as an energy infrastructure owner and operator in multiple facets of the various u.s. and canadian energy industries and markets , we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future . with respect to our interstate natural gas pipelines , related storage facilities and lng terminals , the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time . to the extent practicable and economically feasible in light of our strategic plans and other factors , we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms , with higher per-unit pricing and for a greater percentage of our available capacity . these long-term contracts are typically structured with a fixed-fee reserving the right to transport natural gas and specify that we receive the majority of our fee for making the capacity available , whether or not the customer actually chooses to utilize the capacity . similarly , the texas intrastate natural gas pipeline operations , currently derives approximately 73 % of its sales and transport margins from long-term transport and sales contracts . as contracts expire , we have additional exposure to the longer term trends in supply and demand for natural gas . as of december 31 , 2015 , the remaining average contract life of our natural gas transportation contracts ( including intrastate pipelines ' purchase and sales contracts ) was approximately six years . our midstream assets provide gathering and processing services for natural gas and gathering services for crude oil . these assets are generally fee-based and the revenues and earnings we realize from gathering natural gas , processing natural gas in order to remove ngl from the natural gas stream , and fractionating ngl into their base components , are affected by the volumes of natural gas made available to our systems . such volumes are impacted by producer rig count and drilling activity . in addition to fee based arrangements , we also provide some services based on percent-of-proceeds , percent-of-index and keep-whole contracts some of which may include minimum volume requirements . our service contracts may rely solely on a single type of arrangement , but more often they combine elements of two or more of the above , which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices . the co 2 source and transportation business primarily has third-party contracts with minimum volume requirements , which as of december 31 , 2015 , had a remaining average contract life of approximately nine years . co 2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed . our recent contracts have generally provided for a delivered price tied to the price of crude oil , but with a floor price . on a volume-weighted basis , for third-party contracts making deliveries in 2016 , and utilizing the average oil price per barrel contained in our 2016 budget , approximately 99 % of our revenue is based on a fixed fee or floor price , and 1 % fluctuates with the price of oil . in the long-term , our success in this portion of the co 2 business segment is driven by the demand for co 2 . however , short-term changes in the demand for co 2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts . in the co 2 business segment 's oil and gas producing activities , we monitor the amount of capital we expend in relation to the amount of production that we expect to add . in that regard , our production during any period is an important measure . in addition , the revenues we receive from our crude oil , ngl and co 2 sales are affected by the prices we realize from the sale of these products . over the long-term , we will tend to receive prices that are dictated by the demand and overall market price for these products . in the shorter term , however , market prices are likely not indicative of the revenues we will receive due to our risk management , or hedging , program , in which the prices to be realized for certain of our future sales quantities are fixed , capped or bracketed through the use of financial derivative contracts , particularly for crude oil . the realized weighted average crude oil price per barrel , with all hedges allocated to oil , was $ 73.11 per barrel in 2015 , $ 88.41 per barrel in 2014 , and $ 92.70 per barrel in 2013. had we not used energy derivative contracts to transfer commodity price risk , our crude oil sales prices would have averaged $ 47.56 per barrel in 2015 , $ 86.48 per barrel in 2014 , and $ 94.94 per barrel in 2013. the factors impacting our terminals business segment generally differ depending on whether the terminal is a liquids or bulk terminal , and in the case of a bulk terminal , the type of product being handled or stored . our liquids terminals business generally has longer-term contracts that require the customer to pay regardless of whether they use the capacity . thus , similar to our natural gas pipeline business , our liquids terminals business is less sensitive to short-term changes in supply and demand . story_separator_special_tag our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations . we use various assumptions in performing these calculations , including those related to the return that we expect to earn on our plan assets , the rate at which we expect the compensation of our employees to increase over the plan term , the estimated cost of health care when benefits are provided under our plan and other factors . a significant assumption we utilize is the discount rate used in calculating our benefit obligations . for 2015 , we selected our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities . the selection of these assumptions is further discussed in note 10 “ share-based compensation and employee benefits ” to our consolidated financial statements . effective january 1 , 2016 , we changed our estimate of the service and interest cost components of net periodic benefit cost ( credit ) for our pension and other postretirement benefit plans . the new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows . the new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates . the change does not affect the measurement of our pension and postretirement benefit obligations and it is accounted for as a change in accounting estimate , which is applied prospectively . the change in the service and interest costs going forward will not be significant . actual results may differ from the assumptions included in these calculations , and as a result , our estimates associated with our pension and other postretirement benefits can be , and often are , revised in the future . the income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants , or over the expected future lives of inactive plan participants . as of december 31 , 2015 , we had deferred net losses of approximately $ 535 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits . 44 the following table shows the impact of a 1 % change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended december 31 , 2015 : replace_table_token_11_th _ ( a ) includes amounts deferred as either accumulated other comprehensive income ( loss ) or as a regulatory asset or liability for certain of our regulated operations . income taxes we record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized . while we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance , any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached . in addition , we do business in a number of states with differing laws concerning how income subject to each state 's tax structure is measured and at what effective rate such income is taxed . therefore , we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate . changes in our effective rate , including any effect on previously recorded deferred taxes , are recorded in the period in which the need for such change is identified . in determining the deferred income tax asset and liability balances attributable to our investments , we have applied an accounting policy that looks through our investments . the application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments . results of operations non-gaap measures the non-gaap financial measures , dcf before certain items and segment ebda before certain items are presented below under “ —distributable cash flow ” and “ —consolidated earnings results , ” respectively . certain items are items that are required by gaap to be reflected in net income , but typically either do not have a cash impact , or by their nature are separately identifiable from our normal business operations and , in our view , are likely to occur only sporadically . our non-gaap measures described below should not be considered as an alternative to gaap net income or any other gaap measure . dcf before certain items and segment ebda before certain items are not financial measures in accordance with gaap and have important limitations as analytical tools . you should not consider either of these non-gaap measures in isolation or as substitutes for an analysis of our results as reported under gaap . because dcf before certain items excludes some but not all items that affect net income and because dcf measures are defined differently by different companies in our industry , our dcf before certain items may not be comparable to dcf measures of other companies . our computation of segment ebda before certain items has similar limitations . management compensates for the limitations of these non-gaap measures by reviewing our comparable gaap measures , understanding the differences between the measures and taking this information into account in its analysis and its decision making processes . 45 distributable cash flow dcf before certain items is an overall performance metric we use to estimate the ability of our assets

cash flows operating activities the net increase of $ 836 million ( 19 % ) in cash provided by operating activities in 2015 compared to 2014 was primarily attributable to : a $ 726 million increase in cash associated with net changes in working capital items and non-current assets and liabilities . the increase was driven , among other things , primarily by $ 347 million of federal and state income tax refunds we received in 2015 of which $ 195 million was previously reported as an income tax receivable as of december 31 , 2014 , and higher cash flows due to favorable changes in the collection of trade and exchange gas receivables . these increases were offset by lower cash flow due to the timing of payments from our trade payables ; a $ 243 million increase in cash due to the higher payments in 2014 for rate case reserve payments primarily driven by the 2014 cpuc settlement and refund payments ; and a $ 133 million decrease in cash from overall net income after adjusting our period-to-period $ 2,235 million decrease in net income for non-cash items primarily consisting of the following : ( i ) loss on impairment of goodwill ( see discussion above in “ —results of operations ” ) ; ( ii ) net losses on impairments and disposals of long-lived assets and equity investments ( see discussion above in “ —results of operations ” ) ; ( iii ) dd & a expenses ( including amortization of excess cost of equity investments ) ; ( iv ) deferred income taxes ; ( v ) a net increase in legal reserves ( see discussion above in “ —results of operations ” ) ; ( vi ) an increase in net unrealized gains relating to derivative contracts used to hedge forecasted natural gas , ngl , and crude oil sales ( see discussion above in “ —results of operations ” ) ; and ( vii ) an increase in equity earnings from our equity investments .


 Write a concise suspicious activity report of the following text delimited by triple backquotes. Return your response as a formal report which covers the key points highlighting the location,dates,entity names and account holder information in chronological order of the text.
     ```cash flows operating activities the net increase of $ 836 million ( 19 % ) in cash provided by operating activities in 2015 compared to 2014 was primarily attributable to : a $ 726 million increase in cash associated with net changes in working capital items and non-current assets and liabilities . the increase was driven , among other things , primarily by $ 347 million of federal and state income tax refunds we received in 2015 of which $ 195 million was previously reported as an income tax receivable as of december 31 , 2014 , and higher cash flows due to favorable changes in the collection of trade and exchange gas receivables . these increases were offset by lower cash flow due to the timing of payments from our trade payables ; a $ 243 million increase in cash due to the higher payments in 2014 for rate case reserve payments primarily driven by the 2014 cpuc settlement and refund payments ; and a $ 133 million decrease in cash from overall net income after adjusting our period-to-period $ 2,235 million decrease in net income for non-cash items primarily consisting of the following : ( i ) loss on impairment of goodwill ( see discussion above in “ —results of operations ” ) ; ( ii ) net losses on impairments and disposals of long-lived assets and equity investments ( see discussion above in “ —results of operations ” ) ; ( iii ) dd & a expenses ( including amortization of excess cost of equity investments ) ; ( iv ) deferred income taxes ; ( v ) a net increase in legal reserves ( see discussion above in “ —results of operations ” ) ; ( vi ) an increase in net unrealized gains relating to derivative contracts used to hedge forecasted natural gas , ngl , and crude oil sales ( see discussion above in “ —results of operations ” ) ; and ( vii ) an increase in equity earnings from our equity investments .
```    
 Suspicious Activity Report : as an energy infrastructure owner and operator in multiple facets of the various u.s. and canadian energy industries and markets , we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future . with respect to our interstate natural gas pipelines , related storage facilities and lng terminals , the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time . to the extent practicable and economically feasible in light of our strategic plans and other factors , we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms , with higher per-unit pricing and for a greater percentage of our available capacity . these long-term contracts are typically structured with a fixed-fee reserving the right to transport natural gas and specify that we receive the majority of our fee for making the capacity available , whether or not the customer actually chooses to utilize the capacity . similarly , the texas intrastate natural gas pipeline operations , currently derives approximately 73 % of its sales and transport margins from long-term transport and sales contracts . as contracts expire , we have additional exposure to the longer term trends in supply and demand for natural gas . as of december 31 , 2015 , the remaining average contract life of our natural gas transportation contracts ( including intrastate pipelines ' purchase and sales contracts ) was approximately six years . our midstream assets provide gathering and processing services for natural gas and gathering services for crude oil . these assets are generally fee-based and the revenues and earnings we realize from gathering natural gas , processing natural gas in order to remove ngl from the natural gas stream , and fractionating ngl into their base components , are affected by the volumes of natural gas made available to our systems . such volumes are impacted by producer rig count and drilling activity . in addition to fee based arrangements , we also provide some services based on percent-of-proceeds , percent-of-index and keep-whole contracts some of which may include minimum volume requirements . our service contracts may rely solely on a single type of arrangement , but more often they combine elements of two or more of the above , which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices . the co 2 source and transportation business primarily has third-party contracts with minimum volume requirements , which as of december 31 , 2015 , had a remaining average contract life of approximately nine years . co 2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed . our recent contracts have generally provided for a delivered price tied to the price of crude oil , but with a floor price . on a volume-weighted basis , for third-party contracts making deliveries in 2016 , and utilizing the average oil price per barrel contained in our 2016 budget , approximately 99 % of our revenue is based on a fixed fee or floor price , and 1 % fluctuates with the price of oil . in the long-term , our success in this portion of the co 2 business segment is driven by the demand for co 2 . however , short-term changes in the demand for co 2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts . in the co 2 business segment 's oil and gas producing activities , we monitor the amount of capital we expend in relation to the amount of production that we expect to add . in that regard , our production during any period is an important measure . in addition , the revenues we receive from our crude oil , ngl and co 2 sales are affected by the prices we realize from the sale of these products . over the long-term , we will tend to receive prices that are dictated by the demand and overall market price for these products . in the shorter term , however , market prices are likely not indicative of the revenues we will receive due to our risk management , or hedging , program , in which the prices to be realized for certain of our future sales quantities are fixed , capped or bracketed through the use of financial derivative contracts , particularly for crude oil . the realized weighted average crude oil price per barrel , with all hedges allocated to oil , was $ 73.11 per barrel in 2015 , $ 88.41 per barrel in 2014 , and $ 92.70 per barrel in 2013. had we not used energy derivative contracts to transfer commodity price risk , our crude oil sales prices would have averaged $ 47.56 per barrel in 2015 , $ 86.48 per barrel in 2014 , and $ 94.94 per barrel in 2013. the factors impacting our terminals business segment generally differ depending on whether the terminal is a liquids or bulk terminal , and in the case of a bulk terminal , the type of product being handled or stored . our liquids terminals business generally has longer-term contracts that require the customer to pay regardless of whether they use the capacity . thus , similar to our natural gas pipeline business , our liquids terminals business is less sensitive to short-term changes in supply and demand . story_separator_special_tag our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations . we use various assumptions in performing these calculations , including those related to the return that we expect to earn on our plan assets , the rate at which we expect the compensation of our employees to increase over the plan term , the estimated cost of health care when benefits are provided under our plan and other factors . a significant assumption we utilize is the discount rate used in calculating our benefit obligations . for 2015 , we selected our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities . the selection of these assumptions is further discussed in note 10 “ share-based compensation and employee benefits ” to our consolidated financial statements . effective january 1 , 2016 , we changed our estimate of the service and interest cost components of net periodic benefit cost ( credit ) for our pension and other postretirement benefit plans . the new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows . the new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates . the change does not affect the measurement of our pension and postretirement benefit obligations and it is accounted for as a change in accounting estimate , which is applied prospectively . the change in the service and interest costs going forward will not be significant . actual results may differ from the assumptions included in these calculations , and as a result , our estimates associated with our pension and other postretirement benefits can be , and often are , revised in the future . the income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants , or over the expected future lives of inactive plan participants . as of december 31 , 2015 , we had deferred net losses of approximately $ 535 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits . 44 the following table shows the impact of a 1 % change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended december 31 , 2015 : replace_table_token_11_th _ ( a ) includes amounts deferred as either accumulated other comprehensive income ( loss ) or as a regulatory asset or liability for certain of our regulated operations . income taxes we record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized . while we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance , any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached . in addition , we do business in a number of states with differing laws concerning how income subject to each state 's tax structure is measured and at what effective rate such income is taxed . therefore , we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate . changes in our effective rate , including any effect on previously recorded deferred taxes , are recorded in the period in which the need for such change is identified . in determining the deferred income tax asset and liability balances attributable to our investments , we have applied an accounting policy that looks through our investments . the application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments . results of operations non-gaap measures the non-gaap financial measures , dcf before certain items and segment ebda before certain items are presented below under “ —distributable cash flow ” and “ —consolidated earnings results , ” respectively . certain items are items that are required by gaap to be reflected in net income , but typically either do not have a cash impact , or by their nature are separately identifiable from our normal business operations and , in our view , are likely to occur only sporadically . our non-gaap measures described below should not be considered as an alternative to gaap net income or any other gaap measure . dcf before certain items and segment ebda before certain items are not financial measures in accordance with gaap and have important limitations as analytical tools . you should not consider either of these non-gaap measures in isolation or as substitutes for an analysis of our results as reported under gaap . because dcf before certain items excludes some but not all items that affect net income and because dcf measures are defined differently by different companies in our industry , our dcf before certain items may not be comparable to dcf measures of other companies . our computation of segment ebda before certain items has similar limitations . management compensates for the limitations of these non-gaap measures by reviewing our comparable gaap measures , understanding the differences between the measures and taking this information into account in its analysis and its decision making processes . 45 distributable cash flow dcf before certain items is an overall performance metric we use to estimate the ability of our assets

