opportunities over the next several years, capital resources will continue to include long-term borrowings and possibly unit issuances. We expect to maintain an investment-grade capital structure and liquidity profile that supports our strategic objectives. Therefore, we will continue to monitor market requirements and our liquidity, and make adjustments to these plans, as needed. Our Strategy. Our strategy is to create superior and sustainable value for our investors, customers, employees and communities by delivering natural gas, liquids, and crude oil infrastructure to premium markets. We will grow our business through organic growth, greenfield expansions, and strategic acquisitions with a focus on safety, reliability and customer responsiveness and profitability. We intend to accomplish this by: •Building off the strength of our asset base •Maximizing that base through sector leading operations and service •Effectively executing the projects we have secured •Securing new growth opportunities that add value for our investors within each of our business segments •Expanding our value chain participation into complementary infrastructure assets 41-------------------------------------------------------------------------------- Table of Contents Natural gas supply dynamics continue to rapidly change and strengthen, and there is growing long-term potential for natural gas to be an effective solution for meeting the energy needs of North America. This causes us to be optimistic about future growth opportunities. Identified opportunities include natural gas-fired generation, growth in industrial markets, LNG exports from North America, and significant new liquids pipeline infrastructure. With our advantage of providing access from strong supply regions to growing natural gas, NGL and crude oil markets, we expect to continue expanding our assets and operations to meet these needs. Crude oil supply dynamics also continue to evolve as North American production increases. Growing North American crude oil production is displacing imports from overseas and driving increased demand for crude oil transportation and logistics. As such, we remain confident about our ability to grow our crude oil pipeline segment and capture future opportunities. Successful execution of our strategy will be determined by such key factors as the continued production and the consumption of natural gas, NGLs and crude oil within the U.S., our ability to provide creative solutions for customers energy needs as they evolve, and continued cost control and successful execution on capital projects. We continue to be actively engaged in the national discussions in the U.S. regarding energy policy and have taken a lead role in shaping policy as it relates to pipeline safety. Significant Economic Factors for Our Business. Our regulated businesses are generally economically stable and are not significantly affected in the short-term by changing commodity prices. However, all of our businesses can be negatively affected in the long term by sustained downturns in the economy or prolonged decreases in the demand for crude oil, natural gas and/or NGLs, all of which are beyond our control and could impair our ability to meet long-term goals. Most of our revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. Lower overall economic output would cause a decline in the volume of natural gas gathered and processed at our plants, resulting in lower earnings and cash flows. This decline would mostly affect gathering revenues, potentially in the short term. Transmission revenues could be affected by long-term economic declines that result in the non-renewal of long-term contracts at the time of expiration. Pipeline transportation and storage customers continue to renew most contracts as they expire. Our combined key natural gas markets-the northeastern and the southeastern United States-are projected to continue to exhibit higher than average annual growth in natural gas demand versus the North American and continental United States average growth rates through 2019. This demand growth is primarily driven by the natural gas-fired electric generation sector. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change is affecting our growth strategies. Traditionally, supply to our markets has come from the Gulf Coast region, both onshore and offshore. The national supply profile is shifting to new sources of gas from natural gas shale basins in the Rockies, Mid-Continent, Appalachia, Texas and Louisiana. These supply shifts are shaping the growth strategies that we will pursue, and therefore, will affect the nature of the projects anticipated in the capital and investment expenditure increases discussed below in "Liquidity and Capital Resources." Recent community and political pressures have arisen around the production processes associated with extracting natural gas from the natural gas shale basins. Although we continue to believe that natural gas will remain a viable energy solution for the U.S., these pressures could increase costs and/or cause a slowdown in the production of natural gas from these basins, and therefore, could negatively affect our growth plans. Our key crude oil markets include the Rocky Mountain and Midwest states with growing connectivity to the Gulf Coast and west coast of the United States. Growth in our business is dependent on growing crude oil supply from North American sources and the ability of that supply to displace imported crude oil from overseas. Any changes in market dynamics that adversely affect the availability and cost-competitiveness of North American crude oil supply would have a negative effect on our current business and associated growth opportunities. Natural gas storage prices have recently been challenged as a result of increasing natural gas supply and narrower seasonal price spreads. Gas supply and demand dynamics continue to change as a result of the development of new non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, there has been a shift to extracting gas in richer, "wet" gas areas, like the Marcellus shale. This has depressed activity in "dry" fields like the Fayetteville shale where our Ozark gathering and transmission assets are located. As the balance of supply and demand evolves, we expect activity in these areas to push prices higher. However, should the activity in the region continue to decline, our businesses there may be subject to possible impairment. The supply increase has also had a negative impact on the seasonal price spreads historically seen between the summer and winter months. As a result, the value of storage assets and contracts has declined in recent years, negatively affecting the results of our storage facilities. Should these market factors continue to keep 42-------------------------------------------------------------------------------- Table of Contents downward pressure on the seasonality spread and re-contracting, we could be subject to further reduced value and possible impairment of our storage assets. Our businesses in the United States and Canada are subject to regulations on the federal, state and provincial levels. Regulations applicable to the natural gas transmission, crude oil transportation and storage industries have a significant effect on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and we cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on our businesses. Additionally, investments and projects located in Canada expose us to risks related to Canadian laws, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of the Canadian government. During the past several years, the Canadian dollar has fluctuated compared to the U.S. dollar, which affected earnings to varying degrees for brief periods. Changes in the exchange rate or any other factors are difficult to predict and may affect our future results. Our strategic objectives include a critical focus on capital expansion projects that will require access to capital markets. An inability to access capital at competitive rates could affect our ability to implement our strategy. Market disruptions or a downgrade in our credit ratings may increase the cost of borrowings or affect our ability to access one or more sources of liquidity. During the past few years, capital expansion projects have been exposed to cost pressures associated with the availability of skilled labor, the pricing of materials and challenges associated with ensuring the protection of our environment and continual safety enhancements to our facilities. We maintain a strong focus on project management activities to address these pressures as we move forward with planned expansion opportunities. Significant cost increases could negatively affect the returns ultimately earned on current and future expansions. For further information related to management's assessment of our risk factors, see Part I. Item 1A. Risk Factors. RESULTS OF OPERATIONS 2013 2012 2011 (in millions) Operating revenues $ 1,965 $ 1,754 $ 1,746 Operating expenses 992 858 872 Gains on sales of other assets and other, net - 1 6 Operating income 973 897 880 Equity in earnings of unconsolidated affiliates 89 86 86 Other income and expenses, net 58 28 27 Interest income 1 1 1 Interest expense 383 407 408 Earnings before income taxes 738 605 586 Income tax expense (benefit) (348 ) 10 1 Net income 1,086 595 585 Net income-noncontrolling interests 16 15 15 Net income-controlling interests $ 1,070 $ 580 $ 570 2013 Compared to 2012 Operating Revenues. The $211 million increase was mainly driven by: • revenues from Express-Platte acquired in March 2013, and • higher revenues from expansion projects primarily at Texas Eastern, partially offset by • lower recoveries of electric power and other costs passed through to customers, • lower storage revenues, and • lower processing revenues associated with pipeline operations. 43-------------------------------------------------------------------------------- Table of Contents Operating Expenses. The $134 million increase was driven by: • operating costs from Express-Platte, • expansion projects primarily at Texas Eastern, • higher governance cost, • higher depreciation due to the acquisition of Express-Platte and expansion projects, • higher employee benefit costs, ad valorem taxes, net of lower software amortization, and • transaction costs related to the U.S. Assets Dropdown, partially offset by • lower electric power and other costs passed through to customers. Other Income and Expenses, Net. The $30 million increase was primarily due to higher allowance for funds used during construction (AFUDC) resulting from increased capital spending on expansion projects. Income Tax Expense (Benefit). Deferred income tax liabilities were eliminated and recorded as a benefit to Income Tax Expense (Benefit) in connection with the U.S. Assets Dropdown and resulting changes in tax status of certain entities. 2012 Compared to 2011 Operating Revenues. The $8 million increase was driven by: • revenues from Big Sandy acquired in July 2011, • higher revenues from expansion projects, and • higher recoveries of electric power and other costs passed through to customers, partially offset by • lower storage revenues, • contract reductions at Ozark Gas Transmission and Texas Eastern, and • lower processing revenues associated with pipeline operations caused by lower prices. Operating Expenses. The $14 million decrease was driven by: • lower equipment repairs and maintenance expenses, pipeline integrity costs, employee benefits and other costs, and • lower project development costs, partially offset by • higher depreciation from expansion projects and the acquisition of Big Sandy in July 2011 and • higher electric power and other costs passed through to customers. Other Income and Expenses, Net. The $1 million increase was primarily due to higher AFUDC resulting from increased capital spending on expansion projects. For a more detailed discussion of earnings drivers, see the segment discussions that follow. Segment Results Management evaluates segment performance based on consolidated EBITDA. Cash, cash equivalents and investments are managed centrally, so the gains and losses on foreign currency remeasurement, and interest and dividend income, are excluded from the segments' EBITDA. We consider segment EBITDA to be a good indicator of each segment's operating performance from its continuing operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner. Our U.S. Transmission business primarily provides transmission and storage of natural gas for customers in various regions of the northeastern and southeastern United States. Our Liquids business primarily provides transportation of oil and NGLs for customers in central and southern United States and Canada. 44-------------------------------------------------------------------------------- Table of Contents Segment EBITDA is summarized in the following table. Detailed discussions follow. EBITDA by Business Segment 2013 2012 2011 (in millions) U.S. Transmission $ 1,279 $ 1,251 $ 1,223 Liquids 132 - - Total reportable segment EBITDA 1,411 1,251 1,223 Other (27 ) (9 ) (9 ) Total reportable segment and other EBITDA 1,384 1,242 1,214 Depreciation and amortization 262 231 221 Interest expense 383 407 408 Interest income and other (1 ) 1 1Earnings from continuing operations before income taxes $ 738 $ 605 $ 586 The amounts discussed below are after eliminating intercompany transactions. U.S. Transmission Increase 2013 2012 (Decrease) 2011 Increase (Decrease) (in millions) Operating revenues $ 1,727 $ 1,754 $ (27 ) $ 1,746 $ 8 Operating expenses Operating, maintenance and other 594 618 (24 ) 642 (24 ) Other income and expenses 146 114 32 113 1 Gains on sales of other assets and other, net - 1 (1 ) 6 (5 ) EBITDA $ 1,279 $ 1,251 $ 28 $ 1,223 $ 28 2013 Compared to 2012 Operating Revenues. The $27 million decrease was driven by: • a $42 million decrease in recoveries of electric power and other costs passed through to customers, • a $24 million decrease due to lower storage revenues as a result of lower contract renewal rates, and • an $8 million decrease from lower processing revenues associated with pipeline operations, partially offset by • a $48 million increase from expansion projects primarily at Texas Eastern. Operating Expenses. The $24 million decrease was driven by: • a $42 million decrease in electric power and other costs passed through to customers, partially offset by • a $6 million increase from expansion projects primarily at Texas Eastern, and • a $10 million increase due to higher employee benefit costs and ad valorem taxes, net of lower software amortization. Other Income and Expenses. The $32 million increase was primarily due to higher AFUDC resulting from increased capital spending on expansion projects. EBITDA. The $28 million increase was driven by higher earnings from the expansions at Texas Eastern partially offset by lower storage revenues, higher operating costs, and lower processing revenues. 45-------------------------------------------------------------------------------- Table of Contents 2012 Compared to 2011 Operating Revenues. The $8 million increase was driven by: • a $51 million increase from expansion projects and the acquisition of Big Sandy in July 2011, and • a $12 million increase in recoveries of electric power and other costs passed through to customers, partially offset by • a $29 million decrease from lower storage revenues and contract reductions at Texas Eastern and Ozark Gas Transmission, and • a $24 million decrease in processing revenues associated with pipeline operations caused by lower prices. Operating Expenses. The $24 million decrease was driven by: • a $32 million decrease due to lower equipment repair and maintenance expenses, pipeline integrity costs, employee benefits and other costs, net of accelerated software amortization, and • a $6 million decrease from project development costs expensed in 2011, partially offset by • a $12 million increase in electric power and other costs passed through to customers. Gains on Sales of Other Assets and Other, net. The $5 million decrease was driven by 2011 customer settlements. EBITDA. The $28 million increase was driven by increased earnings from expansions and lower operating costs, partially offset by expected lower storage revenues, contract reductions at Texas Eastern and Ozark Gas Transmission and lower processing revenues associated with pipeline operations. Matters Affecting Future U.S. Transmission Results We plan to continue earnings growth through capital efficient projects, such as transportation and storage expansion to support a two-pronged "supply push" / "market pull" strategy, as well as continued focus on optimizing the performance of the existing operations through organizational efficiencies and cost control. "Supply push" is when producers agree to pay to transport specified volumes of natural gas in order to support the construction of new pipelines or the expansion of existing pipelines. "Market pull" is taking gas away from established liquid supply points and building pipeline transportation capacity to satisfy end-user demand in new markets or demand growth in existing markets. Future earnings growth will be dependent on the success of our expansion plans in both the market and supply areas of the pipeline network, which includes, among other things, shale gas exploration and development areas, the ability to continue renewing service contracts and continued regulatory stability. Natural gas storage prices have recently been challenged as a result of increasing natural gas supply and narrower seasonal price spreads. As a result, the value of storage assets and contracts has declined in recent years, negatively affecting the results of our storage facilities. Should these market factors continue to keep downward pressure on the seasonality spread and re-contracting, we could be subject to further reduced value and possible impairment for our storage assets. Our interstate pipeline operations are subject to pipeline safety regulation administered by PHMSA of the U.S. Department of Transportation. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. In January 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act amends the Pipeline Safety Act in a number of significant ways, including: • Authorizing PHMSA to assess higher penalties for violations of its regulations, • Requiring PHMSA to adopt appropriate regulations within two years requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities and to perform a study on the application of such technology to existing pipeline facilities in HCAs, • Requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days, • Requiring PHMSA to study and report on the adequacy of soil cover requirements in HCAs, and • Requiring PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply). In 2011, PHMSA initiated an Advance Notice of Proposed Rulemaking announcing its consideration of substantial revisions in its regulations to increase pipeline safety. PHMSA also has issued an Advisory Bulletin which among other things, 46-------------------------------------------------------------------------------- Table of Contents advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. These legislative and regulatory changes, when implemented, will impose additional costs on new pipeline projects as well as on existing operations. Because the extent of the new requirements and the timing of their application is still uncertain, we cannot reasonably determine the effects these changes will have on our operations, earnings, financial condition and cash flows at this time. Liquids Increase 2013 2012 (Decrease) 2011 Increase (Decrease) (in millions) Operating revenues $ 238 $ - $ 238 $ - $ - Operating expenses Operating, maintenance and other 109 - 109 - - Other income and expenses 3 - 3 - - EBITDA $ 132 $ - $ 132 $ - $ - Express pipeline receipts, MBbl/d (a,b) 207 - 207 - - Platte PADD II deliveries, MBbl/d (b) 168 - 168 - - _________ (a) Thousand barrels per day. (b) Data includes activity since March 14, 2013, the date of the acquisition of Express-Platte by Spectra Energy. Our Liquids segment is comprised of Express-Platte and our investments in Sand Hills and Southern Hills. Results of Express-Platte represent results since March 14, 2013, the date of Spectra Energy's acquisition. Results of Sand Hills and Southern Hills represent results since November 15, 2012, the date of Spectra Energy's acquisition of both entities. 2013 Compared to 2012 Operating Revenues. The $238 million increase was attributable to Express-Platte. Operating Expenses. The $109 million increase was attributable to Express-Platte. Other Income and Expenses. The $3 million increase was attributable to our equity earnings in Sand Hills and Southern Hills. EBITDA. The $132 million increase was primarily driven by the earnings from Express-Platte. Matters Affecting Future Liquids Results We plan to continue earnings growth by maximizing throughput on all sections of the pipeline systems. On the Express-Platte system, this entails connecting where possible to rail or barge terminals to extend the market reach of the pipeline to refinery-customers beyond the end of the pipeline. This also includes optimizing pipeline and storage operations and expanding terminal operations where appropriate. On the Southern Hills and Sand Hills NGL pipelines, volumes will continue to increase as NGL supply increases behind the system and new extraction plants are connected to the pipeline. Extensions may be added to the lines and pumps may be added to increase capacity. Future earnings growth will be dependent on the success in renewing existing contracts or in securing new supply and market for all pipelines. This will require ongoing increases in supply of both crude oil and NGL and continued access to attractive markets. For the NGL pipelines, continued growth is dependent on successful execution of expansion projects to attach new supply. See Matters Affecting Future U.S. Transmission Results for discussions of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PHMSA, which are also applicable to the Liquids segment. 47-------------------------------------------------------------------------------- Table of Contents Other 2013 2012 Increase (Decrease) 2011 Increase (Decrease) (in millions) Operating expenses $ 27 $ 9 $ 18 $ 9 $ - EBITDA $ (27 ) $ (9 ) $ (18 ) $ (9 ) $ - 2013 Compared to 2012 Operating Expenses. The $18 million increase was driven by higher governance costs and transaction costs related to the U.S. Assets Dropdown, which was effective on November 1, 2013. Distributable Cash Flow We define Distributable Cash Flow as EBITDA plus • net cash from equity investments, less • interest expense, • equity AFUDC, • distributions to noncontrolling interests, and • maintenance capital expenditures, excluding the effect of reimbursable projects. Distributable Cash Flow does not reflect changes in working capital balances. Distributable Cash Flow should not be viewed as indicative of the actual amount of cash that we plan to distribute for a given period. Distributable Cash Flow is the primary financial measure used by our management and by external users of our financial statements to assess the amount of cash that is available for distribution. The effects of the U.S. Assets Dropdown and the Express-Platte acquisition have been excluded from the Distributable Cash Flow calculation for periods prior to the dropdown transactions in order to reflect the true amount of the cash that was available for distribution. Distributable Cash Flow is a non-GAAP measure and should not be considered an alternative to Net Income, Operating Income, cash from operations or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles (GAAP) in the United States. Distributable Cash Flow excludes some, but not all, items that affect Net Income and Operating Income and these measures may vary among other companies. Therefore, Distributable Cash Flow as presented may not be comparable to similarly titled measures of other companies. Significant drivers of variances in Distributable Cash Flow between the periods presented are substantially the same as those previously discussed under Results of Operations. Other drivers include the timing of certain cash outflows, such as capital expenditures for maintenance. 48-------------------------------------------------------------------------------- Table of Contents Reconciliation of Net Income to Non-GAAP "Distributable Cash Flow" 2013 2012 2011 (in millions) Net Income $ 1,086 $ 595 $ 585 Add: Interest expense 383 407 408 Income tax expense (benefit) (a) (348 ) 10 1 Depreciation and amortization 262 231 221 Foreign currency loss 2 - - Less: Interest income 1 1 1 EBITDA 1,384 1,242 1,214 Add: Net cash from equity investments 28 19 21 Less: Interest expense 383 407 408 Distributions to noncontrolling interests 19 18 18 Maintenance capital expenditures 228 241 258 Equity AFUDC 58 27 17 Adjustment (b) 409 339 322 Distributable Cash Flow $ 315 $ 229 $ 212 ________(a) Tax benefit in 2013 is due to the elimination of deferred income tax liabilities related to the U.S. Assets Dropdown. (b) Removes the results of the U.S. Assets Dropdown for the periods prior to the dropdown (January 1, 2011 to October 31, 2013) and the results of Express-Platte for the periods prior to the dropdown (March 14, 2013 to August 1, 2013). CRITICAL ACCOUNTING POLICIES AND ESTIMATES The application of accounting policies and estimates is an important process that continues to evolve as our operations change and accounting guidance is issued. We have identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments. We base our estimates and judgments on historical experience and on other various assumptions that we believe are reasonable at the time of application. These estimates and judgments may change as time passes and more information becomes available. If estimates are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. We discuss our critical accounting policies and estimates and other significant accounting policies with our Audit Committee. Regulatory Accounting We account for certain of our operations under accounting for regulated entities. As a result, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. We continually assess whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this assessment, we believe our existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, regulatory asset write-offs would be required to be recognized. Additionally, regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment and amortization of regulatory assets. Total regulatory assets were $254 million as of December 31, 2013 and $212 million as of December 31, 2012. Total regulatory liabilities were $66 million as of December 31, 2013 and $62 million as of December 31, 2012. 49-------------------------------------------------------------------------------- Table of Contents Impairment of Goodwill We had goodwill balances of $3.2 billion at December 31, 2013 and $2.8 billion at December 31, 2012. The increase in goodwill in 2013 was primarily the result of the Express-Platte acquisition. As permitted under the accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management's judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts. In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine fair values of those reporting units. The long-term growth rate used for our quantitative assessment reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America, increasing demand for natural gas transmission capacity on our pipeline systems primarily as a result of forecasted growth in natural gas-fired power plants and increasing demand for crude oil and NGL transportation capacity on our pipeline systems. We assumed a long-term growth rate of 2.5% for our 2013 quantitative goodwill impairment analysis. Had we assumed a 100 basis point lower growth rate for the reporting unit that we quantitatively assessed, there would have been no impairment of goodwill. We continue to monitor the effects of the global economic downturn with respect to the long-term cost of capital utilized to calculate our reporting units' fair values. For our 2013 quantitative goodwill impairment analysis, we assumed weighted-average costs of capital of 5.4% that market participants would use. Had we assumed a 100 basis point increase in the weighted-average cost of capital for the reporting unit that we quantitatively assessed, there would have been no impairment of goodwill. Based on the results of our annual goodwill impairment testing, no indicators of impairment were noted and the fair values of our reporting units at April 1, 2013 (our testing date) were substantially in excess of their carrying values. No triggering events or changes in circumstances occurred during the period April 1, 2013 through December 31, 2013 that would warrant re-testing for goodwill impairment. Revenue Recognition Revenues from the transmission, storage and gathering of natural gas, and from the transportation of crude oil are generally recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial. LIQUIDITY AND CAPITAL RESOURCES Known Trends and Uncertainties As of December 31, 2013, we had negative net working capital of $770 million. This balance includes commercial paper liabilities of $338 million and current maturities of long-term debt of $445 million. We will rely upon cash flows from operations, including cash distributions received from our equity affiliates, and various financing transactions, which may include issuances of debt and/or equity securities, to fund our liquidity and capital requirements for 2014. We have access to a revolving credit facility, with available capacity of $1.7 billion at December 31, 2013. This facility is used principally to back-stop our commercial paper program, which is used to manage working capital requirements and for temporary funding of our capital expenditures. We expect to be self-funding and plan to continue to pursue expansion opportunities over the next several years. Capital resources may continue to include commercial paper, short-term borrowings under our current credit facility and possibly securing additional sources of capital including debt and/or equity. Cash flows from operations are fairly stable given that most of our revenues and those of our equity affiliates are derived from operations under firm contracts. However, total operating cash flows are subject to a number of factors, including, but not limited to, contract renewal rates and cash distributions from our equity affiliates. The amount of cash distributed to us by our equity affiliates and the amount of cash we may be required to fund, is determined by our equity affiliates based on their operating cash flows and other factors as determined by their management. While we participate on the management committees of these equity affiliates, determination of the amount of distributions and contributions, if any, are not within our control. We received total distributions from equity affiliates of $180 million in 2013, $106 million in 2012 and $107 million in 2011. See Item 1A. Risk Factors for discussion of other factors that could affect our cash flows. 50-------------------------------------------------------------------------------- Table of Contents As a result of our ongoing strong earnings performance expected in existing operations, we expect to maintain a capital structure and liquidity profile that supports our strategic objectives. We will continue to monitor market requirements and our liquidity and make adjustments to these plans, as needed. Cash Flow Analysis The following table summarizes the changes in cash flows for each of the periods presented: 2013 2012 2011 (in millions) Net cash provided by (used in): Operating activities $ 1,029 $ 891 $ 761 Investing activities (3,689 ) (1,880 ) (901 ) Financing activities 2,733 1,016 110 Net increase (decrease) in cash and cash equivalents 73 27 (30 ) Cash and cash equivalents at beginning of the period 48 21 51 Cash and cash equivalents at end of the period $ 121 $ 48 $ 21 Operating Cash Flows Net cash provided by operating activities increased $138 million to $1,029 million in 2013 compared to 2012. This increase was driven primarily by: •earnings related to the acquisition of Express-Platte in 2013. Net cash provided by operating activities increased $130 million to $891 million in 2012 compared to 2011. This increase was primarily due to: •changes in working capital. Investing Cash Flows Net cash flows used in investing activities increased $1,809 million to $3,689 million in 2013 compared to 2012. This increase was driven mainly by: •a $2,234 million increase in acquisitions in 2013, partially offset by •a $144 million decrease in capital and investment expenditures in 2012, and • $141 million of net proceeds from available-for-sale securities in 2013 compared to $141 million of net purchases in 2012. Net cash flows used in investing activities increased $979 million to $1,880 million in 2012 compared to 2011. This increase was driven mainly by: • $141 million of net purchases of available-for-sale securities in 2012 compared to $202 million of net proceeds in 2011, and • a $697 million increase in capital and investment expenditures in 2012, primarily the initial investment in Sand Hills and Southern Hills, partially offset by • a $319 million net cash outlay for the acquisition of M&N US in 2012 compared to a $390 million net cash outlay for the acquisition of Big Sandy in 2011. 51-------------------------------------------------------------------------------- Table of Contents Capital and Investment Expenditures by Business Segment 2013 2012 2011 (in millions) U.S. Transmission (a) $ 1,000 $ 930 $ 746 Liquids (b) 299 513 - Total consolidated $ 1,299 $ 1,443 $ 746 _________(a) Excludes the $2,210 million net cash outlay for the U.S. Assets Dropdown in 2013 and the $390 million acquisition of Big Sandy in 2011. (b) Excludes the $343 million net cash outlay for the acquisition of Express-Platte in 2013. Capital and investment expenditures for 2013 totaled $1,299 million and included $1,078 million for expansion projects and $221 million for maintenance and other projects. We project 2014 capital and investment expenditures of approximately $1.2 billion, including $0.9 billion of expansion capital expenditures and $0.3 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. Given our objective of growth through acquisitions, we anticipate that we will continue to invest significant amounts of capital to acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities. On August 2, 2013, we acquired a 40% ownership interest in Express US and a 100% ownership interest in Express Canada from subsidiaries of Spectra Energy for $410 million in cash and 7.2 million of newly issued common and general partner units. See Note 2 of Notes to Consolidated Financial Statements for further discussion. On November 1, 2013, we completed the closing of substantially all of the U.S. Assets Dropdown, including Spectra Energy's remaining 60% interest in the U.S. portion of Express-Platte. We paid Spectra Energy aggregate consideration with the issuance of approximately 171.1 million newly issued partnership units and $ 2.3 billion in cash. See Note 2 of Notes to Consolidated Financial Statements for further discussion. In October 2012, we acquired a 39% ownership interest in M&N US from Spectra Energy for approximately $319 million in cash and approximately $56 million in newly issued common and general partner units. See Note 2 of Notes to Consolidated Financial Statements for further discussion. In July 2011, we completed the acquisition of Big Sandy for approximately $390 million in cash. See Note 2 of Notes to Consolidated Financial Statements for further discussion. Capital expansion projects are developed and executed using results-proven project management processes. We evaluate the strategic fit and commercial and execution risks, and continuously measure performance compared to plan. Ongoing communications between project teams and senior leadership ensure we maintain the right focus and deliver the expected results. We expect that significant natural gas infrastructure, including both natural gas transportation and storage with links to growing gas supplies and markets, will be needed over time to serve growth in gas-fired power generation, oil-to-gas conversions, industrial development and attachments to new gas supply. Expansion capital expenditures included several key projects placed into service in 2013, including: • New Jersey-New York Expansion-An 800 million cubic feet per day (MMcf/d) expansion of the Texas Eastern pipeline system consisting of a new 16-mile pipeline extension into lower Manhattan, New York and other associated facility upgrades. The project is designed to transport gas produced in the U.S. Gulf Coast, Mid-Continent, Rockies and Marcellus Shale regions into New York City and was placed into service during the fourth quarter of 2013. • Sand Hills-Approximately 720 miles of NGL pipeline constructed by DCP Midstream, with an initial capacity of 200,000 Bbls/d, transporting NGLs from Permian Basin and Eagle Ford shale regions to NGL markets on the Gulf Coast. Phase I was completed in the fourth quarter of 2012, with initial service from Eagle Ford shale region to Mont Belvieu. Phase II provides service from the Permian Basin to the Eagle Ford shale region. This project was placed into service during the second quarter of 2013. • Southern Hills-Approximately 800 miles of NGL pipeline also constructed by DCP Midstream, connecting several DCP Midstream processing plants and anticipated third-party producers, providing NGL transportation from the Mid-Continent to Mont Belvieu. This project was placed into service during the second quarter of 2013. 52-------------------------------------------------------------------------------- Table of Contents Significant 2014 expansion projects expenditures are expected to include: • TEAM 2014-A 600 MMcf/d expansion of the Texas Eastern pipeline system consisting of new pipeline construction. The project is designed to transport gas produced in the Marcellus Shale to U.S. markets in the northeast, midwest and Gulf Coast. In-service is scheduled by the second half of 2014. • Kingsport-An additional 86 MMcf/d on the East Tennessee system to support a customer's multi-year project to convert five coal-fired power plant boilers to natural gas. Approximately 25 MMcf/d of the project was placed in service in November 2013 and the remainder is scheduled to be in-service in the first quarter of 2015. • OPEN-A 550 MMcf/d expansion of the Texas Eastern pipeline system consisting of new pipeline, a new compressor station and other associated facility upgrades. The project is designed to transport gas produced in the Utica Shale and Marcellus Shale to U.S. markets in the Midwest, Southeast and Gulf Coast. In-service is scheduled for the fourth quarter of 2015. • Sabal Trail-A 1,100 MMcf/d of new capacity to access onshore shale gas supplies. Facilities include a new 465-mile pipeline, laterals and various compressor stations. In-service is expected by the second quarter of 2017. • AIM-A 342 MMcf/d expansion of the Algonquin system consisting of replacement pipeline, new pipeline, new and modified meter station facilities and additional compression at existing stations. The project is designed to transport gas from existing interconnects in New Jersey and New York to LDC marked in the northeast. In-service is expected by the fourth quarter of 2016. Financing Cash Flows Net cash provided by financing activities increased $1,717 million to $2,733 million in 2013 compared to 2012. This change was driven mainly by: • a $1,682 million net increase in long-term debt issuances in 2013 compared to 2012, mostly to fund the U.S. Assets Dropdown from Spectra Energy, • $523 million of net contributions from parent in 2013 compared to $240 million of net contributions in 2012, and • a $69 million increase in proceeds from issuance of units in 2013, partially offset by • a $307 million net decrease in proceeds from issuances of commercial paper in 2013. Net cash provided by financing activities increased $906 million to $1,016 million in 2012 compared to 2011. This change was driven mainly by: •a $299 million decrease in 2011 of our revolving credit facility borrowings outstanding, •a $288 million net increase in long term debt issuances in 2012, •$240 million of net contributions from parent in 2012 compared to a $109 million of net contributions in 2011, and •a $282 million increase in proceeds from issuances of commercial paper in 2012, partially offset by •a $70 million decrease in proceeds from the issuance of units in 2012. Significant Financing Activities-2013 Debt Issuances. The following long-term debt issuances were completed during 2013 to fund a portion of the cash consideration for the U.S. assets acquisition from Spectra Energy which closed on November 1, 2013: Amount Interest Rate Due Date (in millions) Spectra Energy Partners, LP $ 1,000 4.75 % 2024 Spectra Energy Partners, LP 500 2.95 % 2018 Spectra Energy Partners, LP 400 5.95 % 2043 Spectra Energy Partners, LP 400 variable 2018 Common Unit Issuances. On November 1, 2013, we issued 167.6 million common units and 3.4 million general partner units to Spectra Energy in connection with the U.S. Assets Dropdown, valued at $7.4 billion. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the U.S. Assets Dropdown. 53-------------------------------------------------------------------------------- Table of Contents In November 2013, we entered into an equity distribution agreement under which we may sell and issue common units up to an aggregate amount of $400 million. The continuous offering program allows us to offer and sell common units, representing limited partner interests, at prices deemed appropriate through a sales agent. Sales of common units, if any, will be made by means of ordinary brokers' transactions on the New York Stock Exchange, in block transactions, or as otherwise agreed to between the sales agent and us. We intend to use the net proceeds from sales under the program for general partnership purposes, which may include debt repayment, future acquisitions, capital expenditures and additions to working capital. Beginning in November, we issued 0.6 million common units to the public in 2013 under this program, for total net proceeds of $24 million. In August 2013, we issued 7.1 million common units and 0.1 million general partner units to Spectra Energy in connection with the acquisition of Express-Platte, valued at $319 million. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the acquisition of Express-Platte. In April 2013, we issued 5.2 million common units to the public representing limited partner interests and 0.1 million general partner units. The net proceeds from this offering were $193 million. The net proceeds from this issuance were temporarily invested in restricted available-for-sale securities until the Express-Platte dropdown, at which time the funds were partially used to pay for a portion of the transaction. See Note 2 of Notes to Consolidated Financial Statements for a discussion of the Express-Platte transaction. Significant Financing Activities-2012 Debt Issuances. The following long-term debt issuances were completed during 2012: Amount Interest Rate Due Date (in millions) Algonquin $ 350 3.51 % 2024 Texas Eastern 500 2.80 % 2022 East Tennessee 200 3.10 % 2024 Common Unit Issuance. In November 2012, we issued 5.5 million common units to the public representing limited partner interests, and 0.1 million general partner units to Spectra Energy. The total net proceeds from this offering were $148 million and were restricted for the purpose of funding capital expenditures and acquisitions. Significant Financing Activities-2011 Debt Issuances. The following long-term debt issuances completed during 2011: Amount Interest Rate Due Date (in millions) Spectra Energy Partners, LP $ 250 2.95 % 2016 Spectra Energy Partners, LP 250 4.60 % 2021 Common Unit Issuance. In June 2011, we issued 7.2 million common units to the public, representing limited partner interests, and 0.1 million general partner units to Spectra Energy. Total net proceeds of $218 million were used to fund a portion of the acquisition of Big Sandy. Available Credit Facility and Restrictive Debt Covenants Commercial Total Paper Outstanding at Available Expiration Credit Facility December 31, Credit Facility Date Capacity 2013 Capacity (in millions) Spectra Energy Partners, LP 2018 $ 2,000 $ 338 $ 1,662 On November 1, 2013, we amended and restated our credit agreement. The credit facility was increased to $2.0 billion and expires in 2018. 54-------------------------------------------------------------------------------- Table of Contents The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facility. As of December 31, 2013, there were no letters of credit issued under the credit facility or revolving borrowings outstanding. The credit agreement contains various covenants, including the maintenance of consolidated leverage ratio, as defined in the agreement. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreement. As of December 31, 2013, we were in compliance with those covenants. In addition, the credit agreement allows for the acceleration of payments or termination of the agreement due to nonpayment, or in some cases, due to the acceleration of our other significant indebtedness of us or of some of our subsidiaries. The credit agreement does not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations. As noted above, the terms of the amended and restated credit agreement requires us to maintain a consolidated leverage ratio of consolidated indebtedness to consolidated earnings before interest, taxes, depreciation and amortization, as defined in the agreement, of 5.0 or less, provided that for three fiscal quarters subsequent to certain acquisitions (such as the November 1, 2013 U.S. Assets Dropdown from Spectra Energy), the ratio may be 5.5 or less. As of December 31, 2013, the consolidated leverage ratio was 4.4 after giving effect to the impact of the U.S, Assets Dropdown. Term Loan Agreement. On November 1, 2013, we entered into and borrowed $400 million under a senior unsecured five-year term loan agreement. A portion of the proceeds from the borrowing was used to pay Spectra Energy for the U.S. Assets Dropdown. Cash Distributions. The partnership agreement requires that, within 60 days after the end of each quarter, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date. We increased the quarterly cash distributions each quarter of 2013 from $0.495 per limited partner unit for the fourth quarter of 2012 to $0.54625 per limited partner unit for the fourth quarter of 2013, or 10%. The cash distribution for the fourth quarter of 2013 was declared on February 4, 2014 and was paid on February 28, 2014. Our Board of Directors evaluates each individual quarterly distribution decision based on an assessment of growth in cash available to make distributions. Growth in our cash available to make distributions over time is dependent on incremental organic growth expansion, third-party acquisitions or acquisitions from Spectra Energy. Our amount of Available Cash depends primarily upon our cash flows, including cash flow from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes. Other Financing Matters. We have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units and various debt securities and another registration statement on file with the SEC to register the issuance of $500 million, in the aggregate, of limited partner units and various debt securities over time. This registration statement has $476 million available as of December 31, 2013. Off Balance Sheet Arrangements We do not have any off-balance sheet financing entities or structures with third parties, except for normal operating lease arrangements and financings entered into by equity investment pipeline operations. These debt obligations do not contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings. Contractual Obligations We enter into contracts that require payment of cash at certain periods based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Total Current Liabilities on the December 31, 2013 Consolidated Balance Sheet other than Current Maturities of Long-Term Debt. It is expected that the majority of these current liabilities will be paid in cash in 2014. 55-------------------------------------------------------------------------------- Table of Contents Contractual Obligations as of December 31, 2013 Payments Due by Period 2015 & 2017 & 2019 & Total 2014 2016 2018 Beyond (in millions) Long-term debt, including current maturities (a) $ 8,155 $ 671 $ 742 $ 1,696 $ 5,046 Operating leases (b) 161 15 30 24 92 Purchase obligations (c) 180 150 30 - - Total contractual cash obligations $ 8,496 $ 836 $ 802 $ 1,720 $ 5,138 _________ (a) See Note 13 of Notes to Consolidated Financial Statements. Amounts include estimated scheduled interest payments over the life of the associated debt. (b) See Note 16. (c) Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table. Quantitative and Qualitative Disclosures About Market Risk We are exposed to market risks associated with interest rates and credit exposure. We have established comprehensive risk management policies to monitor and manage these market risks. Spectra Energy is responsible for the overall governance of managing our interest rate risk and credit risk, including monitoring exposure limits. Credit Risk Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. Our exposure generally relates to receivables and unbilled revenue for services provided, as well as volumes owed by customers for imbalances or gas loaned by us generally under park and loan services and no-notice services. Our principal customers for natural gas transmission, storage and gathering services are industrial end-users, marketers, exploration and production companies, LDCs and utilities located throughout the United States. The principal customers for our integrated oil transportation pipeline are Canadian and United States producers that use Express-Platte to connect to refineries located in the U.S. Rocky Mountain and Midwest regions. We have concentrations of receivables from these industry sectors. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the customers' financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We also obtain parental guarantees, cash deposits or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract. Approximately 90% of our credit exposures for transmission, storage and gathering services are either with customers who have an investment-grade rating (or the equivalent based on an evaluation by Spectra Energy), or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers' creditworthiness. As a result of future capital projects for which natural gas producers may be the primary customer, the percentage of our customers who are rated investment-grade may decline. We had no net exposure to any customer that represented greater than 10% of the gross fair value of trade accounts receivable at December 31, 2013. We manage cash to maximize value while assuring appropriate amounts of cash are available, as required. We typically invest our available cash in high-quality money market securities. Such money market securities are designed for safety of principal and liquidity, and accordingly, do not include equity-based securities. Based on our policies for managing credit risk, our exposures and our credit and other reserves, we do not anticipate an adverse effect on our consolidated results of operations or financial position as a result of non-performance by any customer. Interest Rate Risk We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total debt and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, 56-------------------------------------------------------------------------------- Table of Contents but not limited to, interest rate swaps to manage and mitigate interest rate risk exposure. At December 31, 2013, there were no interest rate swaps outstanding. See also Notes 1, 13 and 15 of Notes to Consolidated Financial Statements. Based on a sensitivity analysis as of December 31, 2013, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2014 than in 2013, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $6 million. Comparatively, based on a sensitivity analysis as of December 31, 2012, had short-term interest rates averaged 100 basis points higher (lower) in 2013 than in 2012, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by $8 million. These amounts were estimated by considering the effect of the hypothetical short-term interest rates on variable-rate debt outstanding, adjusted for interest rate hedges, investments, and cash and cash equivalents outstanding as of December 31, 2013 and 2012. OTHER ISSUES Global Climate Change. Policymakers at regional, federal, provincial and international levels continue to evaluate potential legislative and regulatory compliance mechanisms to achieve reductions in global GHG emissions in an effort to address the challenge of climate change. Certain of our assets and operations are subject to direct and indirect effects of current global climate change regulatory actions in their respective jurisdictions, and it is likely that other assets and operations will become subject to direct and indirect effects of current and possible future global climate change regulatory actions. The current international climate framework, the United Nations-sponsored Kyoto Protocol, prescribes specific targets to reduce GHG emissions for developed countries for the 2008-2012 period. The Kyoto Protocol expired in 2012 and had not been ratified by the United States. United Nations-sponsored international negotiations were held in Warsaw, Poland in November 2013 to continue laying the groundwork for a new global agreement on climate action to come into effect by 2020. An agreement was reached at the 2012 climate negotiations to amend the Kyoto Protocol extending it to 2020 when a potential new agreement could take effect. In 2011, the Canadian government withdrew from the Kyoto Protocol. In 2008, the Canadian government outlined a regulatory framework mandating GHG reductions from large final emitters. Regulatory design details from the Canadian government remain forthcoming. The materiality of any potential compliance costs is unknown at this time as the final form of the regulation and compliance options have yet to be determined by policymakers In 2007, the province of Alberta adopted legislation which requires existing large emitters (facilities releasing 100,000 metric tons or more of GHG emissions annually) to reduce their annual emissions intensity by 12% beginning July 1, 2007. Express Canada is currently not impacted by this legislation. However, in 2013 the Alberta Minister of Environment indicated that the government is reviewing the legislation and considering increasing its stringency. In the United States, climate change action is evolving at state, regional and federal levels. We expect that some of our assets and operations in the United States could be affected by eventual mandatory GHG programs; however, the timing and specific policy objectives in many jurisdictions, including at the federal level, remain uncertain. The United States has not ratified the Kyoto Protocol, nor has the federal government adopted a mandatory GHG emissions reduction requirement for our sector. The EPA issued a final Mandatory Greenhouse Gas Reporting rule in 2009 that required annual reporting of GHG emissions data from certain of our U.S. operations beginning in 2010. In 2010, the EPA released additional requirements for natural gas system reporting that have expanded the reporting requirements for GHG emissions starting in 2011. These reporting requirements have not had and are not anticipated to have a material impact on our consolidated results of operations, financial position or cash flows. In 2010, the EPA issued the PSD and Tailoring Rule. Beginning in January 2011, the Tailoring Rule required that construction of new or modification of existing major sources of GHG emissions be subject to the PSD air permitting program (and later, the Title V permitting program) although the regulation also significantly increased the emission thresholds that would subject facilities to these regulations. In June 2012, these regulations, along with other GHG regulations and determinations issued by the EPA, were upheld by the D.C. Circuit of Appeals. A petition for a rehearing en banc with the full D.C. Circuit has been filed by the parties challenging these regulations. In July 2012, the EPA determined in Step 3 of the Tailoring Rule process that it would maintain the current GHG emissions thresholds for PSD and Title V applicability. This rule has also been appealed. We anticipate that in the future, new capital projects or modification of existing projects could be subject to additional permitting requirement related to GHG emissions that may result in delays in completing such projects. In addition, several legislative proposals that would impose GHG emissions constraints have been considered by the U.S. Congress. To date, no such legislation has been enacted into law. A number of states in the United States are establishing or considering state or regional programs that would mandate reductions in GHG emissions. These regional programs include the Regional Greenhouse Gas Initiative which applies only to power producers in select northeastern states, the Western Climate 57-------------------------------------------------------------------------------- Table of Contents Initiative which includes California and the Midwestern Greenhouse Gas Reduction Accord which includes six midwestern states. We expect some of our assets and operations could be affected either directly or indirectly by state or regional programs. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain. Due to the speculative outlook regarding any federal, provincial and state policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects. We continue to monitor the development of greenhouse gas regulatory policies. Other. For additional information on other issues, see Notes 5 and 16 of Notes to Consolidated Financial Statements. New Accounting Pronouncements There were no significant accounting pronouncements issued during 2013, 2012 or 2011 that had or will have a material impact on our consolidated results of operations, financial position or cash flows. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Quantitative and Qualitative Disclosures About Market Risk for discussion. 58-------------------------------------------------------------------------------- Table of Contents |